10-K 1 d10k.htm FORM 10-K Form 10-K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 

 

FORM 10-K

 

 

 

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2007

 

¨

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
Energen Corporation Preferred Stock Purchase Rights   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 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 29, 2007:

 

Energen Corporation

   $3,886,440,012   

Indicate number of shares outstanding of each of the registrant’s classes of common stock as of February 5, 2008:

 

Energen Corporation

   71,681,985 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 24, 2008 (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.

Call Option

  

A contract that gives the investor the right, but not the obligation, to buy the underlying commodity at a certain price on an agreed upon date.

Carried Interest

  

An agreement under which one party agrees to pay for a specified portion or for all of the development and operating costs of another party on a property in which both own a portion of the working interest.

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 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.

Put Option

  

A contract that gives the purchaser the right, but not the obligation, to sell the underlying commodity at a certain price on an agreed date.

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 oil and natural gas liquids components have been converted to cubic feet equivalents at a rate of 6 thousand cubic feet per barrel.


ENERGEN CORPORATION

2007 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

 

          Page
   PART I   
Item 1.   

Business

   4
Item 1A.   

Risk Factors

   11
Item 1B.   

Unresolved Staff Comments

   12
Item 2.   

Properties

   13
Item 3.   

Legal Proceedings

   14
Item 4.   

Submission of Matters to a Vote of Security Holders

   15
   PART II   
Item 5.   

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

   18
Item 6.   

Selected Financial Data

   20
Item 7.   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   22
Item 7A.   

Quantitative and Qualitative Disclosures about Market Risk

   37
Item 8.   

Financial Statements and Supplementary Data

   38
Item 9.   

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

   86
Item 9A.   

Controls and Procedures

   86
   PART III   
Item 10.   

Directors, Executive Officers and Corporate Governance

   89
Item 11.   

Executive Compensation

   89
Item 12.   

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   89
Item 13.   

Certain Relationships and Related Transactions, and Director Independence

   89
Item 14.   

Principal Accountant Fees and Services

   89
   PART IV   
Item 15.   

Exhibits and Financial Statement Schedules

   90
Signatures    95

 

2


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

and Alabama Gas Corporation (Alagasco).

Forward-Looking Statements: Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. 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.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, our ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.

Third Party Facilities: The forward-looking statements also assume generally uninterrupted access to third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources Corporation, the Company’s oil and gas subsidiary, relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company.

Energen Resources’ Production and Drilling: 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 acquisition, development 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.

Energen Resources’ Hedging: Although Energen Resources makes use of futures, swaps, options 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 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.

Alagasco’s Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and

 

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fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position.

Operations: 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 leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of 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. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows.

Alagasco’s Service Territory: 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.

PART I

 

ITEM 1. BUSINESS

General

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

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

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

Financial Information About Industry Segments

The information required by this item is provided in Note 19, Industry Segment Information, in the Notes to Financial Statements.

 

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Narrative Description of Business

 

 

Oil and Gas Operations

General: Energen’s oil and gas operations focus on increasing production and adding proved reserves through the development and acquisition of oil and gas properties. In addition, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. All gas, oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior, San Juan and Permian 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 2007, Energen Resources’ proved oil and gas reserves totaled 1,754 billion cubic feet equivalent (Bcfe). Substantially all of these reserves are located in the San Juan Basin in New Mexico and Colorado, the Permian Basin in west Texas and the Black Warrior Basin in Alabama. Approximately 82 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 18 years. Natural gas represents approximately 64 percent of Energen Resources’ proved reserves, with oil representing approximately 26 percent and natural gas liquids comprising the balance.

Growth Strategy: Energen has operated for more than ten years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $1.2 billion in property acquisitions, $1.3 billion in related development, and $209 million in exploration and related development. Energen Resources’ capital investment in 2008 and 2009 is currently expected to approximate $579 million primarily for existing properties. The Company also may allocate additional capital during this two-year period for other oil and gas activities such as property acquisitions and the exploration and development of potential shale plays primarily in Alabama. The estimates above do not include amounts for capital related to potential acquisitions or development of these shale plays discussed below.

Energen Resources seeks to acquire onshore North American properties which offer proved undeveloped and/or behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources will consider acquisitions of other types of properties which meet its investment requirements, including acquisitions with unproved properties. In addition, Energen Resources conducts exploration activities primarily in areas in which it has operations and remains open to exploration activities which complement its core expertise and meet its investment requirements. Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties’ undeveloped reserves and behind-pipe reserve potential as well as engaging in other activities. These activities include 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 development activities. Energen Resources operated approximately 91 percent of its proved reserves at December 31, 2007.

In October 2006, Energen Resources sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its unproved lease position of approximately 200,000 acres in various shale plays in Alabama for $75 million and a $15 million carried drilling interest. In addition, the two companies signed an agreement to form an area of mutual interest (AMI) through which they will pursue new leases, exploration, development and operations on a 50-50 basis, for at least the next 10 years. Energen Resources and Chesapeake continue to lease shared acreage in the AMI, which encompasses Alabama and some of Georgia, in advance of drilling. As of February 25, 2008, Energen Resources’ net acreage position in Alabama shale totaled approximately 287,500 acres and represents multiple shale opportunities.

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

 

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available drilling locations; changes in the economic or operating environments that allow previously uneconomic locations to be added; technological advances that make reserve locations available for development; successful development of existing proved undeveloped reserve locations that reclassify adjacent probable locations to proved undeveloped reserve locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in management’s intent to develop certain opportunities.

During the three years ended December 31, 2007, the Company’s development efforts have added 364 Bcfe of proved reserves from the drilling of 975 gross development wells (including 27 sidetrack wells) and 150 well recompletions and pay-adds. In 2007, Energen Resources’ successful development wells and other activities added approximately 127 Bcfe of proved reserves; the company drilled 367 gross development wells (including 22 sidetrack wells), performed some 34 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources’ production from continuing operations totaled 98.6 Bcfe in 2007 and is estimated to total 102 Bcfe in 2008, including 100 Bcfe of estimated production from proved reserves owned at December 31, 2007. In 2009, production is estimated to be 108 Bcfe, including approximately 100 Bcfe produced from proved reserves currently owned.

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

 

Years ended December 31,

   2007    2006    2005

Development:

        

Productive

       135.5        151.7        153.9

Dry

       1.0        -        1.7

Total

       136.5        151.7        155.6

Exploratory:

        

Productive

       21.7        40.1        4.1

Dry

       0.3        3.0        -

Total

       22.0        43.1        4.1

As of December 31, 2007, the Company was participating in the drilling of 9 gross development wells, with the Company’s interest equivalent to 5 wells. In addition to the development wells drilled, the Company drilled 99.8, 35.9 and 33 net service wells during 2007, 2006 and 2005, respectively. As of December 31, 2007, the Company was participating in the drilling of 1 gross service well, with the Company’s interest equivalent to 0.9 well.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2007, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

 

     Gross    Net

Gas wells

   4,101    2,333

Oil wells

   3,161    1,587

Developed acreage

   820,732    564,748

Undeveloped acreage

   324,395    287,852

There were 17 wells with multiple completions in 2007. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in Alabama.

Risk Management: Energen Resources attempts to lower the commodity price risk associated with its oil and natural gas business through the use of futures, swaps and options. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge more than two fiscal years forward. Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the

 

6


degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.

The Company may also enter into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, put options and swaps on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change.

In the case of an acquisition, Energen Resources may hedge more than two years forward to protect targeted returns. Energen Resources prefers long-lived reserves and primarily uses the then-current oil and gas futures prices in its evaluation models, the prevailing swap curve and, for the longer-term, its own pricing assumptions.

See the Forward-Looking Statements in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, 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 marketers and 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 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 producers, 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 177 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.4 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2007, Alagasco served an average of 416,967 residential customers and 34,200 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 10,200 miles of main and more than 11,900 miles of service lines, odorization and regulation facilities, and customer meters.

APSC Regulation: As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended in 2007, 2002, 1996, 1990, 1987 and 1985. On December 21, 2007, the APSC extended RSE for a seven-year period through December 31, 2014. Under the terms of the extension, RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology. Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year).

Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, 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. Prior to the December 21, 2007 extension, RSE limited the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provided for certain cost control

 

7


measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer fell within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment was required. If the change in O&M expense per customer exceeded the index range, three-quarters of the difference was returned to customers. To the extent the change was less than the index range, the utility benefited by one-half of the difference through future rate adjustments.

Subsequent to the extension, the equity on which a return will be permitted will be phased down to 57 percent by December 31, 2008 and 55 percent by December 31, 2009. The changes to the O&M expense cost control measurement subsequent to the extension are as follows: annual changes in O&M expense will be measured on an aggregate basis rather than per customer; the percentage change in O&M expense must fall within a range of 0.75 points above or below the percentage change in the index range; non-recurring and/or recurring items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation; the O&M expense base for measurement purposes will continue to be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the index range in two successive years, in which case the base for the following year will be set at the top of the index range.

The temperature adjustment rider to Alagasco’s rate tariff, approved by the APSC in 1990, was designed to mitigate the earnings impact of variances from normal temperatures. Alagasco calculates a temperature adjustment to customers’ monthly bills to moderate the impact of departures from normal temperatures on Alagasco’s earnings. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers’ bills. Other non-temperature weather conditions that may affect customer usage are not included such as the impact of wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. Adjustments to customers’ bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider that permits the pass-through to customers of changes in the cost of gas supply.

The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is achieved. Subsequent to the 2007 extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR.

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 several 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.

