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

$
253,562

$
259,624

Other comprehensive income (loss):
 
 
 
Cash flow hedges:
 
 
 
Current period change in fair value of commodity derivative instruments, net of tax of ($6,660), $40,720 and $41,399, respectively
(10,866
)
66,438

67,547

Reclassification adjustment for commodity derivative instruments, net of tax of ($13,560), ($17,994) and ($8,953), respectively
(22,124
)
(29,359
)
(14,607
)
Current period change in fair value of interest rate swap, net of tax of ($80), ($1,228) and ($507), respectively
(148
)
(2,281
)
(941
)
Reclassification adjustment for interest rate swap, net of tax of $603 and $574, respectively
1,120

1,066


Total cash flow hedges
(32,018
)
35,864

51,999

Pension and postretirement plans:
 
 
 
Amortization of net obligation at transition, net of taxes of $112, $100 and $96, respectively
207

186

177

Amortization of prior service cost, net of taxes of $90, $119 and $104, respectively
167

221

194

Amortization of net loss, net of taxes of $4,472, $1,676 and $1,270, respectively
8,306

3,113

2,359

Current period change in fair value of pension and postretirement plans, net of taxes of $6,237, ($9,393), and ($5,699), respectively
11,582

(17,443
)
(10,584
)
Total pension and postretirement plans
20,262

(13,923
)
(7,854
)
Comprehensive Income
$
192,798

$
275,503

$
303,769


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


43



CONSOLIDATED BALANCE SHEETS
Energen Corporation

(in thousands)
December 31, 2013
 
December 31, 2012
 
 
 
 
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
5,555

 
$
9,704

Accounts receivable, net of allowance for doubtful accounts of $5,694 and $6,549 at December 31, 2013 and 2012, respectively
257,545

 
277,900

Inventories
 
 
 
Storage gas inventory
32,095

 
32,205

Materials and supplies
16,601

 
28,291

      Liquified natural gas in storage
3,634

 
3,498

Regulatory assets
2,756

 
45,515

Income tax receivable
5,765

 
6,664

Assets held for sale
51,104

 

Deferred income taxes
41,299

 
8,520

Prepayments and other
10,877

 
12,823

Total current assets
427,231

 
425,120

Property, Plant and Equipment
 
 
 
Oil and gas properties, successful efforts method
6,864,375

 
6,439,127

Less accumulated depreciation, depletion and amortization
1,776,802

 
1,765,241

Oil and gas properties, net
5,087,573

 
4,673,886

Utility plant
1,491,433

 
1,416,590

Less accumulated depreciation
605,924

 
573,947

Utility plant, net
885,509

 
842,643

Other property, net
30,556

 
25,107

Total property, plant and equipment, net
6,003,638

 
5,541,636

Other Assets
 
 
 
Regulatory assets
84,890

 
110,566

Other postretirement assets
35,351

 
1,404

Long-term derivative instruments
5,439

 
40,577

Deferred charges and other
65,663

 
56,587

Total other assets
191,343

 
209,134

TOTAL ASSETS
$
6,622,212

 
$
6,175,890


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


44



CONSOLIDATED BALANCE SHEETS
Energen Corporation

(in thousands, except share data)
December 31, 2013
 
December 31, 2012
 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current Liabilities
 
 
 
Long-term debt due within one year
$
60,000

 
$
50,000

Notes payable to banks
539,000

 
643,000

Accounts payable
250,756

 
257,579

Accrued taxes
36,228

 
30,076

Customer deposits
21,692

 
24,705

Amounts due customers
16,990

 
19,718

Accrued wages and benefits
33,884

 
24,984

Regulatory liabilities
49,006

 
45,116

Royalty payable
51,519

 
34,426

Liabilities related to assets held for sale
18,545

 

Other
32,273

 
30,178

Total current liabilities
1,109,893

 
1,159,782

Long-term debt
1,343,464

 
1,103,528

Deferred Credits and Other Liabilities
 
 
 
Asset retirement obligation
108,533

 
118,023

Pension liabilities
67,675

 
110,282

Regulatory liabilities
94,125

 
80,404

Deferred income taxes
1,013,245

 
905,601

Long-term derivative instruments
398

 
11,305

Other
26,860

 
10,275

Total deferred credits and other liabilities
1,310,836

 
1,235,890

Commitments and Contingencies


 


Shareholders’ Equity
Preferred stock, cumulative, $0.01 par value, 5,000,000
shares authorized

 

Common shareholders’ equity
 
 
 
Common stock, $0.01 par value; 150,000,000 shares authorized, 75,574,156 shares issued at December 31, 2013 and 75,067,760 shares issued at December 31, 2012
756

 
751

    Premium on capital stock
520,909

 
492,108

    Capital surplus
2,802

 
2,802

    Retained earnings
2,476,616

 
2,314,055

    Accumulated other comprehensive income (loss), net of tax
 
 
 
Unrealized gain on hedges, net
13,362

 
46,352

Pension and postretirement plans
(32,245
)
 
(52,507
)
Interest rate swap
(1,184
)
 
(2,156
)
Deferred compensation plan
3,259

 
2,774

Treasury stock, at cost: 2,967,999 shares and 2,998,620 shares at December 31, 2013 and 2012, respectively
(126,256
)
 
(127,489
)
Total shareholders’ equity
2,858,019

 
2,676,690

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
6,622,212

 
$
6,175,890

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

45



CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
Energen Corporation

 
Common Stock
Premium on Capital Stock
Capital Surplus
Retained Earnings
Accumulated
Other
Comprehensive Income (Loss)
Deferred
Compensation Plan
Treasury
Stock
Total
Shareholders’ Equity
(in thousands, except share data)
Number of Shares
Par
Value
BALANCE DECEMBER 31, 2010
74,786,376

$
748

$
468,934

$
2,802

$
1,880,183

$
(74,397
)
$
3,288

$
(127,515
)
$
2,154,043

Net income
 
 
 
 
259,624

 
 
 
259,624

Other comprehensive income
 
 
 
 
 
44,145

 
 
44,145

Purchase of treasury shares, net
 
 
 
 
 
 
 
(713
)
(713
)
Shares issued for employee benefit plans
221,036

2

7,235

 
 
 
 
 
7,237

Deferred compensation obligation
 
 
 
 
 
 
223

(223
)

Stock-based compensation
 
 
5,763

 
 
 
 
 
5,763

Tax benefit from employee stock plans
 
 
986

 
 
 
 
 
986

Cash dividends - $0.54 per share
 
 
 
 
(38,922
)
 
 
 
(38,922
)
BALANCE DECEMBER 31, 2011
75,007,412

750

482,918

2,802

2,100,885

(30,252
)
3,511

(128,451
)
2,432,163

Net income
 
 
 
 
253,562

 
 
 
253,562

Other comprehensive income
 
 
 
 
 
21,941

 
 
21,941

Purchase of treasury shares, net
 
 
 
 
 
 
 
(277
)
(277
)
Shares issued for employee benefit plans
60,348

1

2,060

 
 
 
 
 
2,061

Deferred compensation obligation
 
 
 
 
 
 
(737
)
737


Stock-based compensation
 
 
6,580

 
 
 
 
502

7,082

Tax benefit from employee stock plans
 
 
550

 
 
 
 
 
550

Cash dividends - $0.56 per share
 
 
 
 
(40,392
)
 
 
 
(40,392
)
BALANCE DECEMBER 31, 2012
75,067,760

751

492,108

2,802

2,314,055

(8,311
)
2,774

(127,489
)
2,676,690

Net income
 
 
 
 
204,554

 
 
 
204,554

Other comprehensive loss
 
 
 
 
 
(11,756
)
 
 
(11,756
)
Purchase of treasury shares, net
 
 
 
 
 
 
 
(1,038
)
(1,038
)
Shares issued for employee benefit plans
506,396

5

18,790

 
 
 
 
 
18,795

Deferred compensation obligation
 
 
 
 
 
 
485

(485
)

Stock-based compensation
 
 
6,869

 
 
 
 
2,756

9,625

Tax benefit from employee stock plans
 
 
3,142

 
 
 
 
 
3,142

Cash dividends - $0.58 per share
 
 
 
 
(41,993
)
 
 
 
(41,993
)
BALANCE DECEMBER 31, 2013
75,574,156

$
756

$
520,909

$
2,802

$
2,476,616

$
(20,067
)
$
3,259

$
(126,256
)
$
2,858,019


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


46



CONSOLIDATED STATEMENTS OF CASH FLOWS
Energen Corporation
Years ended December 31, (in thousands)
2013
2012
2011
 
 
 
 
Operating Activities
 
 
 
Net income
$
204,554

$
253,562

$
259,624

Adjustments to reconcile net income to net cash
   provided by operating activities:









     Depreciation, depletion and amortization
527,845

419,598

283,997

Asset impairment
29,794

21,545


Accretion expense
8,192

7,534

6,837

Deferred income taxes
83,650

124,399

129,041

Bad debt expense
781

153

2,525

Change in derivative fair value
48,029

(41,819
)
36,210

Gain on sale of assets
(46,377
)
(529
)
(5,994
)
Stock-based compensation expense
14,892

6,047

9,011

Exploratory expense
16,008

16,757

10,916

Other, net
23,810

8,597

7,537

Net change in:
 
 
 
Accounts receivable
4,216

(11,923
)
(16,359
)
Inventories
11,596

10,018

(14,710
)
Accounts payable
(58,859
)
(16,392
)
12,978

Amounts due customers, including gas supply pass-through
40,542

(57,747
)
(2,597
)
Income tax receivable
899

679

37,146

Pension and other postretirement benefit contributions
(11,747
)
(5,996
)
(5,986
)
Other current assets and liabilities
29,552

1,254

11,655

Net cash provided by operating activities
927,377

735,737

761,831

Investing Activities
 
 
 
Additions to property, plant and equipment
(1,195,402
)
(1,184,300
)
(889,614
)
Acquisitions, net of cash acquired
(31,331
)
(139,563
)
(310,193
)
Proceeds from sale of assets
174,824

2,562

7,987

Purchase of short-term investments
(310,000
)


Sale of short-term investments
310,000



Other, net
(1,701
)
(881
)
(1,679
)
Net cash used in investing activities
(1,053,610
)
(1,322,182
)
(1,193,499
)
Financing Activities
 
 
 
Payment of dividends on common stock
(41,993
)
(40,392
)
(38,922
)
Issuance of common stock
17,780

1,224

6,415

Issuance of long-term debt
600,000


749,952

Reduction of long-term debt
(350,105
)
(1,218
)
(5,547
)
Net change in short-term debt
(104,000
)
628,000

(290,000
)
Tax benefit on stock compensation
3,142

550

986

Other
(2,740
)
(1,556
)
(4,334
)
Net cash provided by financing activities
122,084

586,608

418,550

Net change in cash and cash equivalents
(4,149
)
163

(13,118
)
Cash and cash equivalents at beginning of period
9,704

9,541

22,659

Cash and cash equivalents at end of period
$
5,555

$
9,704

$
9,541

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

47



STATEMENTS OF INCOME
Alabama Gas Corporation

Years ended December 31, (in thousands)
2013
2012
2011
 
 
 
 
Operating Revenues
$
533,338

$
451,589

$
534,953

Operating Expenses
 
 
 
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
 
 
 
Current
19,687

18,966

(1,388
)
Deferred
15,000

11,278

28,058

Taxes, other than income taxes
37,070

32,541

36,268

Total operating expenses
474,257

388,617

475,407

Operating Income
59,081

62,972

59,546

Other Income (Expense)
 
 
 
Allowance for funds used during construction
698

623

807

Other income
14,393

2,382

1,309

Other expense
(1,124
)
(291
)
(320
)
Total other income
13,967

2,714

1,796

Interest Expense
 
 
 
Interest on long-term debt
13,509

13,744

12,100

Other interest expense
2,140

2,540

2,640

Total interest expense
15,649

16,284

14,740

Net Income
$
57,399

$
49,402

$
46,602


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


48



BALANCE SHEETS
Alabama Gas Corporation

(in thousands)
December 31, 2013
 
December 31, 2012
 
 
 
 
ASSETS
 
 
 
Property, Plant and Equipment
 
 
 
Utility plant
$
1,491,433

 
$
1,416,590

Less accumulated depreciation
605,924

 
573,947

Utility plant, net
885,509

 
842,643

Other property, net
41

 
42

Current Assets
 
 
 
Cash
3,032

 
5,559

Accounts receivable
 
 
 
Gas
103,301

 
94,011

Other
5,447

 
5,117

Affiliated companies
4,662

 
5,742

Allowance for doubtful accounts
(5,000
)
 
(5,700
)
Inventories
 
 
 
Storage gas inventory
32,095

 
32,205

Materials and supplies
5,471

 
5,528

Liquified natural gas in storage
3,634

 
3,498

Regulatory assets
2,756

 
45,515

Income tax receivable
3,644

 
2,762

Deferred income taxes
20,049

 
18,799

Prepayments and other
4,654

 
4,451

           Total current assets
183,745

 
217,487

Other Assets
 
 
 
Regulatory assets
84,890

 
110,566

Other postretirement assets
26,457

 
848

Deferred charges and other
17,433

 
11,290

           Total other assets
128,780

 
122,704

TOTAL ASSETS
$
1,198,075

 
$
1,182,876


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


49



BALANCE SHEETS
Alabama Gas Corporation

(in thousands, except share data)
December 31, 2013
 
December 31, 2012
 
 
 
 
LIABILITIES AND CAPITALIZATION
 
 
 
Capitalization
 
 
 
Preferred stock, cumulative, $0.01 par value, 120,000
shares authorized
$

 
$

Common shareholder’s equity
 
 
 
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at December 31, 2013 and 2012, respectively
20

 
20

Premium on capital stock
31,682

 
31,682

Capital surplus
2,802

 
2,802

Retained earnings
350,076

 
325,999

Total common shareholder’s equity
384,580

 
360,503

Long-term debt
249,923

 
250,028

Total capitalization
634,503

 
610,531

Current Liabilities
 
 
 
Notes payable to banks
50,000

 
77,000

Accounts payable
48,653

 
51,741

Accrued taxes
28,027

 
24,186

Customer deposits
21,692

 
24,705

Amounts due customers
16,990

 
19,718

Accrued wages and benefits
7,682

 
6,703

Regulatory liabilities
49,006

 
45,116

Other
10,113

 
9,018

Total current liabilities
232,163

 
258,187

Deferred Credits and Other Liabilities
 
 
 
Deferred income taxes
205,631

 
189,381

Pension liabilities
20,191

 
43,611

Regulatory liabilities
94,125

 
80,404

Other
11,462

 
762

Total deferred credits and other liabilities
331,409

 
314,158

Commitments and Contingencies

 

TOTAL LIABILITIES AND CAPITALIZATION
$
1,198,075

 
$
1,182,876


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


50



STATEMENTS OF SHAREHOLDER’S EQUITY
Alabama Gas Corporation

(in thousands, except share data)
 
Common Stock
Premium on
Capital Stock
Capital
Surplus
Retained
Earnings
Total
Shareholder’s Equity
 
Number of
Shares
Par
Value
Balance December 31, 2010
1,972,052

$
20

$
31,682

$
2,802

$
292,815

$
327,319

Net income
 
 
 
 
46,602

46,602

Cash dividends
 
 
 
 
(29,183
)
(29,183
)
Balance December 31, 2011
1,972,052

20

31,682

2,802

310,234

344,738

Net income
 
 
 
 
49,402

49,402

Cash dividends
 
 
 
 
(33,637
)
(33,637
)
Balance December 31, 2012
1,972,052

20

31,682

2,802

325,999

360,503

Net income
 
 
 
 
57,399

57,399

Cash dividends
 
 
 
 
(33,322
)
(33,322
)
Balance December 31, 2013
1,972,052

$
20

$
31,682

$
2,802

$
350,076

$
384,580


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


51



STATEMENTS OF CASH FLOWS
Alabama Gas Corporation

Years ended December 31, (in thousands)
2013
2012
2011
 
 
 
 
Operating Activities
 
 
 
Net income
$
57,399

$
49,402

$
46,602

Adjustments to reconcile net income to net cash
    provided by operating activities:









Depreciation and amortization
43,907

42,270

39,916

Deferred income taxes
15,000

11,278

28,058

Bad debt expense
774

146

2,457

Gain on sale of assets
(10,889
)


Other, net
14,068

10,667

1,560

Net change in:
 
 
 
Accounts receivable
(23,955
)
(13,528
)
4,862

Inventories
31

10,544

(7,371
)
Accounts payable
(2,464
)
(5,906
)
(1,499
)
Amounts due customers, including gas supply pass-through
40,542

(57,747
)
(2,597
)
Income tax receivable
(882
)
7,000

553

Pension and other postretirement benefit contributions
(6,070
)
(2,725
)
(2,811
)
Other current assets and liabilities
2,700

(8,654
)
(2,802
)
Net cash provided by operating activities
130,161

42,747

106,928

Investing Activities
 
 
 
Additions to property, plant and equipment
(86,037
)
(69,860
)
(73,447
)
Proceeds from sale of assets
13,838



Other, net
(62
)
(3,252
)
(2,743
)
Net cash used in investing activities
(72,261
)
(73,112
)
(76,190
)
Financing Activities
 
 
 
Payment of dividends on common stock
(33,322
)
(33,637
)
(29,183
)
Proceeds from issuance of long-term debt


50,000

Reduction of long-term debt
(105
)
(218
)
(5,547
)
Net change in short-term debt
(27,000
)
62,000

(55,000
)
Other

(38
)
(101
)
Net cash provided by (used in) financing activities
(60,427
)
28,107

(39,831
)
Net change in cash and cash equivalents
(2,527
)
(2,258
)
(9,093
)
Cash and cash equivalents at beginning of period
5,559

7,817

16,910

Cash and cash equivalents at end of period
$
3,032

$
5,559

$
7,817


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


52



NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 

Energen Corporation (Energen or the Company) is 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, exploration and production of oil and gas in the continental United States (oil and gas operations) and in the purchase, distribution and sale of natural gas principally in central and north Alabama (natural gas distribution). The following is a description of the Company’s significant accounting policies and practices.

A. Principles of Consolidation

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

B. Oil and Gas Operations

Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense during the year:

Years ended December 31, (in thousands)
2013
2012
2011
Capitalized exploratory well costs at beginning of period
$
79,791

$
70,437

$
21,438

Additions pending determination of proved reserves
421,599

406,226

178,005

Reclassifications due to determination of proved reserves
(442,909
)
(396,872
)
(129,006
)
Exploratory well costs charged to expense
(881
)


Capitalized exploratory well costs at end of period
$
57,600

$
79,791

$
70,437


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

Years ended December 31, (in thousands)
2013
2012
2011
Exploratory wells in progress
$
14,794

$
77,693

$
70,437

Capitalized exploratory well costs for a period of one year or less
42,481



Capitalized exploratory well costs for a period greater than one year
1,206

2,098


Total capitalized exploratory well costs
$
58,481

$
79,791

$
70,437


At December 31, 2013, the Company had 48 gross exploratory wells either drilling or waiting on results from completion and testing. All of these wells are located in the Permian Basin. The Company has one gross well capitalized greater than a year which is pending results from completion and testing. This well is currently waiting on facilities.

Operating Revenues: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers.

53



Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no significant production imbalances at December 31, 2013 and 2012 .