 

8


As of December 31, 2007, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:

 

     December 31, 2007     
   (Mcfd)     

Southern firm transportation

   152,933     

Southern storage and no notice transportation

   251,679   

Transco firm transportation

   70,000   

Various intrastate transportation

   20,240     

Competition and Rate Flexibility: 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/or 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 flexible rate strategies to help it compete for the large customer gas load in the marketplace. Rate flexibility remains critical as the utility faces competition for this load. To date, the utility has been effective in utilizing its flexible rate strategies to minimize bypass and price-based switching to alternate fuels and alternate sources of gas.

In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs; Alagasco’s core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential and its small commercial and industrial customers. In 2007, approximately 300 of Alagasco’s transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled more than $7.8 million.

The Competitive Fuel Clause (CFC) and Transportation Tariff also have been important to Alagasco’s ability to compete effectively for customer load in its service territory. The CFC allows Alagasco to adjust large customer rates on a case-by-case basis to compete with alternate fuels and alternate sources of gas. The GSA rider to Alagasco’s tariff allows the Company to recover a reduction in charges allowed under the CFC because the retention of any customer, particularly large commercial and industrial transportation customers, benefits all customers by recovering a portion of the system’s fixed costs. The Transportation Tariff allows Alagasco to transport gas for customers, rather than buy and resell it to them, and is based on Alagasco’s sales profit margin so that operating margins are unaffected. During 2007 substantially all of Alagasco’s large commercial and industrial customer deliveries involved the transportation of customer-owned gas. In addition, Alagasco served as gas purchasing agent for more than 99 percent of its transportation customers. Alagasco also uses long-term special contracts as a vehicle for retaining large customer load. At the end of 2007, 65 of the utility’s largest commercial and industrial transportation customers were under special contracts of varying lengths.

Natural gas service available to Alagasco customers falls into two broad categories: interruptible and firm. Interruptible service contractually is subject to interruption by Alagasco for various reasons; the most common occurrence is curtailment of industrial customers during periods of peak core market heating demand. Interruptible service typically is provided to large commercial and industrial transportation customers who can reduce their gas consumption by adjusting production schedules or by switching to alternate fuels for the duration of the service interruption. More expensive firm service, on the other hand, generally is not subject to interruption and is provided to residential and to small commercial and industrial customers; these core market customers depend on natural gas primarily for space heating.

Growth: Customer growth presents a major challenge for Alagasco, given its mature, slow-growth service area. In 2007 Alagasco’s average number of customers decreased 1 percent. Alagasco will continue to concentrate on maintaining its current penetration levels in the residential new construction market and generating additional revenue in the small and large commercial and industrial market segments.

 

9


Seasonality: Alagasco’s gas distribution business is highly seasonal since a material portion of the utility’s total sales and delivery volumes is to space heating customers. Alagasco’s rate 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 calculation is performed monthly, and adjustments are made to customers’ bills in the actual month the weather variation occurs.

 

 

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 and is not expected to do so in the future; however, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

A discussion of certain litigation against Energen Resources in the state of Louisiana related to the restoration of oilfield properties is included in Item 3, Legal Proceedings of Part I in this Form 10-K.

Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns) and five manufactured gas distribution sites (one of which it still owns). An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco’s share, if any, of such costs will not materially affect the Company’s financial position.

 

 

Employees

The Company has approximately 1,542 employees, of which Alagasco employs 1,169 and Energen Resources employs 373. The Company believes that its relations with employees are good.

 

10


ITEM 1A. RISK FACTORS

Third Party Facilities: Energen Resources delivers to and Alagasco is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company.

Energen Resources’ Production and Drilling: 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.

Energen Resources’ Hedging: Although Energen Resources makes use of futures, swaps, options 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 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.

Alagasco’s Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position.

Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of 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. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows.

 

11


Energen Resources Customer Concentration: 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. The four largest oil, natural gas and natural gas liquids purchasers account for approximately 22 percent, 14 percent, 11 percent and 10 percent, respectively, of Energen Resources’ estimated 2008 production. Energen Resources’ other purchasers each bought less than 8 percent of production.

Alagasco’s Service Territory: 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.

Access to Credit Markets: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by rating agency evaluations of the Company and of Alagasco. Events affecting credit market liquidity could increase borrowing costs or limit availability of funds.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

 

12


ITEM 2. PROPERTIES

The corporate headquarters of Energen, Alagasco and Energen Resources 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 18, 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.

Oil and Gas Operations

Energen Resources focuses on increasing its production and proved reserves through the acquisition and development of onshore North American producing oil and gas properties. Energen Resources maintains offices in Arcadia, Louisiana; in Farmington, New Mexico; and in Midland, Texas. The Company also maintains offices in Lehman, Seminole, Westbrook and Penwell, Texas; and in Brookwood and Tuscaloosa, Alabama.

LOGO

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

The following table sets forth the production volumes for the year ended December 31, 2007, and proved reserves and reserves-to-production ratio by area as of December 31, 2007:

 

     

Year Ended

December 31, 2007

  December 31, 2007    December 31, 2007
   Production Volumes

(MMcfe)

  Proved Reserves
(MMcfe)
   Reserves-to-
Production Ratio

San Juan Basin

   47,517           943,423            19.85 years        

Permian Basin

   28,655           501,920            17.52 years        

Black Warrior Basin

   14,813           234,253            15.81 years        

North Louisiana/East Texas

   7,187           68,653            9.55 years        

Other

   433           5,403            12.48 years        

Total

   98,605           1,753,652            17.78 years        

 

13


The following table sets forth proved reserves by area as of December 31, 2007:

 

      Gas MMcf    Oil MBbl    NGL MBbl

San Juan Basin

   762,091    1,326    28,896

Permian Basin

   47,648    72,944    2,768

Black Warrior Basin

   234,253    -    -

North Louisiana/East Texas

   67,573    180    -

Other

   4,353    175    -

Total

   1,115,918    74,625    31,664

The following table sets forth proved developed reserves by area as of December 31, 2007:

 

      Gas MMcf    Oil MBbl    NGL MBbl

San Juan Basin

   569,800    1,320    25,805

Permian Basin

   44,042    59,553    2,543

Black Warrior Basin

   231,791    -    -

North Louisiana/East Texas

   53,526    161    -

Other

   4,351    175    -

Total

   903,510    61,209    28,348

Energen Resources files Form EIA-23 with the Department of Energy which reports gross proved reserves, including the working interest share of other owners, for properties operated by the Company. The proved reserves reported in the table above represent our share of proved reserves for all properties, based on our ownership interest in each property. For properties operated by Energen Resources, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Company-owned proved reserves reported in the table above does not exceed five percent. Estimated proved reserves as of December 31, 2007 are based upon studies for each of our properties prepared by Company engineers and reviewed by Ryder Scott Company, L.P. and T. Scott Hickman and Associates, Inc., independent oil and gas reservoir engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.

The following table sets forth the total net productive gas and oil wells by area as of December 31, 2007, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

 

      Net Wells    Net Developed
Acreage
   Net Undeveloped
Acreage

San Juan Basin

   1,390    302,202    1,413

Permian Basin

   1,579    87,851    3,309

Black Warrior Basin

   782    147,190    1,187

North Louisiana/East Texas

   159    20,675    55

Alabama Shale and Other

   10    6,830    281,888

Total

   3,920    564,748    287,852

Natural Gas Distribution

The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 10,200 miles of main and more than 11,900 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, four division commercial offices, three division business centers, two payment centers, three district offices, seven service centers, and other related property and equipment, some of which are leased by Alagasco.

 

ITEM 3. LEGAL PROCEEDINGS

Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specific relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its

 

14


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

Jefferson County, Alabama

In January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources’ calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. RGGS seeks a declaratory judgment with respect to the parties’ rights under the lease, reformation of the lease, monetary damages and termination of Energen Resources’ rights under the lease. The Occluded Gas Lease dated January 1, 1986 was originally between Energen Resources and United States Steel Corporation (U.S. Steel) as lessor. RGGS became the lessor under the lease as a result of a 2004 conveyance from U.S. Steel to RGGS. Approximately 120,000 acres in Jefferson and Tuscaloosa counties, Alabama, are subject to the lease. Separately on February 6, 2006, Energen Resources received notice of immediate lease termination from RGGS. During 2007, Energen Resources’ production associated with the lease was approximately 10.5 Bcf.

RGGS has adopted positions contrary to the seventeen years of course of dealing between Energen Resources and its original contracting partner, U.S. Steel. The Company believes that RGGS’ assertions are without merit and that the notice of lease termination is ineffective. Energen Resources intends to vigorously defend its rights under the lease. The Company remains in possession of the lease, believes that the likelihood of a judgment in favor of RGGS is remote, and has made no material accrual with respect to the litigation or purported lease termination.

Enron Corporation

Enron and Enron North America Corporation (ENA) have settled with Energen Resources and Alagasco related to the Enron and ENA bankruptcy proceedings. Under the settlement, Energen Resources was allowed claims in the bankruptcy cases against Enron and ENA of $12.5 million each. In December 2006, Energen Resources sold its claims against Enron and ENA for a gain of $6.7 million after-tax. All other claims have been released.

Legacy Litigation

During recent years, numerous lawsuits have been filed against oil production companies in Louisiana for restoration of oilfield properties. These suits are referred to in the industry as “legacy litigation” because they usually involve operations that were conducted on the affected properties many years earlier. Energen Resources is or has been a party to several legacy litigation lawsuits, most of which result from the operations of predecessor companies. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from legacy litigation in excess of the Company’s accrued provision for estimated liability are not considered material to the Company’s financial position.

Other

Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for the estimated liability.

 

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the fourth quarter of 2007.

 

15


EXECUTIVE OFFICERS OF THE REGISTRANTS

Energen Corporation

 

Name

   Age   

Position (1)

James T. McManus, II

   49   

Chairman, Chief Executive Officer and President of Energen and Chairman and Chief Executive Officer of Alagasco (2)

Wm. Michael Warren, Jr.

   60   

(3)

Charles W. Porter, Jr.

   43   

Vice President, Chief Financial Officer and Treasurer of Energen and Alagasco (4)

John S. Richardson

   50   

President and Chief Operating Officer of Energen Resources (5)

Dudley C. Reynolds

   55   

President and Chief Operating Officer of Alagasco (6)

J. David Woodruff, Jr.

   51   

General Counsel and Secretary of Energen and Alagasco and Vice President-Corporate Development of Energen (7)

Grace B. Carr

   52   

Vice President and Controller of Energen (8)

 

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. Warren retired from the Company at the end of 2007. He had been employed by the Company in various capacities since 1983 and served as Chairman of the Board and Chief Executive Officer of Energen and each of its subsidiaries since 1998. Mr. Warren was succeeded by Mr. McManus as Chief Executive officer effective July 1, 2007 and as Chairman of the Board of Energen and each of its subsidiaries effective January 1, 2008. Mr. Warren continues to serve as a Director of Energen and each of its subsidiaries.

  

(4)

  

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.

  

(5)

  

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.

 

16


  

(6)

  

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.

  

(7)

  

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 and Vice President-Corporate Development of Energen in October 1995. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003.

  

(8)

  

Ms. Carr was employed by the Company in various capacities from January 1985 to April 1989. She was not employed from May 1989 through December 1997. She was elected Controller of Energen in January 1998 and elected Vice President and Controller of Energen in October 2001.

 

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, 2006

   39.49    32.71      35.00    .11              

June 30, 2006

   38.42    32.16      38.41    .11              

September 30, 2006

   44.48    36.95      41.87    .11              

December 31, 2006

   47.60    38.50      46.94    .11              

March 31, 2007

   51.43    43.78      50.89    .115            

June 30, 2007

   60.49    51.05      54.94    .115            

September 30, 2007

   58.90    48.24      57.12    .115            

December 31, 2007

   70.41    56.81      64.23    .115            

Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On February 8, 2008, there were 7,135 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 $0.48 per share on the Company’s common stock in 2008. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

The following table summarizes information concerning securities authorized for issuance under equity compensation plans:

 

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*

   466,339                  $30.79            1,953,996                  

Equity compensation plans not
approved by security holders

   -                  -            -                  

Total

   466,339                  $30.79            1,953,996                  
*

These plans include the Company’s 1997 Stock Incentive Plan and the 1992 Energen Corporation Directors Stock Plan

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

 

Period    Total Number of
Shares Purchased
 
 
  Average Price
Paid per Share
   Total Number of
Shares Purchased as
Part of Publicly
Announced Plans
   Maximum Number
of Shares that May
Yet Be Purchased
Under the Plans**

October 1, 2007 through
October 31, 2007

   -     -    -    8,992,700

November 1, 2007 through
November 30, 2007

   -     -    -    8,992,700

December 1, 2007 through
December 31, 2007

   1,857 *   $    64.43    -    8,992,700

Total

   1,857     $    64.43    -    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 a resolution 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, 2002, in the Company and each of the indices. Total shareholder return includes reinvested dividends.

LOGO

 

As of December 31,

     2002      2003      2004      2005      2006      2007

S&P 500 Index

   $ 100    $ 129    $ 143    $ 150    $ 173    $ 183

Energen

   $ 100    $ 144    $ 210    $ 262    $ 343    $ 473

S15OILP Index

   $ 100    $ 127    $ 172    $ 279    $ 289    $ 413

S15GASUX

   $ 100    $ 124    $ 145    $ 157    $ 196    $ 223

 

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)

     2007      2006       2005      2004      2003

INCOME STATEMENT

             

Operating revenues

   $   1,435,060    $   1,393,986 *   $   1,128,394    $ 936,857    $ 841,631

Income from continuing operations

   $ 309,212    $ 273,523 *   $ 172,886    $ 127,305    $ 110,104

Net income

   $ 309,233    $ 273,570 *   $ 173,012    $ 127,463    $ 110,654

Diluted earnings per average common share
from continuing operations

   $ 4.28    $ 3.73 *   $ 2.35    $ 1.74    $ 1.54

Diluted earnings per average common share

   $ 4.28    $ 3.73 *   $ 2.35    $ 1.74    $ 1.55

BALANCE SHEET

             

Total property, plant and equipment, net

   $ 2,538,243    $ 2,252,414     $ 2,068,011    $ 1,783,059    $ 1,433,451

Total assets

   $ 3,079,653    $ 2,836,887     $ 2,618,226    $ 2,181,739    $ 1,778,232

Long-term debt

   $ 562,365    $ 582,490     $ 683,236    $ 612,891    $ 552,842

Total shareholders’ equity

   $ 1,378,658    $ 1,202,069     $ 892,678    $ 803,666    $ 699,032

COMMON STOCK DATA

             

Annual dividend rate at period-end

   $ 0.46    $ 0.44     $ 0.40    $ 0.385    $ 0.37

Cash dividends paid per common share

   $ 0.46    $ 0.44     $ 0.40    $ 0.3775    $ 0.365

Diluted average common shares outstanding (000)

     72,181      73,278       73,715      73,117      71,434

Price range:

             

High

   $ 70.41    $ 47.60     $ 44.31    $ 30.04    $ 21.00

Low

   $ 43.78    $ 32.16     $ 27.06    $ 19.94    $ 14.04

Close

   $ 64.23    $ 46.94     $ 36.32    $ 29.48    $ 20.52

 

*

Includes an after-tax gain of $34.5 million, or $0.47 per diluted share, on the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shale to Chesapeake Energy Corporation.

All information has been restated to reflect a 2-for-1 stock split effective June 1, 2005.

 

20


SELECTED BUSINESS SEGMENT DATA

Energen Corporation

 

Years ended December 31,

(dollars in thousands)

     2007      2006      2005      2004      2003

OIL AND GAS OPERATIONS

              

Operating revenues from continuing operations

              

Natural gas

   $ 499,406    $ 437,560    $ 365,635    $ 276,482    $ 235,022

Oil

     251,497      181,459      116,651      98,409      87,192

Natural gas liquids

     68,623      50,258      38,455      30,902      25,938

Other

     6,066      61,265      6,953      4,324      4,380

Total

   $ 825,592    $ 730,542    $ 527,694    $ 410,117    $ 352,532

Production volumes from continuing operations

              

Natural gas (MMcf)

     64,300      62,824      61,048      57,164      55,304

Oil (MBbl)

     3,879      3,645      3,316      3,434      3,411

Natural gas liquids (MMgal)

     77.2      76.3      70.5      68.2      66.6

Production volumes from continuing
operations (MMcfe)

     98,606      95,596      91,020      87,513      85,291

Total production volumes (MMcfe)

     98,605      95,595      91,099      87,606      86,157

Proved reserves

              

Natural gas (MMcf)

     1,115,918      1,096,429      1,080,161      1,019,436      886,307

Oil (MBbl)

     74,625      74,893      74,962      54,500      52,528

Natural gas liquids (MBbl)

     31,664      29,504      31,934      34,613      27,245

Total (MMcfe)

     1,753,652      1,722,811      1,721,537      1,554,114      1,364,945

Other data from continuing operations
Lease operating expense (LOE)

              

LOE and other

   $ 148,280    $ 134,853    $ 104,241    $ 79,191    $ 67,833

Production taxes

     53,798      49,509      52,271      37,285      27,686

Total

   $ 202,078    $ 184,362    $ 156,512    $ 116,476    $ 95,519

Depreciation, depletion and amortization

   $ 114,241    $ 97,842    $ 89,340    $ 80,896    $ 79,495

Capital expenditures

   $ 379,479    $ 259,678    $ 353,712    $ 403,936    $ 163,338

Operating income

   $ 451,567    $ 405,149    $ 243,876    $ 180,379    $ 153,325

NATURAL GAS DISTRIBUTION

              

Operating revenues

              

Residential

   $ 388,291    $ 426,066    $ 384,753    $ 340,229    $ 320,938

Commercial and industrial

     164,903      181,900      166,957      138,686      126,638

Transportation

     49,255      45,950      43,291      40,221      38,250

Other

     7,019      9,528      5,699      7,604      3,273

Total

   $ 609,468    $ 663,444    $ 600,700    $ 526,740    $ 489,099

Gas delivery volumes (MMcf)

              

Residential

     20,665      22,310      24,601      25,383      27,248

Commercial and industrial

     10,593      11,226      12,498      12,323      12,564

Transportation

     51,448      50,760      49,850      54,385      55,623

Total

     82,706      84,296      86,949      92,091      95,435

Average number of customers

              

Residential

     416,967      420,558      425,110      425,673      427,413

Commercial, industrial and transportation

     34,200      34,456      34,936      35,248      35,463

Total

     451,167      455,014      460,046      460,921      462,876

Other data

              

Depreciation and amortization

   $ 47,136    $ 44,244    $ 42,351    $ 39,881    $ 37,171

Capital expenditures

   $ 58,862    $ 76,157    $ 73,276    $ 58,208    $ 57,906

Operating income

   $ 72,742    $ 74,274    $ 72,922    $ 66,199    $ 66,848

 

21


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

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation’s net income for the year ended December 31, 2007 totaled $309.2 million, or $4.28 per diluted share and compared favorably to the year ended December 31, 2006 net income of $273.6 million, or $3.73 per diluted share. This 14.7 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids and the impact of a 3 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources Corporation, Energen’s oil and gas subsidiary, partially offset by the prior year after-tax gain of approximately $34.5 million, or $0.47 per diluted share, on the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shale to Chesapeake Energy Corporation (Chesapeake). For the year ended December 31, 2007, Energen Resources earned $273.2 million, as compared with $237.6 million in the previous year. Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, generated net income of $36.8 million in the current year as compared with net income in the prior period of $37.3 million. For the year ended December 31, 2005, Energen reported earnings of $173 million, or $2.35 per diluted share.