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. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of December 31, 2013 , which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value was required to be recognized in operating revenues immediately. All other derivative transactions not designated as cash flow hedge accounting are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Gains and losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.

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 will be accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change .

Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:

Years ended December 31, (in thousands)
2013
2012
2011
Mark-to-market gain (loss) on derivatives
$
(47,832
)
$
58,750

$
(37,587
)

All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged.

Long-Lived Assets and Discontinued Operations: The Company reports gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.


54



Acquisitions: Energen Resources recognizes all acquisitions at fair value. Energen Resources estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen Resources obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. Energen Resources uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in operations and maintenance (O&M) expense on the consolidated income statements.

C. Natural Gas Distribution

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

Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. Gains and losses on all dispositions of land are recognized at time of disposal. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010 , the APSC approved a reduction in depreciation rates, effective June 1, 2010 , for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $16.3 million , $14.2 million , $22.2 million and $2.7 million for the years ended December 31, 2013, 2012 and 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $15.8 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $39.7 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a five year period beginning January 1, 2015. The total amount refundable to customers is subject to adjustments over the remaining five year period for charges made to the Enhanced Stability Reserve (ESR) and other APSC approved charges. The refunds as of December 2013 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.1 percent, 3.2 percent and 3.1 percent in the years ended December 31, 2013 , 2012 and 2011 , respectively.

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

Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2013 and 2012.

Derivative Commodity Instruments: In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Alagasco recognizes all derivatives 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 Gas Supply Adjustment (GSA) rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Alagasco.


55



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

Years ended December 31, (in thousands)
2013
2012
2011
Taxes on revenues
$
25,870

$
21,479

$
25,268


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

D. Fair Value Measurements

The carrying values of cash and cash equivalents, accounts payable and receivable, derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is defined as follows:

Level 1 -
Unadjusted quoted prices in active markets for identical assets or liabilities;
Level 2 -
Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;
Level 3 -
Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

Derivative commodity instruments are OTC derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to 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.

Pension and postretirement plan assets include mutual and comingled funds and limited partnerships. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds. Level 3 fair values used unobservable market prices primarily associated with certain alternative investments and a limited partnership.

E. Income Taxes

The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.

56



F. Accounts Receivable and Allowance for Doubtful Accounts

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

G. Cash and Cash Equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.

H. Short-term Investments

All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2013 and 2012, Energen had no short-term investments.

I. Earnings Per Share (EPS)

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

J. Stock-Based Compensation

The Company measures all share-based compensation awards at fair value at the date of grant and expenses the awards over the requisite vesting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. The Company recognizes all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. The Company utilizes the long-form method of calculating the available pool of windfall tax benefit. For the years ended December 31, 2013 , 2012 and 2011, the Company recognized an excess tax benefit of $3.1 million , $0.6 million and $1.0 million , respectively, related to its stock-based compensation.

K. Estimates

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

L. Employee Benefit Plans

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


57



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

Measurement: The Company calculates periodic expense for defined benefit pension plans and other postretirement benefit plans on an actuarial basis and the net funded status of benefit plans is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future. The Company measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.

Discount Rate: In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate for each plan was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments.

Long-Term Rate of Return: The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The Company considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.

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

M. Environmental Costs

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

2. REGULATORY MATTERS
 

Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s 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 of the order is extended through September 30, 2018. 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.  Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for Securities and Exchange Commission reporting purposes.

Alagasco’s allowed range of return on average common equity is 13.15 percent to 13.65 percent through December 31, 2013. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the years ended December 31, 2013 , 2012 and 2011, Alagasco had net pre-tax reductions in revenues of $10.6 million , $6.3 million and $6.7 million , respectively, to bring the return on average equity to midpoint within the allowed range of return. Under the provisions of RSE, a $10.3 million annual increase, $7.8 million annual increase and $13.0

58



million annual increase in revenues became effective December 1, 2013 , 2012 , and 2011 , respectively. On January 1, 2014 an $8.5 million decrease in revenues became effective as a result of the December 20, 2013 RSE modification.

RSE limits the utility’s equity upon which a return was permitted to 55 percent of total capitalization, subject to certain adjustments through December 31, 2013. 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 on a rate year basis, no adjustment was required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference was 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 items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013, 2012 and 2011.

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

The APSC approved an Enhanced Stability Reserve in 1998 which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500 , respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.
Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $660,000 . Amounts in excess of this limitation are deferred for recovery in future years.

The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized through Alagasco’s rate-setting mechanism on a straight-line basis with a weighted average remaining life of approximately 13 years . At December 31, 2013 and 2012 , the net unamortized acquisition adjustments were $3.2 million and $3.8 million , respectively.























59



3. LONG-TERM DEBT AND NOTES PAYABLE
 

Long-term debt consisted of the following:

(in thousands)
December 31, 2013
December 31, 2012
 
 
 
Energen Corporation:
 
 
Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028
$
154,000

$
154,000

5% Notes

50,000

4.625% Notes, due September 1, 2021
400,000

400,000

Senior Term Loans, (floating rate interest LIBOR plus 1.625%; 1.792% at December 31, 2013), due March 31, 2014 to December 17, 2017
600,000


Senior Term Loans, (floating rate interest LIBOR plus 1.375%)

300,000

Alabama Gas Corporation:
 
 
5.20% Notes, due January 15, 2020
40,000

40,000

5.70% Notes, due January 15, 2035
34,923

35,028

5.368% Notes, due December 1, 2015
80,000

80,000

5.90% Notes, due January 15, 2037
45,000

45,000

3.86% Notes, due December 21, 2021
50,000

50,000

Total
1,403,923

1,154,028

Less amounts due within one year
60,000

50,000

Less unamortized debt discount
459

500

Total
$
1,343,464

$
1,103,528


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

Years ending December 31,  (in thousands)
2014
2015
2016
2017
2018
$60,000
$140,000
$60,000
$439,000

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

Years ending December 31,  (in thousands)
2014
2015
2016
2017
2018
$80,000

In December 2013, the Company issued $600 million in Senior Term Loans (Senior Term Loans) with a floating interest rate due March 31, 2014 through December 17, 2017. The Company used the long-term debt proceeds to repay the Senior Term Loans of $300 million issued in November 2011 and to repay short-term obligations under its syndicated credit facility.

At December 31, 2013, the Company had interest rate swap agreements with a notional of $200 million . The interest rate swaps exchange a variable interest rate for a fixed interest rate of 2.6675 percent . The fair value of the Company’s interest rate swap was a $1.8 million and a $3.3 million liability at December 31, 2013 and 2012, respectively, and is classified as a Level 2 fair value liability. The fair value of the Company’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.

The long-term debt and short-term debt agreements of Energen and Alagasco contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens.

60



Although none of the agreements have covenants or events of default based on credit ratings, the interest rates applicable to the Senior Term Loans and the Energen and Alagasco syndicated credit facilities discussed below may adjust based on credit rating changes. All of the Company’s debt is unsecured.

Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s Indenture dated November 1, 1993 with The Bank of New York as Trustee, a cross default provision provides that any debt default by Alagasco of more than $10 million will constitute an event of default by Alagasco. Neither Indenture includes a restriction on the payment of dividends.

Energen and Alagasco Credit Facilities: On October 30, 2012, Energen and Alagasco entered into $1.25 billion and $100 million , respectively, five -year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Borrowings under these credit facilities are subject to the execution of individual note agreements each with maturity dates of less than one year. Accordingly, outstanding amounts due under these credit facilities are classified as short term obligations in the accompanying consolidated financial statements. Alagasco has been authorized by the APSC to borrow up to $200 million at any one time under the short-term credit facilities.

Energen’s obligations under the $1.25 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. The financial covenants of the Energen credit facility limit Energen to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Energen may not pay dividends during an event of default or if the payment would result in an event of default.

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

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

Upon an uncured event of default under either of the credit facilities, all amounts owing under the defaulted credit facility, if any, depending on the nature of the event of default will automatically, or may upon notice by the administrative agent or the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. Energen and Alagasco were in compliance with the terms of their respective credit facilities as of December 31, 2013 .

The following is a summary of information relating to the credit facilities:
(in thousands)
December 31, 2013
December 31, 2012
Energen outstanding
$
489,000

$
566,000

Alagasco outstanding
50,000

77,000

Notes payable to banks
539,000

643,000

Available for borrowings
811,000

707,000

Total
$
1,350,000

$
1,350,000

Energen maximum amount outstanding at any month-end
$
901,000

$
643,000

Energen average daily amount outstanding
$
804,895

$
331,068

Energen weighted average interest rates based on:
 
 
Average daily amount outstanding
1.38
%
1.82
%
Amount outstanding at year-end
1.32
%
1.35
%
Alagasco maximum amount outstanding at any month-end
$
75,000

$
77,000

Alagasco average daily amount outstanding
$
35,027

$
21,254

Alagasco weighted average interest rates based on:
 
 
Average daily amount outstanding
1.12
%
1.44
%
Amount outstanding at year-end
1.26
%
1.11
%

61



Energen’s total interest expense was $69.2 million , $65.5 million and $44.8 million for the years ended December 31, 2013 , 2012 and 2011 , respectively. Energen’s total interest expense for the years ended December 31, 2013 and 2012 included capitalized interest expense of $0.2 million and $0.5 million . Total interest expense for Alagasco was $15.6 million , $16.3 million and $14.7 million for the years ended December 31, 2013 , 2012 and 2011 , respectively. At December 31, 2013, Energen and Alagasco paid commitment fees on the unused portion of available credit facilities ranging from 15 to 25 basis points per annum.

4. INCOME TAXES
 

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

Years ended December 31, (in thousands)
2013
2012
2011
Taxes estimated to be payable currently:
 
 
 
Federal
$
23,342

$
16,295

$
11,595

State
2,516

3,125

5,065

Total current
25,858

19,420

16,660

Taxes deferred:
 
 
 
Federal
85,950

119,053

125,622

State
(2,300
)
5,346

3,419

Total deferred
83,650

124,399

129,041

Total income tax expense
$
109,508

$
143,819

$
145,701


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

Years ended December 31, (in thousands)
2013
2012
2011
Income tax expense from continuing operations
$
105,282

$
144,534

$
126,322

Income tax expense (benefit) from discontinued operations
2,215

(715
)
19,379

Income tax expense from gain on disposal of discontinued operations
2,011



Total income tax expense
$
109,508

$
143,819

$
145,701


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

Years ended December 31, (in thousands)
2013
2012
2011
Taxes estimated to be payable currently:
 
 
 
Federal
$
17,495

$
18,227

$
(1,280
)
State
2,192

739

(108
)
Total current
19,687

18,966

(1,388
)
Taxes deferred:
 
 
 
Federal
13,252

9,066

24,938

State
1,748

2,212

3,120

Total deferred
15,000

11,278

28,058

Total income tax expense
$
34,687

$
30,244

$
26,670








62



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

(in thousands)
December 31, 2013
December 31, 2012
 
Current
Noncurrent
Current
Noncurrent
Deferred tax assets:
 
 
 
 
Unbilled and deferred revenue
$
12,547

$

$
10,137

$

Allowance for doubtful accounts
2,066


2,408


Insurance and other accruals
4,851


3,821


Compensation accruals
15,405


13,116


Inventories
1,260


1,664


Other comprehensive income

15,350


19,158

Gas supply adjustment related accruals
698


969


Derivative instruments
10,769




State net operating losses and other carryforwards

4,577


3,577

Other
1,219

1

1,340

25

Total deferred tax assets
48,815

19,928

33,455

22,760

Valuation allowance
(299
)
(2,674
)
(268
)
(2,793
)
Total deferred tax assets
48,516

17,254

33,187

19,967

Deferred tax liabilities:
 
 
 
 
Depreciation and basis differences

1,008,026


898,625

Pension and other costs

15,379


20,143

Derivative instruments

2,048

4,272

3,162

Other comprehensive income
5,540


18,133


Other
1,677

5,046

2,262

3,638

Total deferred tax liabilities
7,217

1,030,499

24,667

925,568

Net deferred tax assets (liabilities)
$
41,299

$
(1,013,245
)
$
8,520

$
(905,601
)

























63



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

(in thousands)
December 31, 2013
December 31, 2012
 
Current
Noncurrent
Current
Noncurrent
Deferred tax assets:
 
 
 
 
Unbilled and deferred revenue
$
12,547

$

$
10,137

$

Allowance for doubtful accounts
1,815


2,155


Insurance accruals
1,769


1,856


Compensation accruals
2,480


2,645


Inventories
1,260


1,664


Gas supply adjustment related accruals
698


969


Other
984

1

774

2

Total deferred tax assets
21,553

1

20,200

2

Deferred tax liabilities:
 
 
 
 
Depreciation and basis differences

186,601


167,329

Pension and other costs

19,031


22,054

Other
1,504


1,401


Total deferred tax liabilities
1,504

205,632

1,401

189,383

Net deferred tax assets (liabilities)
$
20,049

$
(205,631
)
$
18,799

$
(189,381
)

The Company files a consolidated federal income tax return with all of its subsidiaries. The Company has a noncurrent deferred tax asset of $1.6 million relating to Energen Resources’ $35.0 million state net operating loss carryforward which will expire beginning in 2027. Energen Resources anticipates generating adequate future taxable income to fully realize this benefit. The Company has a full valuation allowance recorded against a noncurrent deferred tax asset of $3.0 million arising from certain state net operating loss and charitable contribution carryforwards. The Company intends to fully reserve this asset until it is determined that it is more likely than not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other valuation allowance with respect to deferred taxes is deemed necessary as the Company anticipates generating adequate future taxable income to realize the benefits of all remaining deferred tax assets on the consolidated balance sheets.

In accordance with Accounting Standards Codification 740-30-25-7, the Company has not recognized a deferred tax liability for the difference between the book basis and the tax basis in the stock of its subsidiaries. The unrecorded gross outside basis difference for Alagasco exceeds the recorded inside asset basis difference by approximately $37.0 million and would result in an additional deferred tax liability of $14.0 million .

Total income tax expense from continuing operations for the Company differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:

Years ended December 31, (in thousands)
2013
2012
2011
Income tax expense at statutory federal income tax rate
$
104,450

$
139,914

$
122,719

Increase (decrease) resulting from:
 
 
 
State income taxes, net of federal income tax benefit
3,799

4,755

8,341

Impact of state law changes
(1,966
)

(2,059
)
Qualified Section 199 production activities deduction

(61
)
(495
)
401(k) stock dividend deduction
(449
)
(514
)
(532
)
Other, net
(552
)
440

(1,652
)
Total income tax expense
$
105,282

$
144,534

$
126,322

Effective income tax rate (%)
35.28

36.16

36.03



64



Total income tax expense for Alagasco differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:

Years ended December 31, (in thousands)
2013
2012
2011
Income tax expense at statutory federal income tax rate
$
32,230

$
27,876

$
25,645

Increase (decrease) resulting from:
 
 
 
State income taxes, net of federal income tax benefit
2,588

2,238

2,059

Reversal of tax reserves from audit settlements, net


(1,365
)
Other, net
(131
)
130

331

Total income tax expense
$
34,687

$
30,244

$
26,670

Effective income tax rate (%)
37.67

37.97

36.40


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

(in thousands)
 
Balance as of December 31, 2010
$
24,590

Additions based on tax positions related to the current year
3,644

Additions for tax positions of prior years
2,324

Reductions for tax positions of prior years
(39
)
Lapse of statute of limitations
(1,482
)
Settlements
(18,444
)
Balance as of December 31, 2011
10,593

Additions based on tax positions related to the current year
3,731

Additions for tax positions of prior years
269

Reductions for tax positions of prior years
(446
)
Lapse of statute of limitations
(1,592
)
Balance as of December 31, 2012
12,555

Additions based on tax positions related to the current year
4,546

Additions for tax positions of prior years
366

Reductions for tax positions of prior years
(46
)
Lapse of statute of limitations
(1,435
)
Balance as of December 31, 2013
$
15,986


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

During 2011, the Company had a gross addition of $5.9 million and recognized in its effective income tax rate $2.9 million of income tax expense for additional unrecognized tax benefit liabilities. These liabilities were partially offset by a $1.5 million benefit for the release of the unrecognized income tax benefit liability due to the Company’s settlement with the IRS discussed above.


65



The amount of unrecognized tax benefits at December 31, 2013 that would favorably impact the Company’s effective tax rate, if recognized, is $6.9 million . The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2013 , 2012 , and 2011 , the Company recognized approximately $15,000 of expense, $25,000 of income and $1.4 million of income for interest (net of tax benefit) and penalties, respectively. The Company had approximately $0.2 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2013 and 2012 , respectively.

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

(in thousands)
 
Balance as of December 31, 2010
$
18,941

Additions based on tax positions related to the current year
13

Additions for tax positions of prior years
1

Reductions for tax positions of prior years (lapse of statute of limitations)
(409
)
Settlements
(18,444
)
Balance as of December 31, 2011
102

Additions based on tax positions related to the current year
62

Additions for tax positions of prior years
201

Reductions for tax positions of prior years (lapse of statute of limitations)
(58
)
Balance as of December 31, 2012
307

Reductions for tax positions of prior years (lapse of statute of limitations)
(31
)
Balance as of December 31, 2013
$
276


The reduction for settlements in 2011 are primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property discussed above. None of Alagasco’s unrecognized tax benefits at December 31, 2013 would impact the Company’s effective tax rate, if recognized. Alagasco recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2013, 2012, and 2011, Alagasco recognized approximately $4,000 of expense, $1,000 of income and $1.4 million of income for interest (net of tax benefit) and penalties, respectively. Alagasco had approximately $8,000 and $4,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2013 and 2012, respectively.

The Company and Alagasco’s tax returns for years 2010-2012 remain open and subject to examination by the IRS and major state taxing jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.





















66



5. EMPLOYEE BENEFIT PLANS
 

Benefit Obligations: The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in the Company’s consolidated financial statements:

As of December 31, (in thousands)
2013
 
2012
2013
 
2012
 
Pension
Postretirement Benefits
Accumulated benefit obligation
$
253,030

 
$
269,101

 
 
 
Benefit obligation:
 
 
 
 
 
 
Balance at beginning of period
$
323,540

 
$
250,619

$
85,785

 
$
88,064

Service cost
14,173

 
10,527

1,694

 
1,853

Interest cost
11,239

 
10,801

3,504

 
4,248

Actuarial (gain) loss
(28,339
)
 
65,048

(21,681
)
 
(5,413
)
Curtailment gain
(4,223
)
 

(1,255
)
 

Retiree drug subsidy program

 

261

 
360

Benefits paid
(23,036
)
 
(13,455
)
(4,726
)
 
(3,327
)
Balance at end of period
$
293,354

 
$
323,540

$
63,582

 
$
85,785

Plan assets:
 
 
 
 
 
 
Fair value of plan assets at beginning of period
$
209,424

 
$
195,659

$
87,189

 
$
78,121

Actual return on plan assets
22,977

 
24,841

14,892

 
8,778

Employer contributions
10,169

 
2,379

1,578

 
3,617

Benefits paid
(23,036
)
 
(13,455
)
(4,726
)
 
(3,327
)
Fair value of plan assets at end of period
$
219,534

 
$
209,424

$
98,933

 
$
87,189

 
 
 
 
 
 
 
Funded status of plans
$
(73,820
)
 
$
(114,116
)
$
35,351

 
$
1,404

 
 
 
 
 
 
 
Noncurrent assets
$

 
$

$
35,351

 
$
1,404

Current liabilities
(6,145
)
 
(3,834
)

 

Noncurrent liabilities
(67,675
)
 
(110,282
)

 

Net asset (liability) recognized
$
(73,820
)
 
$
(114,116
)
$
35,351

 
$
1,404

Amounts recognized to accumulated other comprehensive income:
 
 
 
 
 
Prior service costs, net of taxes
$
323

 
$
528

$

 
$

Net actuarial (gain) loss, net of taxes
37,479

 
52,472

(5,584
)
 
(715
)
Transition obligation, net of taxes

 

27

 
222

Total accumulated other comprehensive income (loss)
$
37,802

 
$
53,000

$
(5,557
)
 
$
(493
)

Alagasco recognized a regulatory asset of $58.2 million and $89.5 million as of December 31, 2013 and 2012 , respectively, for the portion of the pension plan obligation to be recovered through rates in future periods. Alagasco also recognized a regulatory liability of $26.2 million and $1.2 million as of December 31, 2013 and 2012, respectively, for the portion of the postretirement health care and life insurance benefit obligation to be refunded through rates in future periods.