2007 vs 2006: For the year ended December 31, 2007, Energen Resources’ net income and income from continuing operations totaled $273.2 million and compared favorably to $237.6 million in the prior year. The primary factors positively influencing income from continuing operations included higher commodity prices of approximately $80 million after-tax, the impact of increased production volumes of approximately $14 million after-tax and the Section 199 Domestic Production Activities Deduction tax benefit on qualified oil and gas production income of approximately $7 million. Negatively affecting comparable income from continuing operations was the $34.5 million after-tax gain on the acreage position sale to Chesapeake recorded in the prior year, higher depreciation, depletion and amortization (DD&A) expense of approximately $10 million after-tax, higher lease operating expense of approximately $8 million after-tax, increased administrative expenses of approximately $3 million after-tax and a prior year $6.7 million after-tax gain on the sale of Energen Resources’ bankruptcy claim against Enron.

Alagasco earned net income of $36.8 million in 2007 as compared with net income of $37.3 million in 2006. This decrease in earnings largely reflected revenue reductions under the utility’s rate-setting mechanism of $2.3 million after-tax partially offset by a $1.2 million after-tax increase arising from the utility’s ability to earn on a higher level of equity and a $0.9 million after-tax reduction in expenses associated with the prior year’s Cost Control Measurement (CCM) giveback. Alagasco’s return on average equity (ROE) was 12.3 percent in 2007 compared with 13.1 percent in 2006.

2006 vs 2005: Energen Resources’ net income rose 75.6 percent to $237.6 million in 2006. Energen Resources’ income from continuing operations totaled $237.6 million in 2006 as compared with $135.2 million in 2005 primarily due to increased commodity prices of approximately $77 million after-tax along with the impact of increased production volumes of approximately $16 million after-tax, the $34.5 million after-tax gain on the sale to Chesapeake and the $6.7 million after-tax gain on the Enron bankruptcy settlement. These increases were partially offset by higher lease operating expense of approximately $19 million after-tax, increased DD&A expense of approximately $5 million after-tax and increased administrative expenses of approximately $5 million after-tax. Alagasco earnings increased to $37.3 million in 2006 from $37 million in 2005 largely as a result of $2 million after-tax increase arising from the utility’s ability to earn on a higher level of equity and reductions in the prior year under the utility’s rate setting mechanism of $1.9 million after-tax largely offset by a decrease in customer usage and a $0.9 million after-tax reduction associated with the CCM giveback. Alagasco achieved a ROE of 13.1 percent in 2006 compared with 13.5 percent in 2005.

Operating Income

Consolidated operating income in 2007, 2006 and 2005 totaled $522 million, $477.3 million and $315.7 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources under Energen’s diversified growth strategy. Alagasco’s operating income has been relatively flat for the three previous years as the utility’s ability to earn a return on a higher level of equity was offset by decreased customer usage and revenue reductions under its rate-setting mechanisms.

 

22


Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of increased commodity prices as well as the impact of increased production volumes. Production increased primarily due to additional development activities in the San Juan and Permian basins partially offset by normal production declines. Revenue per unit of production for natural gas production increased 11.6 percent to $7.77 per thousand cubic feet (Mcf), oil revenue per unit of production rose 30.2 percent to $64.83 per barrel and natural gas liquids revenue per unit of production increased 34.8 percent to an average price of $0.89 per gallon during 2007. Production from continuing operations rose 3.1 percent to 98.6 Bcfe during 2007. Natural gas production increased 2.3 percent to 64.3 billion cubic feet (Bcf) and oil volumes increased 6.4 percent to 3,879 thousand barrels (MBbl). Production of natural gas liquids increased 1.2 percent to 77.2 million gallons (MMgal).

In 2006, revenues from oil and gas operations increased primarily as a result of increased commodity prices and increased production volumes. Production increased primarily due to additional development activities in the San Juan Basin, accelerated workovers due to milder winter weather and increased volumes related to the purchase of Permian Basin oil properties in the fourth quarter of 2005. Negatively affecting production were normal production declines. Revenue per unit of production related to natural gas increased 16.2 percent to $6.96 per Mcf, oil revenue per unit of production rose 41.5 percent to $49.79 per barrel and natural gas liquids revenue per unit of production increased 20 percent to an average price of $0.66 per gallon during the year ended December 31, 2006. Production from continuing operations increased 5 percent to 95.6 Bcfe in 2006. Natural gas production rose 2.9 percent to 62.8 Bcf, oil volumes increased 9.9 percent to 3,645 MBbl and natural gas liquids production increased 8.2 percent to 76.3 MMgal.

Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses. Revenues from operating fees were $6.1 million, $6.6 million and $8.7 million in 2007, 2006 and 2005, respectively. During 2006, Energen Resources recorded a $55.5 million pre-tax gain in other operating revenues for the sale of a 50 percent interest in Energen Resources’ acreage position in Alabama shale to Chesapeake.

 

Years ended December 31, (in thousands, except sales price data)

   2007     2006    2005  

Operating revenues from continuing operations

       

Natural gas

   $    499,406     $    437,560    $    365,635  

Oil

   251,497     181,459    116,651  

Natural gas liquids

   68,623     50,258    38,455  

Operating fees

   6,119     6,553    8,674  

Other

   (53 )   54,712    (1,721 )

Total operating revenues from continuing operations

   $    825,592     $    730,542    $    527,694  

Production volumes from continuing operations

       

Natural gas (MMcf)

   64,300     62,824    61,048  

Oil (MBbl)

   3,879     3,645    3,316  

Natural gas liquids (MMgal)

   77.2     76.3    70.5  

Revenue per unit of production including effects of all derivative instruments

       

Natural gas (per Mcf)

   $          7.77     $          6.96    $          5.99  

Oil (per barrel)

   $        64.83     $        49.79    $        35.18  

Natural gas liquids (per gallon)

   $          0.89     $          0.66    $          0.55  

Revenue per unit of production including effects of qualifying cash flow hedges

       

Natural gas (per Mcf)

   $          7.76     $          6.96    $          6.36  

Oil (per barrel)

   $        64.80     $        49.54    $        35.18  

Natural gas liquids (per gallon)

   $          0.89     $          0.66    $          0.55  

Revenue per unit of production excluding effects of all derivative instruments

       

Natural gas (per Mcf)

   $          6.45     $          6.53    $          7.81  

Oil (per barrel)

   $        67.17     $        59.88    $        51.61  

Natural gas liquids (per gallon)

   $          0.98     $          0.80    $          0.74  

Average production (lifting) cost (per Mcfe)

   $          1.50     $          1.41    $          1.15  

Average production tax (per Mcfe)

   $          0.55     $          0.52    $          0.57  

Average DD&A rate (per Mcfe)

   $          1.13     $          1.00    $          0.96  

 

23


Operations and maintenance (O&M) expense increased $28.7 million and $31.5 million in 2007 and 2006, respectively. Lease operating expense (excluding production taxes) in 2007 increased $13.4 million largely due to additional compression costs (approximately $2 million), increased repair and maintenance expense in the San Juan and Permian basins (approximately $7 million), higher transportation related to increased San Juan Basin production (approximately $3 million) and a general rise in field service costs. In 2006, lease operating expense (excluding production taxes) increased by $30.6 million due to a variety of factors including the December 2005 acquisition of Permian Basin oil properties (approximately $9 million), additional maintenance expense primarily in the San Juan Basin designed to increase production (approximately $2 million), increased workover expense (approximately $6 million), higher transportation costs (approximately $4 million), an increased number of wells in period comparisons and other overall cost increases. In 2007, administrative expense increased $16.6 million primarily due to a prior year pre-tax gain of $10.7 million on the sale of Energen Resources’ bankruptcy claims against Enron and increased labor-related costs, including settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of $2.3 million. Administrative expense decreased $2.6 million in 2006 largely due to the $10.7 million pre-tax gain against Enron; this gain was partially offset by higher labor-related costs. Exploration expense declined $1.3 million in 2007 largely due to decreased exploratory efforts. In 2006, exploration expense rose $3.5 million.

DD&A expense increased $16.4 million in 2007 and $8.5 million in 2006. The average DD&A rates were $1.13 per Mcfe in 2007, $1.00 per Mcfe in 2006 and $0.96 per Mcfe in 2005. The increase in the average 2007 DD&A rate, which contributed approximately $13 million, was primarily due to higher development costs along with a decline in prior year-end reserve prices. Increased production volumes also contributed approximately $3 million to the increase in DD&A expense in the current year. The increase in the average 2006 rate contributed approximately $3.8 million and was largely due to higher depletion rates on oil properties purchased in the Permian Basin in December 2005 and higher rates due to a downward revision to estimated reserves resulting from a reduction in year-end reserve prices. Partially offsetting the higher rate was increased production in lower rate areas. Increased production volumes contributed approximately $4.4 million due to the 2006 increase in DD&A expense.

Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes. Energen Resources recorded severance taxes of $53.8 million, $49.5 million and $52.3 million for 2007, 2006 and 2005, respectively. Severance taxes increased $4.3 million in 2007 over the prior year. Higher commodity market prices and the impact of increased production volumes contributed approximately $3 million and $1.6 million, respectively. Decreased severance taxes in 2006 resulted from lower natural gas commodity market prices largely offset by higher production volumes and increased oil and natural gas liquids commodity market prices. 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). On December 21, 2007, the APSC issued an order to extend the utility’s rate-setting mechanism. Under the terms of the extension, RSE will continue after December 31, 2014, unless, after notice to the company and a hearing, the APSC votes to modify or discontinue the RSE methodology. Alagasco’s allowed range of return on equity remains 13.15 percent to 13.65 percent throughout the term of the order. Prior to the December 21, 2007 extension, RSE limited the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provided for certain cost control measures designed to monitor Alagasco’s O&M expense. Subsequent to the extension, the equity on which a return will be permitted will be phased down to 57 percent by December 31, 2008 and 55 percent by December 31, 2009.

Prior to the extension, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense per customer fell within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment was required. If the change in O&M expense per customer exceeded the index range, three-quarters of the difference was returned to customers. To the extent the change was less than the index range, the utility benefited by one-half of the difference through future rate adjustments. The changes to the O&M expense cost control measurement subsequent to the extension are as follows: annual changes in O&M expense will be measured on an aggregate basis rather than per customer; the

 

24


percentage change in O&M expense must fall within a range of 0.75 points above or below the percentage change in the index range; certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation; the O&M expense base for measurement purposes will continue to be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the index range in two successive years, in which case the base for the following year will be set at the top of the index range.

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, but the financial impact is moderated by a temperature adjustment mechanism that requires Alagasco to adjust certain customer bills monthly to reflect changes in usage due to departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

Alagasco’s natural gas and transportation sales revenues totaled $609.5 million, $663.4 million and $600.7 million in 2007, 2006 and 2005, respectively. Sales revenue in 2007 declined largely due to a decrease in gas costs of approximately $28 million and a decline in customer usage of approximately $27 million. In 2006, sales revenue increased primarily due to an increase in gas costs approximately $82 million partially offset by a decrease in customer usage of approximately $28 million. In 2007, weather was 7.9 percent warmer than in the prior year. Residential sales volumes declined 7.4 percent while commercial and industrial volumes decreased 5.6 percent. Transportation volumes rose 1.4 percent. In 2006, weather that was 2.5 percent warmer than in the prior year along with customer conservation related to higher gas costs contributed to a 9.3 percent decline in residential sales volumes while commercial and industrial volumes decreased 10.2 percent. Transportation volumes increased 1.8 percent. In 2007, lower gas costs along with decreased gas purchase volumes contributed to a 14.7 percent decrease in cost of gas. Higher gas costs partially offset by a decline in gas purchase volumes resulted in a 17.2 percent increase in cost of gas in 2006.

O&M expense at the utility increased 1.9 percent in 2007 primarily due to increased labor-related costs (approximately $2 million), including settlement charges for the nonqualified supplemental retirement plans and the defined benefit pension plans of $3.4 million, largely offset by decreased bad debt expense (approximately $1 million). In 2006, O&M expense increased slightly primarily due to higher bad debt expense (approximately $1 million) and increased distribution maintenance expenses (approximately $1.7 million). These increases were offset by decreased labor-related expenses (approximately $4.5 million). The increase in O&M expense per customer for the rate year ended September 30, 2006 was above the inflation-based CCM established by the APSC as part of the utility’s rate-setting mechanism; as a result, three quarters of the differences, or $1.5 million pre-tax, was returned to the customers through RSE (see Note 2, Regulatory Matters, in the Notes to Financial Statements). Alagasco’s O&M expense fell within the index range for the rate years ended September 30, 2007 and 2005.

Depreciation expense rose 6.5 percent and 4.5 percent in 2007 and 2006, respectively, due to extension and replacement of the utility’s distribution and replacement of its support systems. 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)

   2007     2006     2005  

Natural gas transportation and sales revenues

   $          609,468     $          663,444     $          600,700  

Cost of natural gas

   (318,429 )   (373,097 )   (318,269 )

Operations and maintenance

   (129,351 )   (126,948 )   (126,041 )

Depreciation

   (47,136 )   (44,244 )   (42,351 )

Income taxes

   (21,636 )   (22,002 )   (22,360 )

Taxes, other than income taxes

   (41,810 )   (44,881 )   (41,117 )

Operating income

   $            51,106     $            52,272     $            50,562  

Natural gas sales volumes (MMcf)

      

Residential

   20,665     22,310     24,601  

Commercial and industrial

   10,593     11,226     12,498  

Total natural gas sales volumes

   31,258     33,536     37,099  

Natural gas transportation volumes (MMcf)

   51,448     50,760     49,850  

Total deliveries (MMcf)

   82,706     84,296     86,949  

 

25


Non-Operating Items

Consolidated: Interest expense in 2007 declined $1.6 million primarily due to lower borrowings at Energen Resources along with decreased interest expense associated with the May 2007 voluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007. Also contributing to the decrease in interest expense at Alagasco was the January 2007 redemption of $34.4 million of 6.75% Notes maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026 partially offset by the issuance of $45 million in long-term debt with an interest rate of 5.9%. Interest expense in 2006 increased $1.9 million largely due to financing costs associated with higher storage gas inventories at Alagasco and an increase in interest rates associated with Energen’s $100 million Floating Rate Senior Notes. The average daily outstanding balance under short-term credit facilities was $67.7 million in 2007. The average daily outstanding balance under short-term credit facilities was $63.7 million in 2006 as compared to $17.7 million in 2005. Income tax expense increased in the periods presented primarily due to higher pre-tax income. Partially offsetting the increase in income tax expense in 2007 was the after-tax impact of the Section 199 deduction (approximately $7 million after-tax).

FINANCIAL POSITION AND LIQUIDITY

The Company’s net cash from operating activities totaled $484.2 million, $482.9 million and $335.1 million in 2007, 2006 and 2005, respectively. Operating cash flow in 2007, 2006 and 2005 benefited from higher realized commodity prices and production volumes at Energen Resources. Negatively affecting operating cash flows during 2007 was an increase in income taxes payable related to depreciation and basis differences in the current period and the prior period utilization of minimum tax credit. In 2006, income from operations before income taxes included a pre-tax gain of $55.5 million related to the Chesapeake acreage sale; the cash proceeds from the sale are included in the investing activities on the Consolidated Statements of Cash Flows, as described more fully below. Working capital needs at Alagasco were reduced by declining gas costs for 2007. During 2006 and 2005, working capital needs at Alagasco were largely affected by increased gas costs compared to the prior period and storage gas inventory. Other working capital items, which primarily are the result of changes in throughput and the timing of payments, combined to create the remaining increases for all years.

During 2007, the Company made net investments of $431.9 million. Energen Resources invested $54.6 million in property acquisitions, including an $18 million acquisition in the Permian Basin and approximately $32 million of unproved leaseholds (including approximately $28 million related to Alabama shale), $313.2 million for development costs including approximately $202 million to drill 345 gross development wells and $7.5 million for exploration. Utility expenditures in 2007 totaled $58.2 million and primarily represented extension and replacement of its distribution system and support facilities. During 2006, the Company made net investments of $256.9 million. Energen Resources invested $46.4 million in property acquisitions, $186.3 million for development costs including approximately $130.6 million to drill 309 gross development wells and $25.9 million for exploration. In December 2006, Energen Resources completed its purchase of gas properties located in the San Juan Basin from Dominion Resources, Inc. for approximately $30 million. Energen Resources sold certain properties during 2006, resulting in cash proceeds of $79.4 million including $75 million received from Chesapeake for a 50 percent interest in its lease position in certain unproved shale acreage in Alabama. Utility expenditures in 2006 totaled $75.1 million. During 2005, cash used in investing activities totaled $400.7 million. Energen Resources invested $188.4 million in property acquisitions, $157.5 million for development costs including approximately $123 million to drill 294 gross development wells and $5.1 million for exploration. In December 2005, Energen Resources completed its purchase of oil properties located in the Permian Basin for approximately $168 million. During 2005, Energen Resources sold certain properties resulting in cash proceeds of $10.8 million. Utility expenditures in 2005 totaled $72.4 million.

During 2007, the Company added approximately 15 Bcfe of reserves primarily from the Permian Basin acquisition. Also during 2007, Energen Resources added 127 Bcfe of reserves from discoveries and other additions, primarily the result of improved drilling technology that increased the number of proved undeveloped locations in the San Juan Basin as well as continued downspacing in the Permian Basin. Energen Resources added approximately 167 Bcfe and 224 Bcfe of reserves in 2006 and 2005, respectively.

 

26


The Company used $53.9 million for net financing activities in 2007 primarily for the early redemption of $100 million Floating Rate Senior Notes due November 15, 2007, $34.4 million of 6.75% Notes maturing September 1, 2031, $10 million of Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026. Partially offsetting these uses of cash was the January 2007 issuance by Alagasco of $45 million in long-term debt with an interest rate of 5.9% due January 15, 2037. In 2006, net cash used for financing activities totaled $224.4 million largely due to $84.3 million incurred from the buy-back of Energen common stock under its stock repurchase plan along with the repayment of short-term borrowings. In addition, long-term debt was reduced by $15.9 million for current maturities in 2006. The Company provided $69.8 million from net financing activities in 2005. In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. In November 2005, Alagasco issued $80 million of long-term debt with an interest rate of 5.368 percent due December 1, 2015. Long-term debt was reduced by $84.8 million including Alagasco’s redemption of $18 million in Medium-Term Notes maturing June 27, 2007 to July 5, 2022 in August 2005 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 in December 2005. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders.

Capital Expenditures

Oil and Gas Operations: Energen Resources spent a total of approximately $1 billion for capital projects during the years ended December 31, 2007, 2006 and 2005. Property acquisition expenditures totaled $289.5 million, development activities totaled $656.9 million, and exploratory expenditures totaled $38.5 million.