67



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

 
December 31, 2013
(in thousands)
Level 1
Level 2
Level 3
Total
Insurance contracts
$

$
14,805

$

$
14,805

United States equities
5,579



5,579

Global equities
2,338



2,338

Fixed income

11,039


11,039

Total
$
7,917

$
25,844

$

$
33,761

 
December 31, 2012
(in thousands)
Level 1
Level 2
Level 3
Total
Insurance contracts
$

$
7,399

$
5,600

$
12,999

United States equities
4,741



4,741

Global equities
2,109



2,109

Fixed income

10,219


10,219

Total
$
6,850

$
17,618

$
5,600

$
30,068


While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of the Company’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in deferred charges and other in the consolidated balance sheets.

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

Years ended December 31, (in thousands)
2013
2012
2011
Balance at beginning of period
$
5,600

$
5,332

$
5,069

Unrealized gains relating to instruments held at the reporting date

268

263

Transfer out of Level 3
(5,600
)


Balance at end of period
$

$
5,600

$
5,332


Changes in Fair Value Levels: The availability of observable market data is monitored to assess the appropriate classification for financial instruments within the fair value hierarchy. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the year ended December 31, 2013, except for the transfer out of Level 3 noted below, there were no significant transfers in or out of Levels 1, 2, or 3.

Transfer of Insurance Contracts: The insurance contracts consist of multiple contracts with two insurance companies and are accounted for at fair value at the contracts’ cash surrender values. During 2013, the Company determined that its insurance contracts meet the requirements to be categorized as a Level 2 fair value measurement.













68



The components of net periodic benefit cost were as follows:

Years ended December 31, (in thousands)
2013
2012
2011
Pension Plans
 
 
 
Components of net periodic benefit cost:
 
 
 
Service cost
$
14,173

$
10,527

$
9,173

Interest cost
11,239

10,801

10,960

Expected long-term return on assets
(14,731
)
(14,093
)
(15,471
)
Prior service cost amortization
490

517

496

Actuarial loss amortization
13,979

8,603

6,435

Termination benefit charge


414

Settlement charge
1,373



Net periodic expense
$
26,523

$
16,355

$
12,007

Postretirement Benefit Plans
 
 
 
Components of net periodic benefit cost:
 
 
 
Service cost
$
1,694

$
1,853

$
1,769

Interest cost
3,504

4,248

4,443

Expected long-term return on assets
(5,024
)
(4,438
)
(4,418
)
Actuarial (gain) loss amortization
(120
)
37


Transition obligation amortization
1,296

1,917

1,917

Curtailment gain
(1,229
)


Net periodic expense
$
121

$
3,617

$
3,711


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

Years ended December 31, (in thousands)
2013
2012
2011
Pension Plans
 
 
 
Net actuarial (gain) loss experienced during the year
$
(14,138
)
$
28,748

$
14,312

Net actuarial loss recognized as expense
(8,934
)
(4,908
)
(3,755
)
Prior service cost recognized as expense
(311
)
(340
)
(298
)
Total recognized in other comprehensive income (loss)
(23,383
)
23,500

10,259

Postretirement Benefit Plans
 
 
 
Net actuarial (gain) loss experienced during the year
$
(8,057
)
$
(1,787
)
$
2,111

Net actuarial gain recognized as expense
550



Transition obligation recognized as expense
(283
)
(294
)
(286
)
Total recognized in other comprehensive income (loss)
$
(7,790
)
$
(2,081
)
$
1,825


Net retirement expense for Alagasco was $12.1 million , $7.8 million and $5.2 million for the years ended December 31, 2013 , 2012 and 2011 , respectively. In conjunction with the sale of its Black Warrior Basin coalbed methane properties in Alabama, the Company recognized a curtailment gain of $1.2 million in the fourth quarter of 2013. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the fourth quarter of 2013, the Company incurred a settlement charge of $0.8 million for the payment of lump sums from a defined benefit pension plan. In the first quarter of 2011, the Company recognized a termination benefit charge of $0.4 million to provide for early retirement of certain non-highly compensated

69



employees. Net periodic postretirement benefit cost for Alagasco was $0.8 million , $2.7 million and $2.8 million for the years ended December 31, 2013 , 2012 and 2011 , respectively.

Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2014 are as follows:

(in thousands)
 
Amortization of prior service cost
$
314

Amortization of net actuarial loss
$
5,422


Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2014 are as follows:

(in thousands)
 
Amortization of net transition obligation
$
42

Amortization of net actuarial gain
$
(593
)

The Company has a long-term disability plan covering most employees. The Company had expense for the years ended December 31, 2013 , 2012 and 2011 of $0.6 million , $0.7 million and $0.5 million , respectively.

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

Years ended December 31,
2013
2012
2011
Pension Plans
 
 
 
Discount rate
3.63
%
4.52
%
4.89
%
Expected long-term return on plan assets
7.00
%
7.00
%
7.25
%
Rate of compensation increase for pay-related plans
3.71
%
3.59
%
3.75
%
Postretirement Benefit Plans
 
 
 
Discount rate
4.26
%
4.95
%
5.45
%
Expected long-term return on plan assets
7.00
%
7.00
%
7.25
%
Rate of compensation increase
3.70
%
3.55
%
3.61
%

The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:
    
Years ended December 31,
2013
2012
Pension Plans
 
 
Discount rate
4.31
%
3.47
%
Rate of compensation increase for pay-related plans
3.63
%
3.71
%
Postretirement Benefit Plans
 
 
Discount rate
4.95
%
4.15
%
Rate of compensation increase for pay-related plans
3.60
%
3.70
%








70



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

As of December 31,
2013
2012
Health care cost trend rate assumed for next year
6.50
%
6.75
%
Rate to which the cost trend rate is assumed to decline
5.00
%
5.00
%
Year that rate reaches ultimate rate
2020

2020


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

(in thousands )
 
 
1-Percentage Point Decrease
1-Percentage Point Increase
Effect on total of service and interest cost
$
(280
)
$
336

Effect on net postretirement benefit obligation
$
(764
)
$
759


Investment Strategy: The Company employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.

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

The Company seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

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

 
Pension
Postretirement Benefits
As of December 31,
Target
2013
2012
Target
2013
2012
Asset category:
 
 
 
 
 
 
Equity securities
41
%
34
%
41
%
60
%
61
%
60
%
Debt securities
38
%
28
%
38
%
40
%
39
%
40
%
Other
21
%
38
%
21
%
%
%
%
Total
100
%
100
%
100
%
100
%
100
%
100
%

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










71



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

 
December 31, 2013
(in thousands)
Level 1
Level 2
Level 3
Total
United States equities
$
34,117

$
8,080

$

$
42,197

Global equities
20,153

13,256


33,409

Fixed income

61,121


61,121

Alternative investments

37,292


37,292

Cash and cash equivalents
5,970

39,545


45,515

Total
$
60,240

$
159,294

$

$
219,534

 
 
 
 
 
 
December 31, 2012
(in thousands)
Level 1
Level 2
Level 3
Total
United States equities
$
41,907

$
9,072

$

$
50,979

Global equities
23,782

10,697


34,479

Fixed income

78,806


78,806

Alternative investments

27,659

14,500

42,159

Cash and cash equivalents

3,001


3,001

Total
$
65,689

$
129,235

$
14,500

$
209,424


United States equities consist of mutual and commingled funds with varying strategies. Such strategies include stock investments across market capitalizations and investment styles. Global equities consist of mutual funds and a limited partnership that invest in United States and non-United States securities broadly diversified across mostly developed markets but with some tactical exposure to emerging markets. Fixed income securities consist of mutual funds and separate accounts. Fixed income securities are well diversified with allocations to investment grade and non-investment grade issues and issues that provide both intermediate and longer duration exposure. Alternative investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative investments are meant to serve as a risk reducer at the total portfolio level as they provide asset class exposures not found elsewhere in the portfolio.

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

Years ended December 31, (in thousands)
2013
2012
2011
Balance at beginning of period
$
14,500

$
17,399

$
26,841

Unrealized gains (losses)

992

(752
)
Unrealized gains relating to instruments held at the reporting date

242

635

Settlements

(4,948
)
(9,604
)
Purchases

815

279

Transfer out of Level 3
(14,500
)


Balance at end of period
$

$
14,500

$
17,399


Changes in Fair Value Levels: The availability of observable market data is monitored to assess the appropriate classification for financial instruments within the fair value hierarchy. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the cumulative reporting period. For the year ended December 31, 2013, except for the transfers out of Level 3 noted below, there were no significant transfers in or out of Levels 1, 2, or 3.

Transfer of Alternative Investments: The alternative investments consist of three investments that are measured at net asset value (NAV). NAV per share serves as an estimate for the fair value of an investment as long as certain requirements are met. During 2013, the Company determined that its alternative investments meet those requirements.




72



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

 
December 31, 2013
(in thousands)
Level 1
Level 2
Total
United States equities
$
43,054

$

$
43,054

Global equities
17,048


17,048

Fixed income

38,831

38,831

Total
$
60,102

$
38,831

$
98,933


 
December 31, 2012
(in thousands)
Level 1
Level 2
Total
United States equities
$
37,482

$

$
37,482

Global equities
15,049


15,049

Fixed income

34,658

34,658

Total
$
52,531

$
34,658

$
87,189


The Company had no Level 3 postretirement benefit plan assets. United States equities consists of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches. Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles. Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.

Cash Flows: 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 Company expects to make benefit payments of approximately $6.1 million during 2014 to retirees with respect to the nonqualified supplemental retirement plans.

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


(in thousands)

Pension Benefits
Postretirement Benefits
Postretirement Benefits – Prescription Drug Subsidy
2014
$66,816
$4,156
$(212)
2015
$16,572
$4,219
$(218)
2016
$18,174
$4,286
$(224)
2017
$22,167
$4,362
$(227)
2018
$28,374
$4,426
$(231)
2019-2023
$134,584
$22,319
$(1,202)

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

73



6. COMMON STOCK PLANS
 

Energen Employee Savings Plan (ESP): A majority of Company employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. The Company may match a percentage of the contributions and make these contributions in Company common stock or in funds for the purchase of Company common stock. Employees may diversify 100 percent of their ESP Company stock account into other ESP investment options. The ESP also contains employee stock ownership plan provisions. At December 31, 2013 , total shares reserved for issuance equaled 1,080,108 . Expense associated with Company contributions to the ESP was $8.0 million , $7.8 million and $6.8 million for the years ended December 31, 2013 , 2012 and 2011 , respectively.

Stock Incentive Plan: The Stock Incentive Plan provided for the grant of incentive stock options and non-qualified stock options to officers and key employees. The Stock Incentive Plan also provided for the grant of performance share awards and restricted stock. The Company has typically funded options, restricted stock obligations and performance share obligations through original issue shares and restricted stock through treasury shares. Under the Stock Incentive Plan, 8,600,000 shares of Company common stock were reserved for issuance with 2,921,392 remaining for issuance as of December 31, 2013 .

Performance Share Awards: The Stock Incentive Plan provided for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provided that payment of earned performance share awards be made in the form of Company common stock.

No performance share awards were granted in 2012 or 2011 . A summary of performance share award activity as of December 31, 2013 , and transactions during the year ended December 31, 2013 is presented below:

 
Stock Incentive Plan



                       Shares
Weighted
Average Price
Nonvested at December 31, 2012

$

Granted (two-year vesting period)
86,221

61.14

Granted (three-year vesting period)
82,606

62.96

Forfeited
(8,008
)
60.03

Nonvested at December 31, 2013
160,819

$
62.13


The Company recorded expense of $4.0 million for the year ended December 31, 2013 for performance share awards with a related deferred income tax benefit of $1.5 million . During the years ended December 31, 2012 and 2011, the Company recorded no expense for performance share awards. As of December 31, 2013, there was $5.5 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.49 years.

Stock Options: The Stock Incentive Plan provided for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provided for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.












74



A summary of stock option activity as of December 31, 2013 , and transactions during the years ended December 31, 2013 , 2012 and 2011 are presented below:

 
Stock Incentive Plan



Shares
Weighted Average Exercise Price
Outstanding at December 31, 2010
1,276,043

$
40.16

Granted
293,978

54.99

Exercised
(227,405
)
32.33

Forfeited
(4,375
)
35.35

Outstanding at December 31, 2011
1,338,241

44.77

Granted
371,040

54.11

Exercised
(58,471
)
24.55

Forfeited
(2,335
)
46.45

Outstanding at December 31, 2012
1,648,475

47.58

Granted
137,762

49.22

Exercised
(590,119
)
40.92

Forfeited
(5,074
)
51.85

Outstanding at December 31, 2013
1,191,044

$
51.06

Exercisable at December 31, 2011
677,753

$
43.72

Exercisable at December 31, 2012
987,733

$
43.75

Exercisable at December 31, 2013
713,445

$
49.80

Remaining reserved for issuance at December 31, 2013
2,921,392


The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values:

Grant date
10/15/2013
1/24/2013
1/25/2012
1/26/2011
Awards granted
3,686
134,076

371,040

293,978

Fair market value of stock option at grant
$30.53
$16.66
$18.79
$19.65
Expected life of award
5.8 years
5.8 years

5.8 years

5.8 years

Risk-free interest rate
1.79%
1.01
%
1.07
%
2.45
%
Annualized volatility rate
40.6%
40.3
%
39.6
%
37.8
%
Dividend yield
0.7%
1.2
%
1.0
%
1.0
%

The Company recorded stock option expense of $3.6 million , $7.0 million and $5.6 million during the years ended December 31, 2013 , 2012 and 2011 , respectively, with a related deferred tax benefit of $1.4 million , $2.6 million and $2.1 million , respectively.

The total intrinsic value of stock options exercised during the year ended December 31, 2013 , was $15.7 million . During the year ended December 31, 2013 , the Company received cash of $17.8 million from the exercise of stock options. Total intrinsic value for outstanding options as of December 31, 2013 , was $23.5 million and $14.9 million for exercisable options. The fair value of options vested for the year ended December 31, 2013 was $5.8 million . As of December 31, 2013 , there was $0.5 million of unrecognized compensation cost related to outstanding nonvested stock options.







75



The following table summarizes options outstanding as of December 31, 2013 :

Stock Incentive Plan

Range of Exercise Prices

Shares
Weighted Average Remaining Contractual Life
$46.45
59,330
3.00 years
$60.56
99,965
4.00 years
$29.79
78,222
5.00 years
$46.69
203,469
6.00 years
$54.99
266,166
7.00 years
$54.11
349,754
8.00 years
$48.36
130,452
9.00 years
$80.48
3,686
9.83 years
$29.79-$80.48
1,191,044
6.77 years

The weighted average remaining contractual life of currently exercisable stock options is 5.89 years as of December 31, 2013 .

Restricted Stock: In addition, the Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. Restricted stock awards have a three year vesting period. A summary of restricted stock activity as of December 31, 2013 , and transactions during the years ended December 31, 2013 , 2012 and 2011 is presented below:

 
Stock Incentive Plan
 

Shares
Weighted Average Price
Nonvested at December 31, 2010
24,150

$
35.49

Vested
(14,875
)
30.81

Nonvested at December 31, 2011
9,275

42.99

Granted
11,115

45.24

Vested
(9,275
)
42.97

Nonvested at December 31, 2012
11,115

45.24

Granted
52,650

52.34

Forfeited
(1,247
)
48.36

Nonvested at December 31, 2013
62,518

$
51.16


The Company recorded expense of $2.0 million , $0.1 million and $0.1 million for the years ended December 31, 2013 , 2012 and 2011 , respectively, related to restricted stock, with a related deferred income tax benefit of $746,000 , $31,000 and $47,000 , respectively. As of December 31, 2013 , there was $1.2 million of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 2.05 years.

Stock Appreciation Rights Plan: The Energen Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Company stock. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. These awards have a three year requisite service period.






76



A summary of stock appreciation rights activity as of December 31, 2013 , and transactions during the years ended December 31, 2013 , 2012 and 2011 are presented below:

 
 Stock Appreciation Rights Plan



Shares
Weighted Average Exercise Price
Outstanding at December 31, 2010
656,340

$
38.30

Granted
189,984

54.99

Exercised/forfeited
(69,106
)
41.21

Outstanding at December 31, 2011
777,218

42.00

Exercised/forfeited
(124,188
)
30.90

Outstanding at December 31, 2012
653,030

44.14

Granted
88,000

48.36

Exercised/forfeited
(363,653
)
39.66

Outstanding at December 31, 2013
377,377

$
49.48


The Company issued the following awards with stock appreciation rights. The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. On December 19, 2013, the Company modified certain stock appreciation rights subsequent to the original grant date. For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2013 :

Grant date
1/24/2013
1/24/2013
1/26/2011
1/26/2011
1/27/2010
 
 
(modified)
 
(modified)
 
Awards granted
87,069
931
182,199
7,785
171,749
Fair market value of award
$34.66
$27.89
$27.07
$24.21
$30.10
Expected life of award
5.6 years
2.5 years
3.6 years
2.5 years
3.0 years
Risk-free interest rate
2.04%
0.56%
1.06%
0.56%
0.80%
Annualized volatility rate
40.6%
40.6%
40.6%
40.6%
40.6%
Dividend yield
0.8%
0.8%
0.8%
0.8%
0.8%

Grant date
2/13-16/2009
1/28/2009
2/4/2008
2/1/2007
Awards granted
3,292
305,257
67,093
85,906
Fair market value of award
$39.87
$41.18
$18.50
$27.03
Expected life of award
2.5 years
2.5 years
2.0 years
1.5 years
Risk-free interest rate
0.58%
0.58%
0.39%
0.23%
Annualized volatility rate
40.6%
40.6%
40.6%
40.6%
Dividend yield
0.8%
0.8%
0.8%
0.8%

Expense associated with stock appreciation rights of $1.5 million and $4.3 million was recorded for the years ended December 31, 2013 and 2011. Income associated with stock appreciation rights of $1.0 million was recorded for the year ended December 31, 2012. During the year ended December 31, 2013 , the total intrinsic value of stock appreciation rights exercised was $8.5 million . During the year ended December 31, 2013 , the Company paid $5.8 million in settlement of stock appreciation rights.

Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which are re-measured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions were valued based on the Company’s stock price at the end of the period adjusted to remove the present value of future dividends.

77



A summary of Petrotech unit activity as of December 31, 2013 , and transactions during the years ended December 31, 2013 , 2012 and 2011 are presented below:
 
 
 Petrotech Incentive Plan


 
Shares
Outstanding at December 31, 2010

8,205

Granted (three-year vesting period)
 
6,314

Paid
 
(1,914
)
Forfeited
 
(1,544
)
Outstanding at December 31, 2011
 
11,061

Granted (three-year vesting period)
 
102,349

Granted (two-year vesting period)
 
3,768

Granted (18 month vesting period)
 
40,822

Paid
 
(3,281
)
Forfeited
 
(13,476
)
Outstanding at December 31, 2012
 
141,243

Granted (three-year vesting period)
 
92,418

Granted (17 month vesting period)
 
2,952

Paid
 
(36,792
)
Forfeited
 
(26,529
)
Outstanding at December 31, 2013
 
173,292


None of the awards issued included a market condition. Energen Resources recognized expense of $6.2 million , $2.6 million and $0.2 million during 2013 , 2012 and 2011 , respectively, related to these units.

1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of the Company’s creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the consolidated statements of shareholders’ equity. As of December 31, 2013 there were 695,140 shares reserved for issuance from the 1997 Deferred Compensation Plan.

1992 Energen Corporation Directors Stock Plan: In 1992 the Company adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 13,500 shares, 11,120 shares and 12,420 shares were awarded during the years ended December 31, 2013 , 2012 and 2011 , respectively, leaving 138,284 shares reserved for issuance as of December 31, 2013 .

Stock Repurchase Program: By resolution adopted May 25, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board authorized the Company to repurchase up to 12,564,400 shares of the Company’s common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2013 , 2012 and 2011 . As of December 31, 2013 , a total of 8,992,700 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company’s stock compensation plans. For the years ended December 31, 2013 , 2012 and 2011 , the Company acquired 14,766 shares, 5,459 shares and 12,867 shares, respectively, in connection with its stock compensation plans.





78



7. COMMITMENTS AND CONTINGENCIES
 


Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 7.1 million barrels of oil equivalent (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.

Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $171 million through September 2024 . During the years ended December 31, 2013 , 2012 and 2011 , Alagasco recognized approximately $50 million , $51 million and $51 million , respectively, of current-year commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 134 Bcf through August 2020 .

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

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 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.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and the Company has accrued a provision for its estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. The Company recognizes its liability for contingencies when information available indicates

79



both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the National Transportation and Safety Board which is investigating the incident. Alagasco has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against Alagasco.

Energen Resources previously disclosed an adverse judgment relating to the ownership of the Company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. Upon a Motion to Reconsider, the adverse judgment was vacated by the District Court in Ward County, Texas and a Summary Judgment Order dated July 30, 2013 was entered confirming Energen Resources’ superior title to the Cadenhead Well and its associated oil and gas leases. The Summary Judgment Order has been appealed by the other party.

New Mexico Audits: 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 .

Lease Obligations: Alagasco leases the Company’s headquarters building over a 25 -year term ending January 31, 2024 and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Effective July 1, 2013, Alagasco subleased the Company’s headquarters to Energen. Prior to July 2013, approximately 49 percent of the total headquarters lease payments were charged to Energen. As of July 2013, approximately 77 percent of the total headquarters lease payments are charged to Energen due to an increase in office space utilized by Energen. Alagasco recognizes Energen’s payment of rent expense in other income with an offset in other expense. These amounts are eliminated on the consolidated statements of income. Alagasco entered into a new lease for the current Alagasco corporate headquarters in July 2013 which is classified as an operating lease. Energen’s total lease payments included as operating lease expense were $25.0 million , $20.9 million and $19.1 million for the years ended December 31, 2013 , 2012 and 2011 , respectively. Minimum future rental payments required after 2013 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31,  (in thousands)
2014
2015
2016
2017
2018
2019 and thereafter
$5,270
$4,940
$4,391
$3,980
$2,409
$10,637

Alagasco’s total payments related to leases included as operating expense were $2.4 million , $2.1 million and $2.3 million for the years ended December 31, 2013 , 2012 and 2011 , respectively. These amounts are net of approximately $0.7 million , $1.0 million and $1.0 million of lease expense paid by Energen in 2013, 2012 and 2011, respectively. Minimum future rental payments required after 2013 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:


80



Years Ending December 31,  (in thousands)
2014
2015
2016
2017
2018
2019 and thereafter
$4,291
$4,062
$3,994
$3,979
$2,409
$10,637

Included in the table above are approximately $16.2 million of payments associated with leasing of the Company’s headquarters, which are expected to be reimbursed to Alagasco by Energen through the remaining term of the related lease.

8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
 

Financial Instruments: The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, approximates $1,420.7 million and $1,255.8 million and has a carrying value of $1,403.9 million and $1,154.0 million at December 31, 2013 and 2012, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, approximates $258.8 million and $284.7 million and has a carrying value of $249.9 million and $250.0 million at December 31, 2013 and 2012, respectively. The fair values were based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At December 31, 2013 , the fixed price purchases under these guarantees had a maximum term outstanding through October 2014 with an aggregate purchase price of $0.5 million and a market value of $0.6 million .

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At December 31, 2013 and 2012 , Alagasco’s finance receivable totaled approximately $10.8 million and $10.7 million , respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 84 months . Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.4 million and $0.5 million as of December 31, 2013 and 2012, respectively.

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

(in thousands)
 
Allowance for credit losses as of December 31, 2011
$
421

Provision
49

Allowance for credit losses as of December 31, 2012
470

Provision
(47
)
Allowance for credit losses as of December 31, 2013
$
423


Risk Management: At December 31, 2013 , the counterparty agreements under which the Company had active positions did not include collateral posting requirements. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at December 31, 2013 . The two largest counterparty net gain positions at December 31, 2013 , Macquarie Bank Limited and J Aron & Company, constituted approximately $8.6 million and $5.3 million of Energen Resources’ total net loss on fair value of derivatives.

81



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

(in thousands)
December 31, 2013
 
Oil and Gas Operations
 
Natural Gas Distribution

Total
Derivative assets or (liabilities) not designated as hedging instruments
 
 
 
Accounts receivable
36,224

 

36,224

Long-term asset derivative instruments
7,992

 

7,992

Total derivative assets
44,216

 

44,216

Accounts receivable
(18,761
)
*

(18,761
)
Long-term asset derivative instruments
(2,553
)
*

(2,553
)
Accounts payable
(30,302
)
 

(30,302
)
Total derivative liabilities
(51,616
)
 

(51,616
)
Total derivatives not designated
(7,400
)
 

(7,400
)

(in thousands)
December 31, 2012
 
Oil and Gas Operations
 
Natural Gas Distribution

Total
Derivative assets or (liabilities) designated as hedging instruments
 
 
 
 
Accounts receivable
$
87,514

 
$

$
87,514

Long-term asset derivative instruments
37,954

 

37,954

Total derivative assets
125,468

 

125,468

Accounts receivable
(37,326
)
*

(37,326
)
Long-term asset derivative instruments
(6,810
)
*

(6,810
)
Long-term liability derivative instruments
(8,726
)
 

(8,726
)
Total derivative liabilities
(52,862
)
 

(52,862
)
Total derivatives designated
72,606

 

72,606

Derivative assets or (liabilities) not designated as hedging instruments
 
 
 
Accounts receivable
14,604

 

14,604

Long-term asset derivative instruments
9,433

 

9,433

Total derivative assets
24,037

 

24,037

Accounts payable

 
(2,593
)
(2,593
)
Long-term liability derivative instruments
(874
)
 

(874
)
Total derivative liabilities
(874
)
 
(2,593
)
(3,467
)
Total derivatives not designated
23,163

 
(2,593
)
20,570

Total derivatives
$
95,769

 
$
(2,593
)
$
93,176

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

The Company had a net $8.2 million and a net $28.4 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in other comprehensive income as of December 31, 2013 and 2012 , respectively.






82



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


Years ended December 31, (in thousands)
Location on Income Statement
2013
2012
2011
Net gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($6,660), $40,720 and $41,399
$
(10,866
)
$
66,438

$
67,547

Gain reclassified from accumulated OCI into
income (effective portion)
Operating revenues
$
34,293

$
52,694

$
26,326

Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)

Operating revenues
$
835

$
(5,340
)
$
(2,767
)

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


Years ended December 31, (in thousands)
Location on Income Statement
2013
2012
2011
Gain (loss) recognized in income on derivative
Operating revenues
$
(73,980
)
$
61,841

$
(37,587
)

As of December 31, 2013 , $13.4 million of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, net of tax, are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of December 31, 2013, the Company had 51.8 billion cubic feet (Bcf) and 6.0 Bcf of natural gas hedges which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 9.8 million barrels (MMBbl) and 5.8 MMBbl of oil hedges which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 1.9 million gallons (MMgal) of natural gas liquid hedges which expire during 2014 that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $4.5 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale or sold.

As of December 31, 2013, 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

As of December 31, 2013 , the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010. 






83



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 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 were classified as Level 2 fair values and are included in the above table as current liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2013 and 2012 .

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.

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

Years ended December 31, (in thousands)
2013
2012
2011
Balance at beginning of period
$
89,019

$
65,801

$
42,755

Realized gains
55,210

63,720

52,716

Unrealized gains (losses) relating to instruments held at the reporting date*
(71,367
)
22,160

23,980

Settlements during period
(54,573
)
(62,662
)
(53,650
)
Balance at end of period
$
18,289

$
89,019

$
65,801

*Includes $7.6 million in mark-to-market losses, $19.9 million in mark-to-market gains and $5.2 million in mark-to-market losses for the years ended December 31, 2013, 2012 and 2011, respectively.









84



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

(in thousands)
Fair Value as of December 31, 2013
Valuation Technique*
Unobservable Input*
Range
Natural Gas Basis - San Juan
 
 
 
 
2014
$
18,159

Discounted Cash Flow
Forward Basis
($0.17 - $0.20) Mcf
2015
$
1,056

Discounted Cash Flow
Forward Basis
($0.26) Mcf
Natural Gas Basis - Permian
 
 
 
 
2014
$
(1,948
)
Discounted Cash Flow
Forward Basis
($0.18 - $0.20) Mcf
Natural Gas Liquids
 
 
 
 
2014
$
1,022

Discounted Cash Flow
Forward Price
 $0.80 - $0.81 Gal
*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

The tables below set forth information about the offsetting of derivative assets and liabilities as follows:

 
December 31, 2013
 
 
 
 
Gross Amounts Not Offset in the Balance Sheets
 
(in thousands)
Gross Amounts Recognized
Gross Amounts Offset in the Balance Sheets
Net Amount Presented in the Balance Sheets
Financial Instruments
Cash Collateral Received
Net Amount
Derivative assets
$
44,215

$
(21,313
)
$
22,902

$

$

$
22,902

Derivative liabilities
$
51,615

$
(21,313
)
$
30,302

$

$

$
30,302


 
December 31, 2012
 
 
 
 
Gross Amounts Not Offset in the Balance Sheets
 
(in thousands)
Gross Amounts Recognized
Gross Amounts Offset in the Balance Sheets
Net Amount Presented in the Balance Sheets
Financial Instruments
Cash Collateral Received
Net Amount
Derivative assets
$
149,504

$
(44,135
)
$
105,369

$

$

$
105,369

Derivative liabilities
$
56,328

$
(44,135
)
$
12,193

$

$

$
12,193


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 .

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 422,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.




85



9. RECONCILIATION OF EARNINGS PER SHARE
 

Years ended December 31,
 
 
 
 
 
 
 
 
 
(in thousands, except per share amounts)
2013
 
 
2012
 
 
2011
 
 
Net
Income

Shares
Per Share Amount
Net
Income

Shares
Per Share Amount
Net
Income

Shares
Per Share Amount
Basic EPS
$
204,554

72,318

$
2.83

$
253,562

72,119

$
3.52

$
259,624

72,056

$
3.60

Effect of dilutive securities
 
 
 
 
 
 
 
 
 
Stock options
 
112

 
 
196

 
 
270

 
Non-vested restricted stock
 
20

 
 
1

 
 
6

 
Performance share awards
 
21

 
 

 
 

 
Diluted EPS
$
204,554

72,471

$
2.82

$
253,562

72,316

$
3.51

$
259,624

72,332

$
3.59


The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive.

Years ended December 31, (in thousands)
2013
2012
2011
Stock options
134,138

849,583

293,978

Non-vested restricted stock
6,529



Performance share awards
4,121




10. ASSET RETIREMENT OBLIGATIONS
 

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the period incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company. Revisions in estimates to the ARO result from revisions to the estimated timing or amount of the underlying cash flows. In 2013 , 2012 and 2011 , Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
 
Balance as of December 31, 2010
$
97,415

Liabilities incurred
4,627

Liabilities settled
(1,539
)
Accretion expense (including discontinued operations of $1,138)
6,837

Balance as of December 31, 2011
107,340

Liabilities incurred
3,994

Liabilities settled
(845
)
Accretion expense (including discontinued operations of $1,195)
7,534

Balance as of December 31, 2012
118,023

Liabilities incurred
2,772

Liabilities settled
(5,525
)
Accretion expense (including discontinued operations of $1,197)
8,192

Reclassification associated with held for sale properties*
(14,929
)
Balance as of December 31, 2013
$
108,533


86



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

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $27.5 million and $24.9 million to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of December 31, 2013 and 2012 , respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $4.6 million and $3.3 million as of December 31, 2013 and 2012, respectively, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

11. SUPPLEMENTAL CASH FLOW INFORMATION
 

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

Years ended December 31, (in thousands)
2013
2012
2011
Interest paid, net of amount capitalized
$
65,143

$
61,379

$
33,601

Income taxes paid
$
25,081

$
17,170

$
9,432

Noncash investing activities:
 
 
 
Accrued development, exploration costs and other capital
$
99,128

$
120,024

$
72,030

Capitalized depreciation
$
66

$
80

$
93

Capitalized asset retirement obligations costs
$
3,574

$
4,409

$
4,927

Allowance for funds used during construction
$
698

$
623

$
807

Capital lease obligations
$

$
5,072

$

Noncash financing activities:
 
 
 
Issuance of common stock for employee benefit plans
$
1,015

$
838

$
822

Treasury stock acquired in connection with tax withholdings
$
977

$
277

$
713


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

Years ended December 31, (in thousands)
2013
2012
2011
Interest paid, net of amount capitalized
$
13,465

$
13,513

$
12,385

Income taxes paid
$
23,138

$
16,796

$
5,143

Interest expense (revenue) on affiliated company debt, net
$
(18
)
$
295

$
376

Noncash investing activities:
 
 
 
Accrued property, plant and equipment costs
$
5,505

$
3,536

$
2,229

Capitalized depreciation
$
66

$
80

$
93

Capitalized asset retirement obligations costs
$
802

$
415

$
300

Allowance for funds used during construction
$
698

$
623

$
807











87



12. ACQUISITION AND DISPOSITION OF PROPERTIES
 

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 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 .

During 2013, Energen also completed a total of approximately $31.3 million in various purchases of unproved leasehold properties.

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

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

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

(in thousands)
 
Consideration given
 
    Cash (net)
$
67,615

Recognized amounts of identifiable assets acquired and liabilities assumed
 
    Proved properties
$
65,581

    Unproved leasehold properties
911

    Accounts receivable
1,358

    Accounts payable
(25
)
    Asset retirement obligation
(210
)
     Total identifiable net assets
$
67,615


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

In December 2012, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $18.7 million . During 2012, Energen also completed a total of approximately $18 million in various purchases of unproved leasehold properties.
 
On December 27, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $60 million . This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

88



The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011 (including the effects of closing adjustments).

(in thousands)
 
Consideration given
 
    Cash (net)
$
60,017

Recognized amounts of identifiable assets acquired and liabilities assumed
 
    Proved properties
$
36,068

    Unproved leasehold properties
23,686

    Accounts receivable
680

    Accounts payable
(244
)
    Asset retirement obligation
(173
)
     Total identifiable net assets
$
60,017


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

On November 16, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $162 million . This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011 (including the effects of closing adjustments).

(in thousands)
 
Consideration given
 
    Cash (net)
$
161,967

Recognized amounts of identifiable assets acquired and liabilities assumed
 
    Proved properties
$
151,544

    Unproved leasehold properties
7,883

    Accounts receivable
3,070

    Accounts payable
(388
)
    Asset retirement obligation
(142
)
     Total identifiable net assets
$
161,967


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

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








89



13. 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 which is reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

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. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

The following table details held-for-sale properties by major classes of assets and liabilities:

(in thousands)
December 31, 2013
 
Black Warrior Basin
North Louisiana/East Texas

Total
Accounts receivable
$
2,829

$
1,272

$
4,101

Inventories

68

68

Oil and gas properties

348,379

348,379

Less accumulated depreciation, depletion and amortization

(301,609
)
(301,609
)
Other property, net

165

165

Total assets held-for-sale
2,829

48,275

51,104

Accounts payable
(1,732
)
(11
)
(1,743
)
Royalty payable
(550
)
(869
)
(1,419
)
Other current liabilities
(379
)
(21
)
(400
)
Other long-term liabilities

(14,983
)
(14,983
)
Total liabilities held-for-sale
(2,661
)
(15,884
)
(18,545
)
Total held-for-sale properties
$
168

$
32,391

$
32,559


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.

Gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. Accordingly, the results of operations for certain held-for-sale properties were reclassified and reported as discontinued operations for all prior periods presented. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.


90



Years ended December 31, (in thousands, except per share data)
2013
2012
2011
 
 
 
 
Oil and gas revenues
$
60,191

$
76,350

$
110,366

Pretax income (loss) from discontinued operations
$
10,028

$
(2,373
)
$
54,698

Income tax expense (benefit)
2,215

(715
)
19,379

Income (Loss) From Discontinued Operations
$
7,813

$
(1,658
)
$
35,319

Gain on disposal of discontinued operations, net
$
5,605

$

$

Income tax expense
2,011



Gain on Disposal of Discontinued Operations, net
$
3,594

$

$

Total Income (Loss) From Discontinued Operations
$
11,407

$
(1,658
)
$
35,319

Diluted Earnings Per Average Common Share
 
 
 
Income (Loss) from Discontinued Operations
$
0.10

$
(0.02
)
$
0.49

Gain on Disposal of Discontinued Operations, net
0.05



Total Income (Loss) From Discontinued Operations
$
0.15

$
(0.02
)
$
0.49

Basic Earnings Per Average Common Share
 
 
 
Income (Loss) from Discontinued Operations
$
0.11

$
(0.02
)
$
0.49

Gain on Disposal of Discontinued Operations, net
0.05



Total Income (Loss) From Discontinued Operations
$
0.16

$
(0.02
)
$
0.49






































91



14. REGULATORY ASSETS AND LIABILITIES
 

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

(in thousands)
December 31, 2013
December 31, 2012
 
Current
Noncurrent
Current
Noncurrent
Regulatory assets:
 
 
 
 
Pension assets
$
325

$
58,243

$
170

$
90,708

Accretion and depreciation for asset retirement obligation

18,046


16,536

Risk management activities


2,593


Rate recovery of asset removal costs, net

4,601


3,322

Enhanced stability reserve

4,000



Gas supply adjustment
2,406


42,726


Other
25


26


Total regulatory assets
$
2,756

$
84,890

$
45,515

$
110,566

 
 
 
 
 
Regulatory liabilities:
 
 
 
 
RSE adjustment
$
4,690

$

$
1,740

$

Unbilled service margin
28,504


25,078


Postretirement liabilities

26,197


1,237

Refundable negative salvage
15,779

39,663

18,265

53,467

Asset retirement obligation

27,528


24,930

Other
33

737

33

770

Total regulatory liabilities
$
49,006

$
94,125

$
45,116

$
80,404


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

15. TRANSACTIONS WITH RELATED PARTIES
 

The Company allocates certain corporate costs to Energen Resources and Alagasco based on the nature of the expense to be allocated using various factors including, but not limited to, total assets, earnings, or number of employees. The Company’s cash management program seeks to minimize borrowing from outside sources through inter-company lending. Under this program, Alagasco may borrow from but does not lend to affiliates. Alagasco had net trade receivables from affiliates of $4.7 million and $5.7 million at December 31, 2013 and 2012 , respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. Alagasco had $18,000 in affiliated company interest revenue during the year ended December 31, 2013 . Alagasco had $0.3 million and $0.4 million in affiliated company interest expense during the years ended December 31, 2012 and 2011 , respectively.