 

Years ended December 31, (in thousands)

     2007      2006      2005

Capital and exploration expenditures for:

        

Property acquisitions

   $ 54,626    $ 46,428    $   188,403

Development

     313,220      186,264      157,458

Exploration

     7,456      25,936      5,065

Other

     5,667      4,411      3,037

Total

     380,969      263,039      353,963

Less exploration expenditures charged to income

     1,490      3,361      251

Net capital expenditures

   $   379,479    $   259,678    $ 353,712

Natural Gas Distribution: During the years ended December 31, 2007, 2006 and 2005, Alagasco invested $208.3 million for capital projects: $164.5 million for expansion, replacements and support of its distribution system and $43.7 million for support facilities and the development and implementation of information systems.

 

Years ended December 31, (in thousands)

     2007      2006      2005

Capital expenditures for:

        

Renewals, replacements, system expansion and other

   $     50,924    $     60,244    $     53,381

Support facilities

     7,938      15,913      19,895

Total

   $ 58,862    $ 76,157    $ 73,276

FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue investing significant capital in Energen Resources’s oil and gas production operations. For 2008, the Company expects its oil and gas capital spending to total approximately $308 million, including $290 million for existing properties. Included in this $290 million is approximately $153 million for the development of previously identified proved undeveloped reserves. The Company expects capital spending to total approximately $271 million during 2009, including approximately $260 million for existing properties. Included in this $260 million is approximately $81 million for the development of previously identified proved undeveloped reserves.

 

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Capital expenditures by area during 2008 are planned as follows:

 

Year ended December 31, (in thousands)

     2008

San Juan Basin

   $       92,300

Permian Basin

     162,150

Black Warrior Basin

     10,500

North Louisiana/East Texas

     25,300

Other

     17,350

Total

   $ 307,600

As of December 31, 2007, Energen Resources had approximately $28 million of unproved leaseholds costs related to its lease position in Alabama shale. As of February 25, 2008, Energen Resources’ net acreage position in Alabama shale totaled approximately 287,500 acres and represents multiple shale opportunities. In 2008, the Company will begin a 5 to 10 well test program. The Company has not included in its capital spending estimates discussed above any amounts associated with exploratory drilling and/or future potential development for the Alabama shale position.

Energen anticipates having the following drilling rigs and net wells by area during 2008. The drilling rigs presented below are operated while the net wells include operated and non-operated wells.

 

     Drilling Rigs    Net Wells

San Juan Basin

   6    67

Permian Basin

   4 - 5    209

Black Warrior Basin

   1-2    31

North Louisiana/East Texas

   2    10

Total

   13 - 15    317

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional accelerated development of existing properties and the exploration and further development of potential shale acreage primarily in Alabama. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above.

To finance capital spending at Energen Resources, the Company primarily expects to use internally generated cash flow supplemented by its short-term 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.

Energen also plans to consider stock repurchases as a capital investment. In May 2006, Energen began a buy-back of its common stock under an existing stock repurchase plan. In June 2006, the Company’s Board of Directors authorized an additional 9 million shares of common stock for repurchase. Energen may buy shares from time to time on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. During 2006, the Company purchased 2.2 million shares at an average price of $39.08 per share. The Company did not repurchase shares of common stock for this program during 2007. The Company plans to continue utilizing internally generated cash flow to fund any future stock repurchases. During 2008, the Company anticipates purchasing approximately $27 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company plans to utilize internally generated cash flows to fund these purchases of common stock.

Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, increased finding and development costs, higher workover and maintenance expenses, increased taxes and other field-service-related expenses. The Company anticipates influences such as weather, natural disasters, changes in global economics and political unrest will continue to contribute to increased commodity price volatility in the near term. Commodity price volatility will affect the Company’s revenue and associated cash flow available for investment.

 

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Alagasco’s use of commodity price hedges for a portion of its gas supply needs is reflected in the utility’s current rates. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (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 gains and losses. Sustained higher natural gas prices may decrease Alagasco’s customer base and could result in a further decline of per customer use and number of customers. The utility will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are impacted by natural gas prices.

Alagasco maintains an investment in storage gas that is expected to average approximately $65 million in 2008 but may vary depending upon the price of natural gas. During 2008 and 2009, Alagasco plans to invest approximately $69 million and $79 million, respectively, in utility capital expenditures for normal distribution and support systems. The utility anticipates funding these capital requirements through internally generated cash flow and the utilization of short-term credit facilities. Alagasco issued $45 million in long-term debt with an interest rate of 5.9% in January 2007 and redeemed $34.4 million of 6.75% Notes maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026 in the same period in order to capitalize on lower interest rates.

Access to capital is an integral part of the Company’s business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. On September 25, 2007, Moody’s Investors Service (Moody’s) downgraded the debt rating of Energen to Baa3 senior unsecured from Baa2. Energen’s debt rating of Baa3 remains investment grade and reflects Moody’s assignment of increased exposure to the Company related to the growth of its oil and gas operations. Moody’s also confirmed the debt rating of Alagasco during this review as A1 senior unsecured. On October 31, 2007, Standard & Poor’s affirmed its BBB+ corporate credit rating on Energen and Alagasco; the outlook remained stable. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued access could be adversely affected by future economic and business conditions and credit rating downgrades. To help finance its growth plans and operating needs, the Company currently has available short-term credit facilities aggregating $415 million of which Energen has available $255 million, Alagasco has available $110 million and $50 million is available to either Company. At December 31, 2007, Energen and Alagasco had borrowings of $72 million and $62 million, respectively on its short-term credit facilities.

Dividends

Energen expects to pay annual cash dividends of $0.48 per share on the Company’s common stock in 2008. 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.

On April 27, 2005, Energen’s shareholders approved a 2-for-1 split of the Company’s common stock. The split was effected in the form of a 100 percent stock dividend and was effective on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split.

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, 2007.

 

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       Payments Due before December 31,

(in thousands)

     Total      2008      2009-2010      2011-2012     
 
2013 and
Thereafter

Short-term debt

   $     134,000    $     134,000    $ -    $ -    $ -

Long-term debt (1)

     573,467      10,000      150,000      6,000      407,467

Interest payments on debt

     446,010      37,300      72,945      50,050      285,715

Purchase obligations (2)

     178,400      50,964      89,450      17,751      20,235

Capital lease obligations

     -      -      -      -      -

Operating leases

     46,147      4,128      8,092      7,339      26,588

Asset retirement obligations (3)

     491,444      5,069      7,311      2,106      476,958

Nonqualified supplemental
retirement plans

     35,111      3,126      4,811      4,711      22,463

Total contractual cash obligations

   $     1,904,579    $     244,587    $     332,609    $     87,957    $     1,239,426

 

(1)

Long-term cash obligations include $1.1 million of unamortized debt discounts as of December 31, 2007.

(2)

Certain of the Company’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of $178 million through October 2015. 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 135.2 Bcf through April 2015.

(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.

The Company has two defined non-contributory pension plans and provides certain postretirement healthcare and life insurance benefits. The Company is not required to make any funding payments during 2008 for the pension plans and does not currently plan to make discretionary contributions. The Company expects to make discretionary payments of approximately $2.2 million to postretirement benefit program assets during 2008. 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 $8.5 million recognized under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” (FIN 48) 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.

OUTLOOK

Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2008 and 2009 as outlined above. Production in 2008 is estimated to be 102 Bcfe, including approximately 100 Bcfe of estimated production from proved reserves owned at December 31, 2007. In 2009, production is estimated to be 108 Bcfe, including approximately 100 Bcfe produced from proved reserves currently owned. Production estimates above do not include amounts for potential future acquisitions or Alabama shale.

Production volumes by area are expected to be as follows:

 

Years Ended December 31, (Bcfe)

   2008        2009    

San Juan Basin

   50    54

Permian Basin

   30    34

Black Warrior Basin

   14    14

North Louisiana/East Texas

   8    6

Total

   102    108

During 2008 and 2009, Energen Resources expects an annualized decline rate of approximately 7 percent for its proved developed producing properties owned at December 31, 2007. During the same period, total production from proved properties is expected to increase approximately 1 percent and total production is expected to increase approximately 4 percent. Total production estimates do not include any production associated with the Alabama shale position.

 

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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. Energen Resources’ major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, national supply and demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas.

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. The four largest oil, natural gas and natural gas liquids purchasers account for approximately 22 percent, 14 percent, 11 percent and 10 percent, respectively, of Energen Resources’ estimated 2008 production. Energen Resources’ other purchasers each bought less than 8 percent of production.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company. At December 31, 2007, 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 three of its counterparties and a net loss with the remaining four. The Company believes the creditworthiness of these counterparties is satisfactory. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge this production more than two years forward. Production may be hedged for a longer period immediately following an acquisition in order to protect targeted returns.

Energen Resources entered into the following transactions for 2008 and subsequent years:

 

Production

Period

  

Total Hedged

Volumes

  

Average Contract

Price

   Description
Natural Gas               
        2008    30.8 Bcf    $8.53 Mcf    NYMEX Swaps
        2008    18.8 Bcf    $7.53 Mcf    Basin Specific Swaps
        2009    24.7 Bcf    $7.81 Mcf    Basin Specific Swaps
        2009    *14.2 Bcf    $8.55 Mcf    NYMEX Swaps
        2009    *4.9 Bcf    $7.55 Mcf    Basin Specific Swaps
Natural Gas Basis Differential
        2008    12.0 Bcf    **    Basis Swaps
Oil               
        2008    3,203 MBbl    $70.17 Bbl    NYMEX Swaps
        2009    2,460 MBbl    $71.03 Bbl    NYMEX Swaps
        2009    *240 MBbl    $92.38 Bbl    NYMEX Swaps
        2010    720 MBbl    $81.20 Bbl    NYMEX Swaps
Oil Basis Differential               
            2008    2,483 MBbl    **    Basis Swaps
            2009    1,980 MBbl    **    Basis Swaps
            2009    *156 MBbl    **    Basis Swaps
Natural Gas Liquids               
            2008    47.8 MMGal    $0.96 Gal    Liquids Swaps
            2009    20.2 MMGal    $1.05 Gal    Liquids Swaps

 

*

Contracts entered into subsequent to December 31, 2007

**

Average contract prices not meaningful due to the varying nature of each contract

 

 

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The Company 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, 2007, the Company was in a net loss position of $110.6 million for derivative contracts and estimates that a 10 percent increase or decrease in the commodities prices would have resulted in a $116.8 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.

Natural Gas Distribution: The extension of RSE in December 2007 provides Alagasco the opportunity to continue earning an allowed ROE between 13.15 percent and 13.65 percent through December 31, 2014. Under the terms of that extension, RSE will continue beyond that date, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue its operations. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. Also as discussed in Note 2, Regulatory Matters, in the Notes to Financial Statements, the utility’s CCM is based on the rate of inflation. Continued low inflation and significantly higher gas prices resulting in increased bad debt expense could impact the utility’s ability to manage its O&M expense sufficiently for the inflation-based cost control requirements of RSE and may result in an average return on equity lower than the allowed range of return. In addition, continued decreases in residential customers and continued declines in use per customer in the residential and small commercial classes will make it more difficult for the utility to earn within its allowed range of return on equity. The utility continues to rely on rate flexibility to deter bypass of its distribution system by large industrial and commercial customers.

As required by SFAS No. 133, Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability as required by SFAS No. 71. At December 31, 2007, Alagasco recorded a $0.4 million loss as a liability in accounts payable with a corresponding current regulatory asset representing the fair value of derivatives. The gains or losses related to these derivative contracts, as adjusted for any changes in the fair value, will be recognized in the GSA during the first quarter of 2008.

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 managements’ most subjective or complex judgments regarding estimates and projected outcomes of future events that could have a material impact on the financial statements.

Oil and Gas Operations

Accounting for Natural Gas and Oil Producing Activities and Related Reserves: The Company utilizes the successful efforts method of accounting for its natural gas and oil producing activities. Under this accounting method, 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

 

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demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have reviewed 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, 2007. 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 undeveloped reserves requires the installation or completion of related infrastructure facilities such as pipelines and the drilling of development wells.

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 2008 depreciation, depletion and amortization expense associated with an assumed downward revision in the reported oil and gas reserve amounts at December 31, 2007:

 

     Percentage Change in Oil & Gas Reserves

From Reported Reserves as of December 31, 2007

(dollars in thousands)

   -5%   -10%

Estimated increase in DD&A expense for the
year ended December 31, 2008, net of tax

   $    3,900   $    8,200

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, generally on a field-by-field basis, using the estimated undiscounted future cash flows of each field. 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.

Energen Resources adheres to Statement of Financial Accounting Standards (SFAS) No.19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relates to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by 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.

 

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Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended requires all derivatives to be recognized on the balance sheet and measured at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources may also enter into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred.

Natural Gas Distribution

Regulated Operations: Alagasco applies SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to its regulated operations. This standard requires a cost to be capitalized as a regulatory asset 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, SFAS No. 71 requires the cost to be recognized as a regulatory liability. The Company anticipates SFAS No. 71 will continue as the applicable accounting standard for its regulated operations. Alagasco’s rate setting methodology, Rate Stabilization and Equalization, has been in effect since 1983.

Consolidated

Employee Benefit Plans: In December 2006, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)” (SFAS No. 158). This Standard retains the previous periodic expense calculation on an actuarial basis under the provisions of SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other than Pensions.” In addition, SFAS No. 158 requires an employer 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. As required by SFAS No. 158 as of December 31, 2006, the pension benefit obligation is the projected benefit obligation (PBO), a measurement of earned benefit obligations at expected retirement salary levels; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation (APBO), a measurement of earned postretirement benefit obligations expected to be paid to employees upon retirement. Prior to implementation of SFAS No. 158, the required pension benefit obligation was the accumulated benefit obligation (ABO), a measurement of earned benefit obligations at existing salary levels, and other postretirement obligations were not recorded as a liability on the statement of financial position. Alagasco established a regulatory asset for the portion of the total benefit obligation to be recovered through rates in future periods in accordance with SFAS No. 71.

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

In selecting the discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments; the discount rate used to determine net periodic costs was 5.77 percent for each of the plans for the year ended December 31, 2007. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions; the return on assets used to determine net periodic expense was 8.25 percent for each of the applicable plans for the year ended December 31, 2007. The estimated weighted average rate of increase in the compensation level for pay related plans was 4.2 percent for the year ended December 31, 2007.

 

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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, 2007:

 

(in thousands)

   Pension
Expense
   Postretirement

Expense

Discount rate change

   $      900        $      100            

Return on assets

   $      400        $      200            

Compensation increase

   $      700        $          -            

The weighted average discount rate, return on plan assets and estimated rate of compensation increase used in the 2008 actuarial assumptions is 6.18 percent, 8.25 percent, and 4.07 percent, respectively.

Asset Retirement Obligation: The Company records the fair value of a liability for an asset retirement obligation (ARO) 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: As of January 1, 2007, the Company accounts for uncertain tax positions in accordance with the provisions of FIN 48. 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 position is provided in Note 17, Recent Pronouncements of the Financial Accounting Standards Board, in the Notes to the Financial Statements.

FORWARD-LOOKING STATEMENTS

Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company’s 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.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, our ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.

Third Party Facilities: The forward looking statements also assume generally uninterrupted access to third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities

 

35


for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company.

Energen Resources’ Production and Drilling: 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 acquisition, development 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.

Energen Resources’ Hedging: Although Energen Resources makes use of futures, swaps 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 and fixed price contracts. A substantial failure to meet sales volume targets whether caused by miscalculations, weather events, natural disaster, accident, 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.

Alagasco’s Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position.

Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of 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. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows.

Alagasco’s Service Territory: 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.

 

36


RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)

The Company adopted the provisions of FIN 48 as of January 1, 2007. This Interpretation prescribed a recognition threshold and measurement attribute for the financial statement recognition, measurement and disclosure of a tax position taken or expected to be taken in a tax return. As a result of the implementation of FIN 48, the Company recognized an approximate $1.2 million increase in the liability for unrecognized tax benefits which was accounted for as a decrease to the January 1, 2007 balance of retained earnings. As of the date of adoption and after the impact of recognizing the increase in liability noted above, the Company’s unrecognized tax benefits totaled $8.2 million. The amount of unrecognized tax benefits at January 1, 2007 that would favorably impact the Company’s effective tax rate, if recognized, was $3.4 million. The Company recognized potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. As of January 1, 2007, the Company recognized approximately $484,000 in potential interest (net of tax benefit) and penalties associated with uncertain tax positions.

During September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which clarifies that fair value should be based on the assumptions market participants would use when pricing an asset or a liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS No. 157, fair value measurements would be separately disclosed by level within the fair value hierarchy effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of this Statement. In February 2008, the FASB announced it will issue Final FASB Staff Positions (FSP’s) that will partially defer the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities and remove certain leasing transactions from the scope of SFAS No. 157. The Company will evaluate the impact of the FSP’s upon issuance.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to measure financial instruments and certain other items at fair value to mitigate volatility in reported earnings. This Statement is effective for fiscal years beginning after November 15, 2007. The effect of this Standard on the Company is currently being evaluated.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations,” which will improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first fiscal year beginning on or after December 15, 2008. The Company is currently evaluating the impact of this Statement.

The FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51,” in December 2007. SFAS No. 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest, and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The effect of this Standard on the Company is currently being evaluated.

 

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.

 

37


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

   39
  

Consolidated Statements of Income for the years ended December 31, 2007, 2006 and 2005

   41
  

Consolidated Balance Sheets as of December 31, 2007 and 2006

   42
  

Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2007, 2006 and 2005

   44
  

Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005

   45
  

Notes to Financial Statements

   51
  

Alabama Gas Corporation

  
  

Report of Independent Registered Public Accounting Firm

   40
  

Statements of Income for the years ended December 31, 2007, 2006 and 2005

   46
  

Balance Sheets as of December 31, 2007 and 2006

   47
  

Statements of Shareholder’s Equity for the years ended December 31, 2007, 2006 and 2005

   49
  

Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005

   50
  

Notes to Financial Statements

   51

2.

  

Financial Statement Schedules

  
  

Energen Corporation

  
  

Schedule II - Valuation and Qualifying Accounts

   85
  

Alabama Gas Corporation

  
  

Schedule II - Valuation and Qualifying Accounts

   85

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.

 

38


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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 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, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, appearing on Management’s Report on Internal Control Over Financial Reporting 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.

As discussed in Note 17, Recent Pronouncements of the Financial Accounting Standards Board, and Note 5, Employee Benefit Plans, in the Notes to Financial Statements, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” and Statement of Financial Accounting Standard (SFAS) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)”, effective January 1, 2007 and December 31, 2006, respectively.