92



16. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
 

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.

(in thousands)
Cash Flow Hedges
Pension and Postretirement Plans
Total
Balance as of December 31, 2012
$
44,196

$
(52,507
)
$
(8,311
)
Other comprehensive income (loss) before reclassifications
(11,014
)
11,582

568

Amounts reclassified from accumulated other comprehensive income (loss)
(21,004
)
8,680

(12,324
)
Change in accumulated other comprehensive income (loss)
(32,018
)
20,262

(11,756
)
Balance as of December 31, 2013
$
12,178

$
(32,245
)
$
(20,067
)

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

 
Year ended
 
 
December 31, 2013
 
(in thousands)
Amounts Reclassified
Line Item Where Presented
Gains and (losses) on cash flow hedges:
 
 
Commodity contracts
$
35,684

Operating revenues
Interest rate swap
(1,723
)
Interest expense
Total cash flow hedges
33,961

 
Income tax expense
(12,957
)
 
Net of tax
21,004

 
Pension and postretirement plans:
 
 
Transition obligation
(319
)
Operations and maintenance
Prior service cost
(257
)
Operations and maintenance
Actuarial losses*
(12,357
)
Operations and maintenance
Actuarial losses on settlement charges*
(421
)
Regulatory asset
Total pension and postretirement plans
(13,354
)
 
Income tax expense
4,674

 
Net of tax
(8,680
)
 
Total reclassifications for the period
$
12,324

 
* In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 is recognized in actuarial losses above and $46,000 is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

17. RECENTLY ISSUED ACCOUNTING STANDARDS
 

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued Accounting Standard Update (ASU) No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained

93



unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 8, Financial Instruments.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 16, Accumulated Other Comprehensive Income (Loss).

18. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)
 

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

 
Year ended December 31, 2013
(in thousands, except per share amounts)
First
Second
Third
Fourth
Operating revenues as originally reported
$
492,679

$
490,057

$
320,406

$
472,733

Discontinued operations*
(18,663
)
(18,562
)


Adjusted operating revenues
$
474,016

$
471,495

$
320,406

$
472,733

Operating income (loss) as originally reported
$
105,336

$
146,304

$
(4,052
)
$
110,630

Discontinued operations*
(3,146
)
(3,871
)


Adjusted operating income (loss)
$
102,190

$
142,433

$
(4,052
)
$
110,630

Income (loss) from continuing operations
$
54,694

$
80,614

$
(5,486
)
$
63,325

Net income (loss)
$
56,692

$
83,067

$
(19,298
)
$
84,093

Diluted earnings per average common share
 
 
 
 
Continuing operations
$
0.76

$
1.11

$
(0.08
)
$
0.87

Net income (loss)
$
0.78

$
1.15

$
(0.27
)
$
1.15

Basic earnings per average common share
 
 
 
 
Continuing operations
$
0.76

$
1.12

$
(0.08
)
$
0.87

Net income (loss)
$
0.79

$
1.15

$
(0.27
)
$
1.16

* As discussed in Note 13, Discontinued Operations, during the fourth quarter of 2013, the Company completed the sale of its Black Warrior Basin coalbed methane properties in Alabama. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013 . Also, during the third quarter of 2013, the Company classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations.

94



 
Year ended December 31, 2012
(in thousands, except per share amounts)
First
Second
Third
Fourth
Operating revenues as originally reported
$
418,444

$
470,355

$
295,324

$
433,046

Discontinued operations
(20,255
)
(18,451
)
(18,895
)
(18,749
)
Adjusted operating revenues
$
398,189

$
451,904

$
276,429

$
414,297

Operating income as originally reported
$
104,170

$
220,598

$
19,458

$
115,166

Discontinued operations
16,324

(4,751
)
(5,494
)
(3,557
)
Adjusted operating income
$
120,494

$
215,847

$
13,964

$
111,609

Income (loss) from continuing operations
$
67,868

$
128,305

$
(1,505
)
$
60,552

Net income
$
57,406

$
131,287

$
2,046

$
62,823

Diluted earnings per average common share
 
 
 
 
Continuing operations
$
0.94

$
1.77

$
(0.02
)
$
0.84

Net income
$
0.79

$
1.82

$
0.03

$
0.87

Basic earnings per average common share
 
 
 
 
Continuing operations
$
0.94

$
1.78

$
(0.02
)
$
0.84

Net income
$
0.80

$
1.82

$
0.03

$
0.87


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

 
Year ended December 31, 2013
(in thousands)
First
Second
Third
Fourth
Operating revenues
$
237,685

$
104,514

$
48,368

$
142,771

Operating income (loss)
$
79,293

$
2,219

$
(22,544
)
$
34,800

Net income (loss)
$
47,222

$
(704
)
$
(8,961
)
$
19,842


 
Year ended December 31, 2012
(in thousands)
First
Second
Third
Fourth
Operating revenues
$
194,487

$
70,887

$
61,809

$
124,406

Operating income (loss)
$
78,560

$
4,448

$
(12,743
)
$
22,951

Net income (loss)
$
46,918

$
326

$
(10,039
)
$
12,197


19. OIL AND GAS OPERATIONS (Unaudited)
 

Capitalized Costs: The following table sets forth capitalized costs:

(in thousands)
December 31, 2013
December 31, 2012
Proved
$
7,043,779

$
6,241,148

Unproved
168,975

197,979

Total capitalized costs
7,212,754

6,439,127

Accumulated depreciation, depletion and amortization
2,078,411

1,765,241

Capitalized costs, net
$
5,134,343

$
4,673,886



95



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

Years ended December 31, (in thousands)
2013
2012
2011
Property acquisition:
 
 
 
Proved
$
4,661

$
79,862

$
214,993

Unproved
26,820

58,634

91,888

Exploration
435,636

419,284

190,854

Development
655,353

749,256

623,775

Total costs incurred
$
1,122,470

$
1,307,036

$
1,121,510


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

Years ended December 31, (in thousands)
2013
2012
2011
Gross revenues*
$
1,206,293

$
1,090,948

$
834,700

Production (lifting costs)
351,541

278,193

226,361

Exploration expense
27,942

19,356

12,967

Depreciation, depletion and amortization
449,700

339,569

210,532

Accretion expense
6,995

6,339

5,699

Income tax expense
128,773

160,551

134,564

Results of operations from producing activities
$
241,342

$
286,940

$
244,577

* The years ended December 31, 2013, 2012 and 2011 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million , a pre-tax non-cash mark-to-market gain on derivatives of $58.8 million and a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million , respectively.

Oil and Gas Operations: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2013 , 2012 and 2011 . Changes to prices and costs could have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of reserves disclosed. The proved reserves are located onshore in the United States of America.

Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers, have audited the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2013 . Ryder Scott audited the reserve estimates for coalbed methane in the San Juan basins and substantially all of the Permian Basin reserves. T. Scott Hickman audited the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 98 percent of the Company’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.


96



Year ended December 31, 2013
Gas MMcf

Oil MBbl

NGL MBbl

Total MMBOE

Proved reserves at beginning of period
809,128

155,348

56,155

346.4

Revisions of previous estimates
18,465

(680
)
2,211

4.6

Purchases
282

142

56

0.2

Extensions and discoveries
50,568

20,517

7,823

36.8

Production
(70,506
)
(10,378
)
(3,233
)
(25.4
)
Sales
(88,212
)
(79
)
(1
)
(14.8
)
Proved reserves at end of period
719,725

164,870

63,011

347.8

Proved developed reserves at end of period
623,305

113,795

42,087

259.8

Proved undeveloped reserves at end of period
96,420

51,075

20,924

88.0

Year ended December 31, 2012
Gas MMcf

Oil MBbl

NGL MBbl

Total MMBOE

Proved reserves at beginning of period
957,368

129,578

53,957

343.1

Revisions of previous estimates
(143,704
)
(8,546
)
(9,557
)
(42.1
)
Purchases
10,656

7,950

2,569

12.4

Extensions and discoveries
61,170

35,132

11,759

57.1

Production
(76,362
)
(8,766
)
(2,573
)
(24.1
)
Proved reserves at end of period
809,128

155,348

56,155

346.4

Proved developed reserves at end of period
708,657

105,976

36,440

260.5

Proved undeveloped reserves at end of period
100,471

49,372

19,715

85.9

Year ended December 31, 2011
Gas MMcf

Oil MBbl

NGL MBbl

Total MMBOE

Proved reserves at beginning of period
954,387

103,262

40,601

302.9

Revisions of previous estimates
(12,823
)
(4,513
)
841

(5.8
)
Purchases
19,362

12,583

5,055

20.8

Extensions and discoveries
68,160

24,564

9,637

45.6

Production
(71,718
)
(6,318
)
(2,177
)
(20.4
)
Proved reserves at end of period
957,368

129,578

53,957

343.1

Proved developed reserves at end of period
788,812

83,899

33,154

248.5

Proved undeveloped reserves at end of period
168,556

45,679

20,803

94.6


2013 Activities: Energen Resources had upward reserve revisions during 2013 which totaled 4.6 MMBOE including approximately 7 MMBOE related to changes in year-end pricing and downward revisions of approximately 5.3 MMBOE of proved undeveloped reserves of which 4.6 MMBOE are expected to be drilled beyond five years with the remainder no longer expected to be drilled. The San Juan Basin upward reserve revisions of 2.2 MMBOE including 5.9 MMBOE related to changes in year-end pricing and downward revisions of approximately 4.6 MMBOE of proved undeveloped reserves that are expected to be drilled beyond five years. Net upward reserve revisions of 1.2 MMBOE in the Permian Basin were due to improved well performance in certain Wolfberry wells and approximately 0.4 MMBOE related to changes in the year-end pricing and downward revisions of approximately 0.7 MMBOE of proved undeveloped reserves that are no longer expected to be drilled.

Energen Resources purchased 0.2 MMBOE of reserves during 2013 primarily related to the acquisitions of oil properties in the Permian Basin.

During 2013, Energen Resources had extensions and discoveries of  36.8 MMBOE of which  45 percent were proved undeveloped reserves and  55 percent were proved developed reserves. Extension drilling resulted in 21.6 MMBOE of discoveries with exploratory drilling providing  15.2 MMBOE of discoveries. The San Juan Basin added  2.3 MMBOE of reserves through 30 pay adds. The Permian Basin added  34.4 MMBOE of reserves primarily through the drilling or identification of  262 well locations.


97



During 2013, Energen Resources had sales of 14.8 MMBOE primarily due to the sale of the Black Warrior Basin coalbed methane properties.

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

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

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

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

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

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

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. At December 31, 2013 , 2012 and 2011 , the Company had a deferred hedging gain of $21.6 million , a deferred hedging gain of $74.8 million and a deferred hedging gain of $15 million , respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.

Years ended December 31, (in thousands)
2013
2012
2011
Future gross revenues
$
19,509,305

$
17,735,363

$
18,196,229

Future production costs
6,136,709

5,715,248

5,823,395

Future development costs
1,896,602

1,892,600

1,539,072

Future income tax expense
3,209,697

2,809,411

3,326,382

Future net cash flows
8,266,297

7,318,104

7,507,380

Discount at 10% per annum
4,248,456

3,618,785

3,878,217

Standardized measure of discounted future net cash
flows relating to proved oil and gas reserves
$
4,017,841

$
3,699,319

$
3,629,163



98



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

Years ended December 31, (in thousands)
2013
2012
2011
Balance at beginning of year
$
3,699,319

$
3,629,163

$
2,467,136

Revisions to reserves proved in prior years:
 
 
 
Net changes in prices, production costs and future development costs
566,838

(922,792
)
707,411

Net changes due to revisions in quantity estimates
(81,762
)
(383,755
)
(80,004
)
Development costs incurred, previously estimated
299,432

472,603

392,720

Accretion of discount
369,932

362,916

246,714

Changes in timing and other
(179,502
)
(317,244
)
(25,937
)
Total revisions
974,938

(788,272
)
1,240,904

New field discoveries and extensions, net of future production and development costs
376,326

1,025,419

755,977

Sales of oil and gas produced, net of production costs
(1,014,593
)
(812,781
)
(763,171
)
Purchases
4,690

189,755

232,768

Sales
(24,876
)


Net change in income taxes
2,037

456,035

(304,451
)
Net change in standardized measure of discounted future net cash flows
318,522

70,156

1,162,027

Balance at end of year
$
4,017,841

$
3,699,319

$
3,629,163



99



20. INDUSTRY SEGMENT INFORMATION
 

The Company is principally engaged in two business segments: the development, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.
Years ended December 31,(in thousands)
2013
2012
2011
Operating revenues from continuing operations
 
 
 
Oil and gas operations
$
1,205,312

$
1,089,230

$
838,160

Natural gas distribution
533,338

451,589

534,953

Total
$
1,738,650

$
1,540,819

$
1,373,113

Operating income (loss) from continuing operations
 
 
 
Oil and gas operations
$
257,963

$
369,765

$
308,561

Natural gas distribution
93,768

93,216

86,216

Eliminations and corporate expenses
(530
)
(1,067
)
(1,078
)
Total
$
351,201

$
461,914

$
393,699

Depreciation, depletion and amortization expense from continuing operations
 
Oil and gas operations
$
453,474

$
343,183

$
213,841

Natural gas distribution
43,907

42,270

39,916

Total
$
497,381

$
385,453

$
253,757

Interest expense
 
 
 
Oil and gas operations
$
53,981

$
49,958

$
30,907

Natural gas distribution
15,649

16,284

14,740

Eliminations and other
(430
)
(700
)
(825
)
Total
$
69,200

$
65,542

$
44,822

Income tax expense (benefit) from continuing operations
 
 
 
Oil and gas operations
$
71,290

$
115,090

$
100,700

Natural gas distribution
34,687

30,244

26,670

Other
(695
)
(800
)
(1,048
)
Total
$
105,282

$
144,534

$
126,322

Capital expenditures
 
 
 
Oil and gas operations
$
1,104,745

$
1,291,211

$
1,115,452

Natural gas distribution
88,769

71,869

73,984

Total
$
1,193,514

$
1,363,080

$
1,189,436

Identifiable assets
 
 
 
Oil and gas operations
$
5,379,135

$
4,975,170

$
4,046,242

Natural gas distribution
1,193,413

1,177,134

1,163,959

Eliminations and other
49,664

23,586

27,215

Total
$
6,622,212

$
6,175,890

$
5,237,416

Property, plant and equipment, net
 
 
 
Oil and gas operations
$
5,116,958

$
4,697,683

$
3,806,787

Natural gas distribution
885,550

842,685

813,471

Other
1,130

1,268

518

Total
$
6,003,638

$
5,541,636

$
4,620,776


100



SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

Energen Corporation

Years ended December 31, (in thousands)
2013
2012
2011
 
 
 
 
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year
$
6,549

$
12,946

$
15,048

 
 
 
 
Additions:
 
 
 
Charged to income
2,244

1,415

4,269

Recoveries and adjustments
(1,463
)
(1,262
)
(1,744
)
 
 
 
 
Net additions
781

153

2,525

 
 
 
 
Less uncollectible accounts written off
(1,636
)
(6,550
)
(4,627
)
 
 
 
 
Balance at end of year
$
5,694

$
6,549

$
12,946


Alabama Gas Corporation

Years ended December 31, (in thousands)
2013
2012
2011
 
 
 
 
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year
$
5,700

$
12,100

$
14,200

 
 
 
 
Additions:
 
 
 
Charged to income
2,243

1,409

4,202

Recoveries and adjustments
(1,469
)
(1,263
)
(1,745
)
 
 
 
 
Net additions
774

146

2,457

 
 
 
 
Less uncollectible accounts written off
(1,474
)
(6,546
)
(4,557
)
 
 
 
 
Balance at end of year
$
5,000

$
5,700

$
12,100



101



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

None

ITEM 9A. CONTROLS AND PROCEDURES

Energen Corporation
a. Disclosure Controls and Procedures

Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

b. Management’s Report on Internal Control Over Financial Reporting

Management of Energen Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Energen Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:
i
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Energen Corporation;
ii
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Energen Corporation are being made only in accordance with authorization of management and directors of Energen Corporation; and
iii
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Management assessed the effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2013 . Management based this assessment on criteria for effective internal control over financial reporting described in “ Internal Control - Integrated Framework” (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Energen Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
 
Based on this assessment, management determined that, as of December 31, 2013 , Energen Corporation maintained effective internal control over financial reporting. The effectiveness of Energen Corporation’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

c. Changes in Internal Control Over Financial Reporting

Our chief executive officer and chief financial officer of Energen Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.





102



Alabama Gas Corporation
a. Disclosure Controls and Procedures

Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

b. Management’s Report on Internal Control Over Financial Reporting

Management of Alabama Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Alabama Gas Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:

i
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Alabama Gas Corporation;
ii
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Alabama Gas Corporation are being made only in accordance with authorization of management and directors of Alabama Gas Corporation; and
iii
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Management assessed the effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2013. Management based this assessment on criteria for effective internal control over financial reporting described in “ Internal Control - Integrated Framework” (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Alabama Gas Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
 
Based on this assessment, management determined that, as of December 31, 2013, Alabama Gas Corporation maintained effective internal control over financial reporting. The effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report which appears herein.

c. Remediation of Material Weakness

Alabama Gas Corporation disclosed in Item 4 . Controls and Procedures of our Quarterly Report on Form 10-Q, for the quarter ended September 30, 2013, that we identified a material weakness in our internal control over financial reporting related to failure by Alabama Gas Corporation’s principal accounting officer to operate within the Company’s code of conduct. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Due to this weakness, certain controls were overridden resulting in an immaterial understatement of expenses for the quarter ended June 30, 2013 of approximately $76,000. Since the override was identified by management prior to preparation of financial statements for the quarter ended September 30, 2013, it did not result in misstatement for that quarter.

Management, with the participation of the chief executive officer and chief financial officer, took action to remediate the material weakness described above including the following:

The principal accounting officer who overrode the control has separated from Alabama Gas Corporation

103



A qualified successor principal accounting officer has been elected by the Alabama Gas Corporation Board of Directors
In addition to an ongoing annual training process, the importance of adherence to Alabama Gas Corporation’s statement of principles and business conduct guidelines as well as compliance with applicable accounting and reporting principles was reviewed and reinforced with key accounting personnel
The importance of timely, complete and accurate recording of expenses was reviewed and reinforced with the Alabama Gas Corporation officers

Management has completed the remediation measures described above and, as of December 31, 2013, has concluded that the steps taken have remediated the material weakness.

d. Changes in Internal Control Over Financial Reporting

As described above under “Remediation of Material Weakness”, there was a change, during the most recent fiscal quarter, in our internal control over financial reporting that materially affected our internal control over financial reporting.


104



PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014 . The definitive proxy statement will be filed on or about March 21, 2014 .

ITEM 11.    EXECUTIVE COMPENSATION

The information regarding executive compensation is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014 .

ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

a. Security Ownership of Certain Beneficial Owners

The information regarding the security ownership of the beneficial owners of more than five percent of Energen’s common stock is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014 .

b. Security Ownership of Management

The information regarding the security ownership of management is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014 .

c. Securities Authorized for Issuance Under Equity Compensation Plans

The following table summarizes information concerning securities authorized for issuance under equity compensation plans as of December 31, 2013:



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

Weighted Average Exercise Price
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders*
1,191,044

$
51.06

3,754,816
Equity compensation plans not approved by security holders


Total
1,191,044

$
51.06

3,754,816
* These plans include 2,921,392 shares associated with the Company’s Stock Incentive Plan, 138,284 shares associated with the 1992 Energen Corporation Directors Stock Plan and 695,140 shares associated with the 1997 Deferred Compensation Plan.

ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information regarding certain relationships and related transactions, and director independence is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014 .

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2014 .


105



PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a. Documents Filed as Part of This Report

(1)
Financial Statements
The consolidated financial statements of Energen and the financial statements of Alagasco are included in Item 8 of this Form 10-K.

(2)
Financial Statement Schedules
The financial statement schedules are included in Item 8 of this Form 10-K.

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


106



Energen Corporation
Alabama Gas Corporation
INDEX TO EXHIBITS
Item 14(a)(3)
Exhibit
 
Number
Description
 
 
*3(a)
Restated Certificate of Incorporation of Energen Corporation (composite, as amended April 29, 2005) which was filed as Exhibit 3(a) to Energen’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005
 
 
*3(b)
Articles of Amendment to Restated Certificate of Incorporation of Energen, designating Series 1998 Junior Participating Preferred Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energen’s Post Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-00395)
 
 
*3(c)
Bylaws of Energen Corporation (as amended through July 23, 2008) which was filed as Exhibit 99.1 to Energen’s Current Report on Form 8-K, dated July 25, 2008
 
 
*3(d)
Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for the year ended September 30, 1995
 
 
*3(e)
Bylaws of Alabama Gas Corporation (as amended through October 24, 2007) which was filed as Exhibit 3 to Energen’s Quarterly Report on Form 10-Q for the period ended October 31, 2007
 
 
*4(a)
Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September 1, 1996 (the “Energen 1996 Indenture”), and which was filed as Exhibit 4(i) to the Registrant’s Registration Statement on Form S-3 (Registration No. 333-11239)
 
 
*4(a)(i)
Officers’ Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
 
 
*4(a)(ii)
Officers’ Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
 
 
*4(a)(iii)
Amended and Restated Officers’ Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filed as Exhibit 4(d)(iii) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2001
 
 
*4(a)(iv)
Officers’ Certificate, dated August 5, 2011, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 4.65 percent Senior Notes due September 1, 2021, which was filed as Exhibit 4.1 to Energen’s Current Report on Form 8-K, dated August 5, 2011
 
 
*4(b)
Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia, National Association, Trustee, (“Alagasco 1993 Indenture”), which was filed as Exhibit 4(k) to Alabama Gas Corporations’ Registration Statement on Form S-3 (Registration No. 33-70466)
 
 
*4(b)(i)
Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.70 percent Notes due January 15, 2035, which was filed as Exhibit 4.3 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005
 
 
*4(b)(ii)
Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.20 percent Notes due January 15, 2020, which was filed as Exhibit 4.4 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005
 
 

107



*4(b)(iii)
Officers’ Certificate, dated November 17, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.368 percent Notes due December 1, 2015, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed November 17, 2005
 
 
*4(b)(iv)
Officers’ Certificate, dated January 16, 2007, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.90 percent Notes due January 15, 2037, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 16, 2007
 
 
*10(a)
Credit Agreement dated October 30, 2012, by and among Energen Corporation, Energen Resources Corporation, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Wells Fargo Bank, National Association and Regions Bank, and Co-Syndication Agents and L/C Issuers, Compass Bank and U.S. Bank National Association, as Co-Documentation Agents and L/C Issuers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank, Compass Bank and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed October 31, 2012
 
 
*10(b)
Credit Agreement dated December 17, 2013, with respect to a $600 million term loan, by and among Energen Corporation, as Borrower, Energen Resources Corporation, as Guarantor, Bank of America, N.A., as Administrative Agent, Wells Fargo Bank, National Association, Regions Bank, Compass Bank, JPMorgan Chase Bank, N.A. and U.S. Bank National Association, as Co-Syndication Agents, and the lenders party thereto, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed December 19, 2013
 
 
*10(c)
Credit Agreement dated October 30, 2012, by and among Alabama Gas Corporation, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Wells Fargo Bank, National Association and Regions Bank, and Co-Syndication Agents and L/C Issuers, Compass Bank and U.S. Bank National Association, as Co-Documentation Agents and L/C Issuers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank, Compass Bank and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed October 31, 2012
 
 
*10(d)
Note Purchase Agreement, dated December 22, 2011, among Alabama Gas Corporation and the Purchasers thereto (the AIG purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.1 to Alabama Gas Corporation’s Current Report on Form 8-K filed December 22, 2011
 
 
*10(e)
Note Purchase Agreement, dated December 22, 2011, among Alabama Gas Corporation and the Purchasers thereto (the Prudential purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.2 to Alabama Gas Corporation’s Current Report on Form 8-K filed December 22, 2011
 
 
*10(f)
Service Agreement Under Rate Schedule CSS (No. SSNG1), between Southern Natural Gas Company and Alabama Gas Corporation, dated as of September 1, 2005, which was filed as Exhibit 10(a) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
 
 
  10(g)
Amended Exhibit A, effective January 15, 2014, to Service Agreement Under Rate Schedule CSS (No. SSNG1) between Southern Natural Gas Company and Alabama Gas Corporation dated September 1, 2005
 
 
*10(h)
Firm Transportation Service Agreement Under Rate Schedule FT and/or FT-NN (No. FSNG1), between Southern Natural Gas Company and Alabama Gas Corporation dated as of September 1, 2005, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
 
 
  10(i)
Amended Exhibit A, effective October 1, 2013, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation
 
 
  10(j)
Amended Exhibit B, effective November 1, 2013, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation
 
 
*10(k)
Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended September 30, 1993
 
 

108



*10(l)
Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alabama Gas Corporation, dated August 1, 1991 which was filed as Exhibit 3(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2003
 
 
*10(m)
Amendment to Service Agreement between Transcontinental Gas Pipeline Corporation and Alabama Gas Corporation, dated December 2, 2005, which was filed as Exhibit 10(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
 
 
*10(n)
Form of Executive Retirement Supplement Agreement between Energen Corporation and its executive officers (as revised October 2000) which was filed as Exhibit 10(c) to Energen’s Annual Report on Form 10-K for the year ended September 30, 2000
 
 
  10(o)
Form of Amendment to Executive Retirement Supplement Agreement between Energen Corporation and its executive officers, dated December 12, 2007
 
 
*10(p)
Form of Severance Compensation Agreement between Energen Corporation and its executive officers which was filed as Exhibit 10.3 to Energen’s Current Report on Form 8-K filed December 13, 2012
 
 
*10(q)
Energen Corporation Stock Incentive Plan (as amended effective December 11, 2013) which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K filed December 12, 2013
 
 
*10(r)
Form of Stock Option Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(r) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012
 
 
*10(s)
Form of Restricted Stock Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(s) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012
 
 
*10(t)
Form of Restricted Stock Unit Agreement under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed December 12, 2013
 
 
*10(u)
Form of Performance Share Award under the Energen Corporation Stock Incentive Plan which was filed as Exhibit 10(t) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2012
 
 
*10(v)
Energen Corporation 1997 Deferred Compensation Plan (as amended December 12, 2012) which was filed as Exhibit 10(u) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2013
 
 
*10(w)
Energen Corporation Directors Stock Plan (as amended April 28, 2010) which was filed as an attachment to Energen’s definitive Proxy Statement on Schedule 14A , filed March 19, 2010
 
 
*10(x)
Energen Corporation Annual Incentive Compensation Plan, as amended effective January 1, 2013, which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K, filed December 13, 2012
 
 
21
Subsidiaries of Energen Corporation and Alabama Gas Corporation
 
 
23(a)
Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)
 
 
23(b)
Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company, L.P.)
 
 
23(c)
Consent of Independent Oil and Gas Reservoir Engineers (T. Scott Hickman and Associates, Inc.)
 
 
24
Power of Attorney
 
 
31(a)
Energen Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)
 
 
31(b)
Energen Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)

109



 
 
31(c)
Alabama Gas Corporation Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)
 
 
31(d)
Alabama Gas Corporation Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)
 
 
32(a)
Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
 
 
32(b)
Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
 
 
99(a)
Reserve Audit – Ryder Scott & Company, L.P.
 
 
99(b)
Reserve Audit – T. Scott Hickman and Associates, Inc.
 
 
101
The financial statements and notes thereto from Energen Corporation’s Annual Report on Form 10-K for the year ended December 31, 2013 are formatted in XBRL
 
 
*Incorporated by reference

110



SIGNATURE

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

ENERGEN CORPORATION
(Registrant)

ALABAMA GAS CORPORATION
(Registrant)

March 3, 2014
 
By   /s/ J.T. McManus, II      
 
 
J.T. McManus, II
 
 
Chairman, Chief Executive Officer and President of
Energen Corporation; Chairman and Chief Executive
Officer of Alabama Gas Corporation; Director


111



SIGNATURES

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

March 3, 2014
 
By
/s/ J.T. McManus, II
 
 
J.T. McManus, II
Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation; Director
 
 
 
 
March 3, 2014
 
By
/s/ Charles W. Porter, Jr.
 
 
Charles W. Porter, Jr.
Vice President, Chief Financial Officer and
Treasurer of Energen Corporation and Alabama
Gas Corporation
 
 
 
 
March 3, 2014
 
By
/s/ Russell E. Lynch, Jr.
 
 
Russell E. Lynch, Jr.
Vice President and Controller of Energen
Corporation
 
 
 
 
March 3, 2014
 
By
/s/ Leonarda M. DiChiara
 
 
Leonarda M. DiChiara
Vice President and Controller of Alabama Gas
Corporation
 
 
 
 
March 3, 2014
 
*
 
 
Kenneth W. Dewey
Director
 
 
 
 
March 3, 2014
 
*
 
 
Jay Grinney
Director
 
 
 
 
March 3, 2014
 
*
 
 
Frances Powell Hawes
Director
 
 
 
 
March 3, 2014
 
*
 
 
Judy M. Merritt
Director
 
 
 
 
 
 
*By
/s/ Charles W. Porter, Jr.
 
 
Charles W. Porter, Jr.
Attorney-in-Fact


112

Exhibit 10(g)
SOUTHERN NATURAL GAS COMPANY
SERVICE AGREEMENT UNDER RATE SCHEDULE CSS
CONTRACT CODE: SSNG1
EXHIBIT A





TYPE
 

SERVICE
TYPE
CODE
 


MSQ
(Mcf)
 


MDIQ
(Mcf)  (1)
 


MDWQ
(Mcf)  (1)
 


START
DATE
 


PRIMARY
TERM
 

PRIMARY
NOTICE
REQUIRED
 


EVERGREEN
TERM
 
EVERGREEN
NOTICE
REQUIRED
Company' s Mu l d o n Storage Field
located in Monroe County, Mississippi,
and/or the Bear Creek Storage Field
located in Bienville Parish, Louisiana
 
1
 
12,464,074
 
95,878
 
251,679
 
1-Nov-1993
 
31-Aug-2017
 
365 DAYS
 
YEARLY
 
365 DAYS
Total Maximum Storage Quantity (Mcf):
 
12,464,074
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




By:
/s/ Dudley C. Reynolds
By:
/s/ Janice H. Parker
 
 
ALABAMA GAS CORPORATION
 
SOUTHERN NATURAL GAS COMPANY, L.L.C.
 
 
 
 
 
 
 
 
 
 
 
Effective Date: __ _1/15/14_ _____________________
 
 
 
 
Supersedes the previous Exhibit A
 
 
 

(1) Shipper's MDIQ and MDWQ shall be subject to adjustment each day based on the quantity of gas Shipper has in storage pursuant to the ratchet percentages set forth in Rate Schedule CSS.


Exhibit 10(i)
SOUTHERN NATURAL GAS COMPANY
FIRM TRANSPORTATION SERVICE AGREEMENT
CONTRACT CODE FSNG1
EXHIBIT A

SERVICE
 
SERVICE
 
RECEIPT POINTS
 
MDRQ
TYPE
 
TYPE CODE
 
PRINT CODE
 
POINT NAME
 
(MCF)
FT
 
29
 
605500
 
COLUMBIA GULF - SHADYSIDE TO SNG
 
16,129

 
 
 
 
605400
 
SESH-CENTERPOINT TO SNG
 
16,931

 
 
 
 
 
 
TOTAL PKG
 
33,060

 
 
 
 
 
 
 
 
 
FT
 
31
 
605400
 
DUNCANVILLE - ENTERPRISE TO SNG
 
2,057

 
 
 
 
606400
 
SESH - CENTERPOlNT TO SNG
 
2,159

 
 
 
 
 
 
TOTAL PKG
 
4,216

 
 
 
 
 
 
 
 
 
FT
 
42
 
060000
 
ELBA TO SNG
 
30,000

 
 
 
 
 
 
 
 
 
FT
 
50
 
605500
 
COLUMBIA GULF - SHADYSIDE TO SNG
 
12,641

 
 
 
 
606500
 
SESH - GULF SOUTH TO SNG
 
9,646

 
 
 
 
605400
 
DUNCANVILLE - ENTERPRISE TO SNG
 
22,943

 
 
 
 
 
 
TOTAL PKG
 
45,230

 
 
 
 
 
 
 
 
 
FT
 
51
 
605500
 
COLUMBIA GULF - SHADYSIDE TO SNG
 
208

 
 
 
 
606400
 
SESH - CENTERPOINT TO SNG
 
219

 
 
 
 
 
 
 
 
427

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL CONTRACT
 
112,933



By:
/s/ Dudley C. Reynolds
By:
/s/ Janice H. Parker
 
 
ALABAMA GAS CORPORATION
 
SOUTHERN NATURAL GAS COMPANY, L.L.C.
 
 
 
 
 
 
 
 
 
 
 
Effective Date: 10/01/2013
 
 
 
 
Supersedes the previous Exhibit A
 
 
 


The MDDQ for Service Type Code 42 is In effect solely during the period October 1 through May 31 each year of the term. Beginning April 2014, MDDQ of 30,000 will be reduced to 0 for the months of April through October.



Exhibit 10(j)
SOUTHERN NATURAL GAS COMPANY
FIRM TRANSPORTATION SERVICE AGREEMENT
CONTRACT CODE FSNG1
EXHIBIT B
 
 
 
 
PRIMARY
 
EVERGREEN
 
 
 
 
HOURLY
SERVICE
SERVICE
START
PRIMARY
NOTICE
EVERGREEN
NOTICE
DELIVERY POINTS
MDDQ
CONTRACT
FLOW RATE
TYPE
TYPE CODE
DATE
TERM
REQUIRED
TERM
REQUIRED
POINT CODE
POINT NAME
(MCF)/Mo
PRESSURE
ENTITLEMENT
FT
29
1-May-04
31-Aug-17
365 DAYS
YEARLY
365 DAYS
658500
ALA - BIRMINGHAM AREA
17,060

 
 
 
 
 
 
 
 
 
940002
ALA - TUSCALOOSA AREA
15,000

 
 
 
 
 
 
 
 
 
940006
ALA - TALLADEGA AREA
1,000

 
 
 
 
 
 
 
 
 
 
Subtotal
33,060

 
 
 
 
 
 
 
 
 
 
 
 
 
 
FT
31
1-May-04
31-Aug-17
365 DAYS
YEARLY
365 DAYS
940035
ALA - JASPER AREA
4,216

 
 
 
 
 
 
 
 
 
 
 
 
 
 

FT

42

1-0ct-13

31-Aug-17

540 DAYS

YEARLY

365 DAYS

940022

ALA - MONTGOMERY AREA
30,000 Oct. 2013 - Mar. 2014
30,000 Nov. - Mar. thereafter

 
 
 
 
 
 
 
 
 
 
 
 
 
 

FT

50

1-0ct-13

31-Aug-17

365 DAYS

YEARLY

365 DAYS

654700

ALA - GADSDEN AREA

5,405

 
 
 
 
 
 
 
 
 
658500
ALA - BIRMINGHAM AREA
13,729

 
 
 
 
 
 
 
 
 
659700
ALA - ANNISTON AREA
5,921

 
 
 
 
 
 
 
 
 
659900
ALA - DEMOPOLIS AREA
1,091

 
 
 
 
 
 
 
 
 
817400
ALA - BRENT & CENTERVILLE
197

 
 
 
 
 
 
 
 
 
909700
ALA - PHENIX CITY AREA
1,474

 
 
 
 
 
 
 
 
 
940002
ALA - TUSCALOOSA AREA
3,438

 
 
 
 
 
 
 
 
 
940005
ALA - LINCOLN AREA
311

 
 
 
 
 
 
 
 
 
940006
ALA - TALLADEGA AREA
835

 
 
 
 
 
 
 
 
 
940011
ALA - OPELIKA AREA
3,459

 
 
 
 
 
 
 
 
 
940021
ALA - FAIRFAX-SHAWMUT AREA
931

 
 
 
 
 
 
 
 
 
940022
ALA - MONTGOMERY AREA
4,878

 
 
 
 
 
 
 
 
 
940023
ALA - SELMA AREA
1,704

 
 
 
 
 
 
 
 
 
940024
ALA - TUSKEGEE AREA
1,327

 
 
 
 
 
 
 
 
 
940035
ALA - JASPER AREA
178

 
 
 
 
 
 
 
 
 
940046
ALA - REFORM AREA
98

 
 
 
 
 
 
 
 
 
940056
ALA - PELL CITY AREA
254

 
 
 
 
 
 
 
 
 
 
Subtotal
45,230

 
 

Page 1 of 7



FT
51
1-0ct-13
31-Aug-17
365 DAYS
YEARLY
365 DAYS
658500
ALA - BIRMINGHAM AREA
427

 
 
 
 
 
 
 
 
 
 
 
 
 
 
FTNN
52
1-0ct-13
31-Aug-17
365 DAYS
YEARLY
365 DAYS
658500
ALA - BIRMINGHAM AREA
755

 
 
 
 
 
 
 
 
 
 
 
 
 
 
FTNN
53
1-0ct-13
31-Aug-17
365 DAYS
YEARLY
365 DAYS
654700
ALA - GADSDEN AREA
27,595

 
 
 
 
 
 
 
 
 
658500
ALA - BIRMINGHAM AREA
70,096

 
 
 
 
 
 
 
 
 
659700
ALA - ANNISTON AREA
30,229

 
 
 
 
 
 
 
 
 
659900
ALA - DEMOPOLIS AREA
5,573

 
 
 
 
 
 
 
 
 
817400
ALA - BRENT & CENTERVILLE
1,003

 
 
 
 
 
 
 
 
 
834100
ALA - PLANT MILLER
2

 
 
 
 
 
 
 
 
 
909700
ALA - PHENIX CITY AREA
7,526

 
 
 
 
 
 
 
 
 
940002
ALA - TUSCALOOSA AREA
17,554

 
 
 
 
 
 
 
 
 
940005
ALA - LINCOLN AREA
1,589

 
 
 
 
 
 
 
 
 
940006
ALA - TALLADEGA AREA
4,265

 
 
 
 
 
 
 
 
 
940011
ALA - OPELIKA AREA
17,656

 
 
 
 
 
 
 
 
 
940021
ALA - FAIRFAX-SHAWMUT AREA
4,751

 
 
 
 
 
 
 
 
 
940022
ALA - MONTGOMERY AREA
24,904

 
 
 
 
 
 
 
 
 
940023
ALA - SELMA AREA
8,698

 
 
 
 
 
 
 
 
 
940024
ALA - TUSKEGEE AREA
6,776

 
 
 
 
 
 
 
 
 
940035
ALA - JASPER AREA
906

 
 
 
 
 
 
 
 
 
940046
ALA - REFORM AREA
502

 
 
 
 
 
 
 
 
 
940056
ALA - PELL CITY AREA
1,299

 
 
 
 
 
 
 
 
 
 
Subtotal
230,924

1/
 
 
 
 
 
 
 
 
 
 
 
 
 
Current TD under Rate Schedule FT - 112,933
Current TD under Rate Schedule FTNN - 231,679
 
 
 
 
 
 
 
 
 
 
 
 

By:
/s/ Amy W. Stewart
By:
/s/ Janice H. Parker
 
 
ALABAMA GAS CORPORATION
 
SOUTHERN NATURAL GAS COMPANY, L.L.C.
 
 
 
 
 
 
 
 
 
 
 
Effective Date: November 1, 2013
 
 
 
 
Supersedes the previous Exhibit A
 
 
 

1/ The MDDO shall be 150,660 mcf for each of the months of April through September each year. Such reduction was authorized as mitigation in Docket Numbers RS92-10 and/or RP99-496 and is set forth at the delivery point and corresponding receipt point level in SoNet Premier. (Service Type Code 42 is excluded from this provision.)

Page 2 of 7



 
 
Service Agreement No. FSNG1
 
EXHIBIT B
Effective: November 1, 2013
 
 
Supersedes the Previous Exhibit B

SHIPPER: Alabama Gas Corporation
This supplement to Exhibit B details the meter station restrictions, hourly flow rate entitlements and firm contract pressure obligations underlying each Delivery Point MDDQ to this Exhibit B.

 
 
 
 
 
 
 
For Information Purposes Only
 
 
 
 
 
 
 
Meter Station Design Capability
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pressure
 
 
Meter
 
Hourly
Daily
 
 
Max
Max
Used for
Point
Point
Station
MDDQ
Flow Rate
Delivery
Contract
Line Pressure
Delivery
Hourly
Station
Name
Code
Code
(Mcf)/Mo.
Entitlement
Capacity
Pressure
Information
Capability
Capability
Capability
Gadsden Area
654700
 
33,000

1,980

 
 
 
 
 
 
Ragland
 
841200
 
 
333

50
 
700

29

50

Ashville
 
841400
 
 
714

Line
>100#
47,000

1,958

430

Gadsden 5
 
841900
 
 
683

195
 
1,500

63

190

Gadsden 1
 
842200
 
 
19,616

145
 
110,000

4,583

145

Gadsden 2
 
842300
 
 
3,502

145
 
10,000

417

145

Gadsden 3
 
842400
 
 
3,162

Line
>150#
18,200

758

250

Gadsden 4
 
843000
 
 
3,131

145
 
15,950

665

470

Gadsden 6
 
843600
 
 
1,859

150
 
3,244

135

140

 
 
 
 
 
 
 
 
 
 
 
Birmingham Area
658500
 
102,067

6,124

 
 
 
 
 
 
Oak Grove
 
821200
 
 
290

100
 
1,200

50

100

Forestdale
 
821800
 
 
1,472

150
 
4,000

167

250

North B'ham
 
822600
 
 
13,868

Line
200# - 300#
126,675

5,278

350

Tarrant
 
822800
 
 
2,467

Line
>150#
37,000

1,542

320

Roebuck
 
825700
 
 
19,487

Line
>425#
125,233

5,218

475

Leeds #1
 
826400
 
 
2,228

75
 
7,400

308

75

Leeds #2
 
826500
 
 
2,974

300
 
14,000

583

300

Lehigh Portland
 
826700
 
 

Line
 
13,400

558

100

Pleasant Grove
 
828600
 
 
6,405

Line
>575#
34,000

1,417

575


Page 3 of 7



 
 
 
 
 
 
 
For Information Purposes Only
 
 
 
 
 
 
 
Meter Station Design Capability
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pressure
 
 
Meter
 
Hourly
Daily
 
 
Max
Max
Used for
Point
Point
Station
MDDQ
Flow Rate
Delivery
Contract
Line Pressure
Delivery
Hourly
Station
Name
Code
Code
(Mcf)/Mo.
Entitlement
Capacity
Pressure
Information
Capability
Capability
Capability
Bessemer #1
 
829200
 
 
5,560

Line
>560#
38,300

1,596

560

Bessemer #2
 
829300
 
 
3,453

Line
>485#
39,000

1,625

485

Genery Gap
 
830400
 
 
15,669

Line
>370#
97,500

4,063

500

Helena-Alagas
 
830900
 
 
3,767

Line
>325#
18,300

763

340

Helena #2
 
831000
 
 

Line
>325#
25,800

1,075

325

Alabaster #1
 
831400
 
 
879

Line
>335#
8,800

367

340

Alabaster #2
 
831500
 
 
975

Line
>340#
3,800

158

340

Alabaster #3
 
831600
 
 
618

Line
>330#
11,090

462

330

Columbiana
 
832600
 
 
1,184

100
 
3,700

154

140

Montevallo
 
833400
 
 
1,660

Line
>150#
8,756

365

340

Ensley
 
837400
 
 
6,902

Line
>150#
67,300

2,804

315

Barrett Co
 
838100
 
 
396

50
 
720

30

150

Bullock
 
838300
 
 
162

50
 
720

30

150

Harbison Walker
 
838700
 
 
697

200
 
3,120

130

174

Fairfield
 
839200
 
 
10,954

Line
>175#
48,900

2,038

315

 
 
 
 
 
 
 
 
 
 
 
Anniston Area
659700
 
36,150

2,169

 
 
 
 
 
 
Anniston #1
 
845600
 
 
12,081

110
 
42,800

1,783

100

Anniston #2
 
845700
 
 
4,776

150
 
50,500

2,104

120

Anniston #3
 
845800
 
 
17,671

250
 
55,500

2,313

250

Heflin
 
847000
 
 
1,031

55
 
1,600

67

55

Chocoloco
 
848100
 
 
591

Line
 
11,600

483

400

 
 
 
 
 
 
 
 
 
 
 
Demopolis Area
659900
 
6,664

400

 
 
 
 
 
 
Demopolis #1
 
801400
 
 
727

60
 
3,400

142

60

Demopolis #2
 
801500
 
 
2,001

75
 
3,900

163

75

Greensboro
 
802400
 
 
1,534

200
 
2,900

121

200


Page 4 of 7



 
 
 
 
 
 
 
For Information Purposes Only
 
 
 
 
 
 
 
Meter Station Design Capability
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pressure
 
 
Meter
 
Hourly
Daily
 
 
Max
Max
Used for
Point
Point
Station
MDDQ
Flow Rate
Delivery
Contract
Line Pressure
Delivery
Hourly
Station
Name
Code
Code
(Mcf)/Mo.
Entitlement
Capacity
Pressure
Information
Capability
Capability
Capability
Uniontown
 
802600
 
 
700

125
 
1,900

79

125

Marion
 
803400
 
 
1,702

165
 
3,000

125

165

 
 
 
 
 
 
 
 
 
 
 
Selma Area
940023
 
10,402

624

 
 
 
 
 
 
Selma #1
 
803700
 
 
575

275
 
28,800

1,200

245

Selma #2
 
803800
 
 
9,827

600
 
34,400

1,433

600

 
 
 
 
 
 
 
 
 
 
 
Phenix City Area
909700
 
9,000

540

 
 
 
 
 
 
Phenix City #1
 
810600
 
 
4,565

Line
<175#
22,400

933

175

Phenix City #2
 
810700
 
 
2,726

200
 
7,000

292

200

Phenix City #3
 
810800
 
 
1,709

Line
<200#
10,800

450

175

 
 
 
 
 
 
 
 
 
 
 
Tuscaloosa Area
940002
 
35,992

2,160

 
 
 
 
 
 
Tuscaloosa #1
 
816400
 
 
14,184

Line
250# - 400#
141,300

5,888

340

Tuscaloosa #2
 
816500
 
 
15,503

Line
>300#
29,200

1,217

440

Tuscaloosa #3
 
816600
 
 
6,305

125
 
12,527

522

175

 
 
 
 
 
 
 
 
 
 
 
Lincoln Area
940005
 
1,900

114

 
 
 
 
 
 
Vincent
 
827800
 
 
905

200
 
1,500

63

200

Lincoln #2
 
828200
 
 
615

250
 
1,343

56

250

Riverside East
 
844800
 
 
100

100
 
300

13

180

Lincoln #1
 
845000
 
 
280

48
 
1,000

42

48

 
 
 
 
 
 
 
 
 
 
 
Talladega Area
940006
 
6,100

366

 
 
 
 
 
 
Talladega Raceway
 
845400
 
 
313

200
 
6,288

262

55

Talladega #1
 
847600
 
 
3,461

50
 
20,000

833

50

Talladega #2
 
847700
 
 
2,326

148
 
14,000

583

145


Page 5 of 7



 
 
 
 
 
 
 
For Information Purposes Only
 
 
 
 
 
 
 
Meter Station Design Capability
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pressure
 
 
Meter
 
Hourly
Daily
 
 
Max
Max
Used for
Point
Point
Station
MDDQ
Flow Rate
Delivery
Contract
Line Pressure
Delivery
Hourly
Station
Name
Code
Code
(Mcf)/Mo.
Entitlement
Capacity
Pressure
Information
Capability
Capability
Capability
Opelika Area
940011
 
21,115

1,267

 
 
 
 
 
 
Lochapoka
 
809500
 
 
1,197

Line
 
14,640

610

500

Auburn
 
812600
 
 
8,704

125
 
10,872

453

250

Opelika #1
 
813400
 
 
5,132

Line
<600#
15,000

625

525

Opelika #2
 
813500
 
 
387

Line
<600#
17,136

714

575

Opelika #3
 
813600
 
 
5,695

Line
 
48,500

2,021

1,000

 
 
 
 
 
 
 
 
 
 
 
Fairfax/Shaw Area
940021
 
5,682

341

 
 
 
 
 
 
Fairfax Mills-WP
 
814400
 
 
83

Line
 
3,384

141

47

Fairfax City
 
814500
 
 
1,934

100
 
3,700

154

100

Shawmut- Lang
 
815200
 
 
2,583

Line
< 600#
17,400

725

400

LaFayette
 
814200
 
 
1,082

150
 
3,400

142

150

 
 
 
 
 
 
 
 
 
 
 
Montgomery Area
940022
 
59,782

3,587

 
 
 
 
 
 
Montgomery #2
 
805100
 
 
3,325

600
 
62,250

2,594

575

Montgomery #3
 
805200
 
 
1,015

175
 
10,400

433

240

Montgomery #4
 
805300
 
 
8,341

Line
 
83,340

3,473

850

Montgomery #5
 
805400
 
 
15,000

700 to 720
 
93,100

3,879

700

Montgomery #6
 
805500
 
 
31,595

700 to 720
 
120,700

5,029

700

Russell Mills
 
806000
 
 
261

Line
 
10,200

425

450

Eclectic
 
806800
 
 
245

100
 
2,500

104

430

 
 
 
 
 
 
 
 
 
 
 
Tuskegee Area
940024
 
8,103

486

 
 
 
 
 
 
Tuskegee #1
 
808800
 
 
6,466

100
 
12,200

508

100

Tuskegee #2
 
808900
 
 
1,314

Line
 
18,000

750

500

Notasulga
 
809400
 
 
323

175
 
700

29

145

 
 
 
 
 
 
 
 
 
 
 

Page 6 of 7



 
 
 
 
 
 
 
For Information Purposes Only
 
 
 
 
 
 
 
Meter Station Design Capability
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pressure
 
 
Meter
 
Hourly
Daily
 
 
Max
Max
Used for
Point
Point
Station
MDDQ
Flow Rate
Delivery
Contract
Line Pressure
Delivery
Hourly
Station
Name
Code
Code
(Mcf)/Mo.
Entitlement
Capacity
Pressure
Information
Capability
Capability
Capability
Jasper
940035
 
5,300

318

 
 
 
 
 
 
Jasper #1
 
835600
 
 
4,627

150
 
22,800

950

150

Parrish Oak
 
836201
 
 
673

144
 
1,700

71

144

 
 
 
 
 
 
 
 
 
 
 
Pell City Area
940056
 
1,553

93

 
 
 
 
 
 
Eden
 
827200
 
 
250

75
 
700

29

75

Pell City
 
827400
 
 
742

70
 
1,600

67

200

Oak Ridge
 
827600
 
 
561

70
 
900

38

70

 
 
 
 
 
 
 
 
 
 
 
Reform Area
940046
 
600

36

 
 
 
 
 
 
Reform
 
818800
 
 
590

48
 
1,000

42

48

Reform #2
 
819400
 
 
10

150
 
700

29

150

 
 
 
 
 
 
 
 
 
 
 
Brent/Centerville
817400
 
1,200

72

1,200

200
 
3,576

149

200

Plant Miller
834100
 
2


2

115
 
41,640

1,735

140

Farm Taps
847900
 


 
Line
 
NA

NA

NA

 
 
 
 
 
 
 
 
 
 
 
GRAND TOTAL:
 
 
344,612

20,677

344,612

 
 
 
 
 


Page 7 of 7

Exhibit 10(o)
AMENDMENT TO
EXECUTIVE RETIREMENT SUPPLEMENT AGREEMENT
(409A Amendment)

THIS AMENDMENT is made and entered into as of the date set forth below, by and between Energen Corporation, an Alabama corporation (the “Company”), and the Executive identified below (the “Executive”).

Date:     December 12, 2007

Executive: ________________________

R E C I T A L S

The Company and the Executive have previously entered into an Executive Retirement Supplement Agreement (the “SERP”) dated as of ________________, ______. The Company and the Executive desire to enter into this Amendment to the SERP to provide for payments in accordance with Section 409A of the Code with respect to benefits accrued under the SERP after December 31, 2004.

NOW, THEREFORE, pursuant to Section 3.3 of the SERP, the Company and the Executive do hereby agree to amend the SERP as follows:

FIRST : Section 2.5(a) of the SERP is hereby amended by adding thereto, at the end thereof, the following:

Notwithstanding the foregoing, with respect to any distribution that is subject to the provisions of Section 409A(a)(2)(B)(i) of the Code, such distribution shall be made as hereinafter provided. First, the Committee shall determine the Supplemental Retirement Benefit of the Executive as if the Executive had Retired on December 31, 2004 (the “Preliminary Grandfathered Benefit”). Second, the Committee shall determine the Supplemental Retirement Benefit of the Executive as of the Executive’s actual Retirement date. Third, the Committee shall determine the lump sum value of the Preliminary Grandfathered Benefit based on the Executive’s attained age as of December 31, 2004 and the factors that would have been used to calculate Present Value hereunder as of December 31, 2004. Fourth, the lump sum value determined pursuant to the preceding sentence shall be increased to reflect the number of months from December 31, 2004 to the date of payment of the lump sum and to reflect interest accretion and survivorship based on the factors used in the preceding sentence (the “Final Grandfathered Benefit”). Fifth, the Committee shall determine the lump sum that would have been paid pursuant to this Section 2.5(a) without regard to the provision of Section 409A

1



of the Code (the “Total Benefit”). Sixth, the lump sum benefit to be paid as promptly as practicable following the Executive’s Severance Date shall be the lesser of the Final Grandfathered Benefit or the Total Benefit. In the event that the Total Benefit exceeds the Final Grandfathered Benefit, an additional benefit shall be paid as promptly as practicable after the date that is six (6) months following the Executive’s Severance Date. Such additional payment shall be equal to the excess of the Total Benefit over the Final Grandfathered Benefit increased to reflect six (6) months interest at the interest rate used to determine the initial payment made following the Executive’s Severance Date.

SECOND : Section 2.5(b) of the SERP is hereby amended to read as follows:

By executing and filing with the Company a form substantially identical to Exhibit I hereof, or such other form as the Company may prescribe or approve, the Executive may revoke an election made pursuant to paragraph (a) above with respect to the Preliminary Grandfathered Benefits or may make any election which could be made pursuant to such paragraph with respect to the Preliminary Grandfathered Benefits but any such election or revocation of an election shall not become effective if the Executive’s Severance Date occurs within one year from the date such revocation or election is made. Except for an election or revocation of an election provided for in this paragraph (b) with respect to a Participant’s Preliminary Grandfathered Benefits, no changes may be made to an election made pursuant to paragraph (a) above.

THIRD : The SERP as hereby amended shall remain in full force and effect.

FOURTH : This Amendment shall be effective as of December 12, 2007.

IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by its duly authorized officer and the Executive has hereunto set his hand and seal all as of the day and year first above written.

ENERGEN CORPORATION


By:    ______________________________
Its:     President and Chief Executive Officer

EXECUTIVE


______________________________

1


Exhibit 21

SUBSIDIARIES OF ENERGEN CORPORATION


Alabama Gas Corporation*
Energen Resources Corporation*
    



* Incorporated in the State of Alabama



Exhibit 23(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-177815) and Forms S-8 (File No. 33-46641, File No. 333-104726, File No. 33-48505, File No. 333-59804, File No. 333-26111, File No. 333-45107, File No. 333-84170 and File No. 333-178794) of Energen Corporation of our report dated March 3, 2014 relating to the consolidated financial statements, financial statement schedule, and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
Birmingham, Alabama
March 3, 2014





Exhibit 23(b)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2013 which appears in this Form 10-K and the inclusion of our report dated February 12, 2014, which appears as an Exhibit to this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-177815) and Forms S-8 (File No. 33-46641, File No. 333-104726, File No. 33-48505, File No. 333-59804, File No. 333-26111, File No. 333-45107, File No. 333-84170 and File No. 333-178794) of Energen Corporation to the reference to our firm name and our audit of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2013 which appears in this Form 10-K and our report dated February 12, 2014, which appears as an Exhibit to this Form 10-K.
/s/ Ryder Scott Company, L.P.
Houston, Texas
February 28, 2014





Exhibit 23(c)

CONSENT

We hereby consent to the reference to our firm name and our audit of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2013 which appears in this Form 10-K and the inclusion of our report dated February 17, 2014, which appears as an Exhibit to this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File No. 333-177815) and Forms S-8 (File No. 33-46641, File No. 333-104726, File No. 33-48505, File No. 333-59804, File No. 333-26111, File No. 333-45107, File No. 333-84170 and File No. 333-178794) of Energen Corporation to the reference to our firm name and our audit of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2013 which appears in this Form 10-K and our report dated February 17, 2014, which appears as an Exhibit to this Form 10-K.
/s/ T. Scott Hickman & Associates, Inc.
Midland, Texas
February 28, 2014




Exhibit 24

POWER OF ATTORNEY
ENERGEN CORPORATION
ALABAMA GAS CORPORATION

Each of the undersigned directors of Energen Corporation, an Alabama corporation, and Alabama Gas Corporation, an Alabama corporation, hereby nominates, constitutes and appoints James T. McManus, II, and Charles W. Porter, Jr., and each of them, the true and lawful attorneys of the undersigned to sign the name of the undersigned as director to the Annual Reports on Form 10-K for the year ended December 31, 2013 of each of said corporations, in such form as they or any one of them may approve, and to file the same with all exhibits thereto and other documents in connection therewith with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, and to any and all amendments to said reports.
    
The undersigned hereby grants to said attorneys full power and authority to do and perform each and every act and thing requisite and necessary to be done so that such Annual Reports shall comply with the Securities Exchange Act of 1934, as amended, and the applicable rules and regulations adopted pursuant thereto, and further grants full power of substitution, resubstitution and revocation, all as fully as the undersigned could do if personally present, hereby ratifying all that said attorneys or their substitutes may lawfully do by virtue hereof.

IN WITNESS WHEREOF, the undersigned directors of Energen Corporation and Alabama Gas Corporation have executed this Power of Attorney as of the 22 rd day of January, 2014.                            

/s/ Kenneth W. Dewey        
Kenneth W. Dewey

/s/ T. Michael Goodrich        
T. Michael Goodrich

/s/ M. James Gorrie        
M. James Gorrie

/ s/ Jay Grinney            
Jay Grinney

/ s/ Frances Powell Hawes    
Frances Powell Hawes

/s/ Judy M. Merritt        
Judy M. Merritt

/s/ Stephen A. Snider        
Stephen A. Snider

/s/ Gary C. Youngblood        
Gary C. Youngblood



Exhibit 31(a)
CERTIFICATION
I, James T. McManus, II, certify that:
1.
I have reviewed this report on Form 10-K of Energen Corporation;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):
a)
All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


March 3, 2014
 
By
/s/ J. T. McManus, II
 
 
 
J. T. McManus, II Chairman and Chief Executive Officer of Energen Corporation






Exhibit 31(b)
CERTIFICATION
I, Charles W. Porter, Jr., certify that:
1.
I have reviewed this report on Form 10-K of Energen Corporation;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):
a)
All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


March 3, 2014
 
By
/s/ Charles W. Porter, Jr.
 
 
 
Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer
of Energen Corporation






Exhibit 31(c)
CERTIFICATION
I, James T. McManus, II, certify that:
1.
I have reviewed this report on Form 10-K of Alabama Gas Corporation;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):
a)
All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


March 3, 2014
 
By
/s/ J. T. McManus, II
 
 
 
J. T. McManus, II Chairman and Chief Executive Officer of Alabama Gas Corporation






Exhibit 31(d)
CERTIFICATION
I, Charles W. Porter, Jr., certify that:
1.
I have reviewed this report on Form 10-K of Alabama Gas Corporation;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):
a)
All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


March 3, 2014
 
By
/s/ Charles W. Porter, Jr.
 
 
 
Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer
of Alabama Gas Corporation






Exhibit 32(a)
CERTIFICATION PURSUANT TO
18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Energen Corporation (the “Registrant”) on Form 10-K for the period ended December 31, 2013 , as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of March 3, 2014

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

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





Exhibit 32(b)
CERTIFICATION PURSUANT TO
18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Alabama Gas Corporation (the “Registrant”) on Form 10-K for the period ended December 31, 2013 , as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of March 3, 2014

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

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




Exhibit 99(a)





ENERGEN RESOURCES CORPORATION





Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests





SEC Parameters





As of

December 31, 2013




\s\ Joseph E. Blankenship
Joseph E. Blankenship, P.E.
TBPE License No. 62093
Senior Vice President
[SEAL]
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580


RYDER SCOTT COMPANY PETROLEUM CONSULTANTS




TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849
1100 LOUISIANA STREET SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

February 12, 2014



Energen Resources Corporation
605 Richard Arrington, Jr. Boulevard North
Birmingham, AL 35203-2707

Attention: Mr. Henry E. Cash, Manager – Acquisitions & Engineering

Gentlemen:

At the request of Energen Resources Corporation (Energen), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2013 prepared by Energen’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on February 4, 2014 and presented herein, was prepared for public disclosure by Energen in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Energen’s estimated net reserves attributable to the leasehold and royalty interests in certain properties owned by Energen and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2013. The properties reviewed by Ryder Scott incorporate 4769 reserve determinations and are located in the states of Colorado, New Mexico and Texas.

The properties reviewed by Ryder Scott account for a portion of Energen’s total net proved reserves as of December 31, 2013. Based on the estimates of total net proved reserves prepared by Energen, the reserves audit conducted by Ryder Scott addresses the percentages shown below.

Percent of Energen’s Total Net Proved Reserves
Audited by Ryder Scott

Reserve Class and Category
 
Percent of Liquid Hydrocarbons
 
Percent of Gas
 
Percent of
Oil Equivalent
 
 
 
 
 
 
 
Total Proved
 
94
 
72
 
86
Proved Developed
 
90
 
68
 
81
Proved Undeveloped
 
100
 
100
 
100


As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

Based on our review, including the data, technical processes and interpretations presented by Energen, it is our opinion that the overall procedures and methodologies utilized by Energen in preparing

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790
621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501    TEL (303) 623-9147    FAX (303) 623-4258


their estimates of the proved reserves as of December 31, 2013 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Energen are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. Energen has informed us that in the preparation of their reserve and income projections, as of December 31, 2013, they used average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Energen attributable to Energen's interest in properties that we reviewed are summarized as follows:

SEC PARAMETERS
Estimated Net Reserves
Certain Leasehold and Royalty Interests of
Energen Resources Corporation
As of December 31, 2013

 
 
Proved
 
 
Developed
 
 
 
Total
 
 
Producing
 
Non-Producing
 
Undeveloped
 
Proved
Net Reserves of Properties
Audited by Ryder Scott
 
 
 
 
 
 
 
 
Oil/Condensate - Barrels
 
104,949,529
 
7,071,760
 
51,061,131
 
163,082,420
Plant Products - Barrels
 
27,426,697
 
1,528,425
 
20,920,285
 
49,875,407
Gas – MMCF
 
413,798
 
7,683
 
96,402
 
517,883
Total Equivalent Oil - BOE
 
201,342,559
 
9,880,685
 
88,048,416
 
299,271,660


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

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Energen’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward”. The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

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

Audit Data, Methodology, Procedure and Assumptions

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

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 95 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through October 2013, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Energen or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 5 percent of the proved producing reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 100 percent of the proved developed non-producing and undeveloped reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Energen for our review or which we have obtained from public data sources that were available through October 2013. The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.

Energen’s reserves included in this audit were in conventional formations in the Permian Basin and coal seams in the San Juan Basin. Many of Energen’s properties in the Permian Basin are producing under secondary and enhanced recovery techniques. Some of Energen’s reserves will be produced through horizontal wellbores; examples would include many of their wells in the San Juan Basin, Carracas and Tiffany Areas, producing from the Fruitland Coal.

To estimate economically recoverable proved oil and gas reserves we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Energen relating to hydrocarbon prices and costs as noted herein.


RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


The hydrocarbon prices furnished by Energen for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2013 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Energen for the geographic area reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

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

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

Geographic Area
Product
Price
Reference
Average
Benchmark
Prices
Average Realized
Prices
North America
 
 
 
 
United States
Oil/Condensate
WTI Cushing
$96.94/Bbl
$92.26/Bbl
NGLs
WTI Cushing
$96.94/Bbl
$30.22/Bbl
Gas
Henry Hub
$3.67/MMBTU
$3.35/MCF
Colorado Interstate
$3.53/MMBTU


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

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by Energen are based on the operating expense reports of Energen and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


overhead costs that are allocated directly to the leases and wells under terms of operating agreements . The operating costs furnished by Energen were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Energen. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Energen are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Energen were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Energen. The estimated net cost of abandonment after salvage was included by Energen for properties where abandonment costs net of salvage were significant. Energen’s estimates of the net abandonment costs were accepted without independent verification.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Energen’s plans to develop these reserves as of December 31, 2013. The implementation of Energen’s development plans as presented to us is subject to the approval process adopted by Energen’s management. As the result of our inquiries during the course of our review, Energen has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Energen’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Energen. Additionally, Energen has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans. All of Energen’s proved undeveloped reserves are scheduled to be developed within five years from the initial disclosure in an SEC filing.

Current costs used by Energen were held constant throughout the life of the properties.
Energen’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend had been established, future production rates were held constant, or inclined during the dewatering phase for coal seam gas, as appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend had been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Energen to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Energen. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Energen’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Energen’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Energen owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Energen for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Energen are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Energen has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Energen’s forecast of future proved production, we have relied upon data furnished by Energen with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Energen. The data described herein were accepted as authentic and sufficient for determining the reserves unless, during the course of our examination, a matter of question came to our attention in which case the data were not accepted until all questions were satisfactorily resolved. We consider the factual data furnished to us by Energen to be appropriate and sufficient for the purpose of our review of Energen’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Energen and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Energen, it is our opinion that the overall procedures and methodologies utilized by Energen in preparing their estimates of the proved reserves as of December 31, 2013 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Energen are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

We were in reasonable agreement with Energen's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Energen's estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Energen when its reserve estimates were prepared. However notwithstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Energen.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


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

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

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

We are independent petroleum engineers with respect to Energen. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Energen.

Energen Resources Corporation is a wholly owned subsidiary of Energen Corporation. Energen Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Energen Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Energen Corporation of the references to our name as well as to the references to our third party report for Energen Corporation, which appears in the December 31, 2013 annual report on Form 10-K of Energen Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Energen Corporation.

We have provided Energen with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Energen and the original signed report letter, the original signed report letter shall control and supersede the digital version.







RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580


\s\ Joseph E. Blankenship


Joseph E. Blankenship, P.E.
TBPE License No. 62093
Senior Vice President
[SEAL]
JEB (DCR)/pl



RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



Professional Qualifications of Primary Technical Person

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

Mr. Blankenship, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1982, is a Senior Vice President and also serves as Chief Technical Advisor for unconventional reserves evaluation. Mr. Blankenship is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Blankenship served in a number of engineering positions with Exxon Company USA. For more information regarding Mr. Blankenship’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Blankenship earned a Bachelor of Science degree in Mechanical Engineering from the University of Alabama in 1977. He is a member of the Honorary Engineering Society Pi Tau Sigma and is a licensed Professional Engineer in the State of Texas. He attended Exxon schools on Reservoir Engineering, Well Log Analysis, Economic Evaluation, Oil and Gas Facility Design, and Offshore Platform Design. He is also a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE). He has served as Chairman of the SPE Newsletter Committee and has been invited by the SPEE to lecture on the subject of Coal Seam evaluation.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Blankenship fulfills. Mr. Blankenship’s continuing education in 2013 included training on Booking of Enhanced Oil Recovery (EOR) Reserves, Formation Fracturing Statistics, SEC Reserves Disclosures, Analysis of Shale Reserves, and Reserves Reconciliation. Mr. Blankenship also served as instructor in two courses on Unconventional Resource Evaluation.

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

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

Based on his educational background, professional training and more than 36 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Blankenship has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.


RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)


PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.


RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).


PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


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

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

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

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


PROBABLE RESERVES (SEC DEFINITIONS)

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

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

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

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

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

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

POSSIBLE RESERVES (SEC DEFINITIONS)

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

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


RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

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

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

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

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

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





RYDER SCOTT COMPANY PETROLEUM CONSULTANTS



PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)


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


DEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

Developed Producing (SPE-PRMS Definitions)

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

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

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS


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

Shut-In
Shut-in Reserves are expected to be recovered from:
(1)
completion intervals which are open at the time of the estimate, but which have not started producing;
(2)
wells which were shut-in for market conditions or pipeline connections; or
(3)
wells not capable of production for mechanical reasons.

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

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


UNDEVELOPED RESERVES (SEC DEFINITIONS)

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

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

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

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

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



RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Exhibit 99(b)

February 17, 2014

Energen Resources Corp.
605 Richard Arrington Jr Boulevard North
Birmingham, AL 35203-2707

Attention Mr. Henry E. Cash

Gentlemen:
Re:     Reserve Audit
San Juan Basin, New Mexico (Conventional)

In accordance with your request, T. Scott Hickman & Associates, Inc. (TSH&A) has performed an audit of the Proved oil and gas reserves estimated by Energen Resources Corp. (ERC) from conventional formations for certain properties located in the San Juan Basin of New Mexico (herein referred to as “Subject Area”) in accordance with guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our audit was completed February 17, 2014.
A reserve audit is the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves and/or reserves information prepared by others and the rendering of an opinion about the methodologies, data and thoroughness of the process that was used, the reserve classification that was assigned and the reserve quantities that were estimated. This letter presents the results of our third party reserve audit based on the guidelines set forth under Section 229.1202(a)(7) and (8) of the SEC regulations. The estimated reserves shown in the following table represent ERC’s estimated net Proved reserves attributable to the leasehold interests in certain properties owned by ERC as of December 31, 2013.


 
ERC Net "Subject Area" Audited Reserves
 
 
 
 
 
 
Oil, MBBL
Gas, MMCF
NGL, MBL
Liquid Eq MBOE
Effective Date
December 31, 2013
 
 
 
 
 
Proved Developed
 
 
 
 
Producing
886.5

160,445.0

12,182.9

39,810.3

Nonproducing
2.3

2,152.0

160.8

521.8

Behind Pipe

3,378.5

281.4

844.5

TOTAL PROVED
888.8

165,975.5

12,625.2

41,176.6

 
 
 
 
 





The total proved reserves for the “Subject Areas” audited by Hickman represent approximately 11.8% of ERC’s total proved reserves expressed in MBOE. The liquid reserves include crude oil, condensate and natural gas liquids expressed in standard 42 gallon barrels. Gas volumes are expressed in millions of standard cubic feet (MMCF) at contract temperature and pressure bases. Gas reserves are converted to oil equivalent using a factor of 6 mcf per barrel.
Proved oil and gas reserves are those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. Reserve estimations are based on industry-accepted principles of engineering and evaluation that are predicated on established scientific concepts. However, the application of such principles involves extensive judgment and assumptions and is subject to changes in performance data, existing technical knowledge,economic conditions and/or regulatory provisions. Consequently, reserve estimates are inherently uncertain and will normally require some revisions in the future, particularly on new wells with little production history and for reserve categories other than Proved Developed Producing. ERC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
Since reserves have to be economically recoverable, it is necessary to determine the producing rate below which producing operations are no longer profitable (economic limit). Determining the economic limit requires the application of oil and gas prices and operating cost data. The SEC regulations require the use of a constant price that is the unweighted arithmetic average of the first-day-of-the-month price for the twelve months prior to the reporting date, except where the price is based on a contractual arrangement. The product prices which were actually used by ERC to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering fees, and transportation fees referred to herein as “differentials.” The differentials used by ERC were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by ERC.
The table below summarizes ERC’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as ERC’s “average realized prices.” The average realized prices shown in the table below were determined from ERC’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and ERC’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us
Geographic Area
Product
Price Reference
Benchmark Prices
Average Realized
Prices
Subject Area:
 
 
 
 
 
Oil/Condensate
WTI Cushing
$96.94/Bbl
$87.65/Bbl
 
NGLs
Mt. Belvieu
$0.76/Gal
$0.75/Gal
 
Gas
Henry Hub
$3.67/MMBTU
$4.19/MCF

The lease./well operating costs used by ERC were the monthly averages for the most recent twelve month available prior to the reporting date. The operating costs included only expenses directly applicable to the lease/well plus general and administrative costs that were appropriate to allocate back to the lease/well. We spot checked operating costs to satisfy ourselves that they were reasonable. In the economic calculations operating costs were held constant unless some scheduled change in operations dictated a change.
Because of the inherent uncertainties in determining reserve quantities, the reserves presented in this report are estimates only and should not be construed as exact quantities. The actual volumes of oil and gas recovered could be more or less than the estimated reserves. The reserves reviewed in this audit are to be produced under primary recovery from conventional formations within the Subject Area. Our audit covered 42.7% of ERC’s net Proved oil, NGL and gas reserves in the San Juan Basin.
We have accepted without independent verification the accuracy and completeness of the historical production and other data furnished by ERC with respect to ownership interest, oil and gas prices, historical costs of operation and development, and any agreements relating to current and future operations of the properties and sales of production. If, however, in the course of our audit something came to our attention which called into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto.



TSH&A has used all methods and procedures necessary to prepare this report including a detailed review of major properties constituting approximately 70% of the total Proved Developed Producing conventional reserves estimated by ERC in the Subject Area as of December 31, 2013. A review of the Proved Developed Nonproducing and Proved Developed Behind Pipe reserves was also conducted. All of the files and records for the leases/wells in the Subject Area were available for our use. Performance and available plant accounting data were initially available through July 2013 at the start of our audit. Specific leases/wells performance data were updated as our review progressed.
In general the reserves we reviewed were estimated by decline curve analysis whereby historical performance data (producing rates and pressures) are extrapolated when such data were deemed to be definitive. When performance data was not definitive or little or no performance history was available, reserve estimate were based on analogous well performance and occasionally by volumetric methods. Nonproducing reserve estimates were based on analogy and volumetrics.
We are qualified to perform engineering evaluations and audits, but do not claim any expertise in accounting or legal matters. As is customary in the profession, no field inspection was made of the properties nor have we verified that all operations are in compliance with state and/or federal conservation, pricing and environmental regulations that may apply. No consideration was given to potential environmental liabilities that may exist. It is our understanding that ERC’s estimates of reserves do not include adjustments for settlement of any potential gas volume and value imbalances which may have resulted from over- or under-production to ERC’s interest. We have not attempted to identify any interest revisions that might exist.
TSH&A is satisfied that the assumptions, methods, data and procedures utilized by ERC in the preparation of the reserve estimates are appropriate and that ERC’s reserve classifications conform to the SEC reserve definitions contained in 210.4-10(a).
In the aggregate the overall proved reserves estimated by ERC in the Subject Area are reasonable and within the audit tolerance of 10 percent as set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (SPE audit guidelines). Therefore it is our opinion that reserves set forth in this report fairly reflect the estimated net Proven reserves owned by the ERC in the Subject Area.

TSH&A has been providing reserve estimation and evaluation services to industry and investment community for over 40 years. All of the Company’s engineers are qualified by education, training and experience as Reserves Estimators and Reserves Auditors under the SPE audit guidelines. Each Engineer has at least 25 years of experience as a reserve evaluator. They are all registered engineers and complete a minimum of 15 hours of continuing education annually.
We are independent petroleum engineers with respect to ERC as provided in the SPE audit guidelines. We do not own an interest in any of the audited properties and are not employed on a contingency basis.
ERC is a wholly owned subsidiary of Energen Corporation. Energen Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Energen Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Energen Corporation, which appears in the December 31, 2013 annual report on Form 10-K of Energen Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Energen Corporation.
Yours very truly,
T. SCOTT HICKMAN & ASSOCIATES, INC.
/s/ J. Louis Moseley
J. Louis Moseley, P.E.