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

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

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 25, 2008

 

39


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

In our opinion, the financial statements of Alabama Gas Corporation listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007 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. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 5, Employee Benefit Plans, in the Notes to Financial Statements, the Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R)”, effective December 31, 2006.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

February 25, 2008

 

40


CONSOLIDATED STATEMENTS OF INCOME

Energen Corporation

 

Years ended December 31, (in thousands, except share data)

     2007       2006       2005  

Operating Revenues

      

Oil and gas operations

   $ 825,592     $ 730,542     $ 527,694  

Natural gas distribution

     609,468       663,444       600,700  

Total operating revenues

     1,435,060       1,393,986       1,128,394  

Operating Expenses

      

Cost of gas

     318,429       373,097       315,622  

Operations and maintenance

     333,443       302,157       268,727  

Depreciation, depletion and amortization

     161,377       142,086       131,691  

Taxes, other than income taxes

     95,831       95,727       93,983  

Accretion expense

     3,948       3,619       2,647  

Total operating expenses

     913,028       916,686       812,670  

Operating Income

     522,032       477,300       315,724  

Other Income (Expense)

      

Interest expense

     (47,100 )     (48,652 )     (46,800 )

Other income

     2,668       951       2,163  

Other expense

     (959 )     (1,046 )     (710 )

Total other expense

     (45,391 )     (48,747 )     (45,347 )

Income From Continuing Operations Before Income Taxes

     476,641       428,553       270,377  

Income tax expense

     167,429       155,030       97,491  

Income From Continuing Operations

     309,212       273,523       172,886  

Discontinued Operations, Net of Taxes

      

Income (loss) from discontinued operations

     3       (6 )     (6 )

Gain on disposal of discontinued operations

     18       53       132  

Income From Discontinued Operations

     21       47       126  

Net Income

   $ 309,233     $ 273,570     $ 173,012  

Diluted Earnings Per Average Common Share

      

Continuing operations

   $ 4.28     $ 3.73     $ 2.35  

Discontinued operations

     -       -       -  

Net Income

   $ 4.28     $ 3.73     $ 2.35  

Basic Earnings Per Average Common Share

      

Continuing operations

   $ 4.32     $ 3.77     $ 2.37  

Discontinued operations

     -       -       -  

Net Income

   $ 4.32     $ 3.77     $ 2.37  

Diluted Average Common Shares Outstanding

     72,180,861       73,278,277       73,714,602  

Basic Average Common Shares Outstanding

     71,591,551       72,504,897       73,051,903  

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

 

41


CONSOLIDATED BALANCE SHEETS

Energen Corporation

 

     December 31,                December 31,            

(in thousands)

   2007                2006            

ASSETS

           

Current Assets

           

Cash and cash equivalents

      $            8,687       $        10,307

Accounts receivable, net of allowance for doubtful accounts of $12,244 and $13,961 at December 31, 2007 and 2006, respectively

      254,154       329,766

Inventories, at average cost

           

Storage gas inventory

      78,064       68,769

Materials and supplies

      13,711       9,281

Liquified natural gas in storage

      3,502       3,766

Regulatory asset

      10,232       35,479

Deferred income taxes

      54,166       -

Prepayments and other

      26,514       32,211

Total current assets

        449,030         489,579

Property, Plant and Equipment

           

Oil and gas properties, successful efforts method

      2,530,049       2,163,065

Less accumulated depreciation, depletion and amortization

      664,290       559,059

Oil and gas properties, net

        1,865,759         1,604,006

Utility plant

      1,108,392       1,060,562

Less accumulated depreciation

      448,053       421,075

Utility plant, net

        660,339         639,487

Other property, net

        12,145         8,921

Total property, plant and equipment, net

        2,538,243         2,252,414

Other Assets

           

Regulatory asset

      32,238       38,385

Prepaid pension costs and postretirement assets

      20,054       19,975

Deferred charges and other

      40,088       36,534

Total other assets

        92,380         94,894

TOTAL ASSETS

        $    3,079,653         $    2,836,887

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

 

42


CONSOLIDATED BALANCE SHEETS

Energen Corporation

 

    December 31,                 December 31,                  

(in thousands, except share data)

  2007                 2006                  

LIABILITIES AND SHAREHOLDERS’ EQUITY

        

Current Liabilities

        

Long-term debt due within one year

    $            10,000        $        100,000  

Notes payable to banks

    134,000        58,000  

Accounts payable

    259,836        194,448  

Accrued taxes

    40,857        42,960  

Customers’ deposits

    21,425        21,094  

Amounts due customers

    20,534        14,382  

Accrued wages and benefits

    25,410        24,548  

Regulatory liability

    32,154        33,871  

Deferred income taxes

    -        5,594  

Other

    62,014        65,985  
         

Total current liabilities

    606,230        560,882  
         

Long-term debt

      562,365          582,490  

Deferred Credits and Other Liabilities

        

Asset retirement obligation

    60,571        53,980  

Pension liabilities

    31,985        32,504  

Regulatory liability

    141,123        135,466  

Deferred income taxes

    238,706        250,906  

Other

    60,015        18,590  
         

Total deferred credits and other liabilities

      532,400          491,446  

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, 74,190,786 shares issued at December 31, 2007 and 73,699,244 shares issued at December 31, 2006

    742        737  

Premium on capital stock

    434,999        412,989  

Capital surplus

    2,802        2,802  

Retained earnings

    1,119,816        844,880  

Accumulated other comprehensive gain (loss), net of tax

        

Unrealized gain (loss) on hedges

    (65,057 )      50,555  

Pension and postretirement plans, net of tax

    (21,167 )      (23,177 )

Deferred compensation plan

    16,121        13,956  

Treasury stock, at cost; 3,374,336 shares and 3,253,337 shares at December 31, 2007 and 2006, respectively

    (109,598 )      (100,673 )
         

Total shareholders’ equity

      1,378,658          1,202,069  

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY

      $      3,079,653          $    2,836,887  

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

 

43


CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Energen Corporation

 

(in thousands, except share data)

  Common Stock   Premium on
Capital Stock
    Capital
Surplus
  Retained
Earnings
    Accumulated
Other
Comprehensive
Income (Loss)
    Deferred
Compensation
Restricted Stock
    Deferred
Compensation
Plan
    Treasury
Stock
    Total
Shareholders’
Equity
 
  Number of
Shares
  Par
Value
               

BALANCE DECEMBER 31, 2004

  73,165,958   $ 732   $ 380,965     $ 2,802   $ 459,626     $ (37,330 )   $ (2,675 )   $ 28,919     $ (29,373 )   $ 803,666  

Net income

            173,012               173,012  

Other comprehensive income (loss):

                   

Current period change in fair value of derivative instruments, net of tax of ($100,484)

              (163,947 )           (163,947 )

Reclassification adjustment, net of tax of $59,636

              97,301             97,301  

Minimum pension liability, net of tax of ($990)

              (1,843 )           (1,843 )
                         

Comprehensive income

                      104,523  
                         

Purchase of treasury shares

                    (2,459 )     (2,459 )

Shares issued for:

                   

Employee benefit plans

  327,379     3     8,958                 1,821       10,782  

Deferred compensation obligation

                  (17,012 )     17,012       —    

Issuance of restricted stock

                (1,249 )         (1,249 )

Amortization of restricted stock

                1,801           1,801  

Stock based compensation

        465                   465  

Tax benefit from employee stock plans

        2,487                   2,487  

Long-range performance plan

        1,986                   1,986  

Cash dividends - $0.40 per share

            (29,324 )             (29,324 )
                                                                       

BALANCE DECEMBER 31, 2005

  73,493,337     735     394,861       2,802     603,314       (105,819 )     (2,123 )     11,907     $ (12,999 )     892,678  

Net income

            273,570               273,570  

Other comprehensive income (loss):

                   

Current period change in fair value of derivative instruments, net of tax of $79,827

              130,244             130,244  

Reclassification adjustment, net of tax of $7,614

              12,423             12,423  

Pension and postretirement plans, net of tax of $3,062

              5,686             5,686  
                         

Comprehensive income

                      421,923  
                         

Adjustment to initially apply SFAS No. 158, net of tax of ($8,161)

              (15,156 )           (15,156 )

Purchase of treasury shares

                    (87,566 )     (87,566 )

Shares issued for:

                   

Employee benefit plans

  205,907     2     1,444                 1,941       3,387  

Deferred compensation obligation

                  2,049       (2,049 )     —    

Reclassification of restricted stock awards

        (2,123 )           2,123           —    

Amortization of restricted stock

        2,252                   2,252  

Stock based compensation

        196                   196  

Tax benefit from employee stock plans

        1,980                   1,980  

Long-range performance plan

        14,501                   14,501  

Forfeiture adjustment on stock plans

        (122 )                 (122 )

Cash dividends - $0.44 per share

            (32,004 )             (32,004 )
                                                                       

BALANCE DECEMBER 31, 2006

  73,699,244     737     412,989       2,802     844,880       27,378       —         13,956     $ (100,673 )     1,202,069  

Net income

            309,233               309,233  

Other comprehensive income (loss):

                   

Current period change in fair value of derivative instruments, net of tax of ($44,619)

              (72,800 )           (72,800 )

Reclassification adjustment, net of tax of ($26,239)

              (42,811 )           (42,811 )

Pension and postretirement plans, net of tax of $1,082

              2,009             2,009  
                         

Comprehensive income

                      195,631  
                         

Adjustment to initially apply FIN 48

            (1,181 )             (1,181 )

Purchase of treasury shares

                    (6,760 )     (6,760 )

Shares issued for:

                   

Employee benefit plans

  491,542     5     9,671                   9,676  

Deferred compensation obligation

                  2,165       (2,165 )     —    

Amortization of restricted stock

        891                   891  

Stock based compensation

        3,134                   3,134  

Tax benefit from employee stock plans

        10,937                   10,937  

Long-range performance plan

        (2,643 )                 (2,643 )

Forfeiture adjustment on stock plans

        20                   20  

Cash dividends - $0.46 per share

            (33,116 )             (33,116 )
                                                                       

BALANCE DECEMBER 31, 2007

  74,190,786   $ 742   $ 434,999     $ 2,802   $ 1,119,816     $ (86,224 )   $ —       $ 16,121     $ (109,598 )   $ 1,378,658  
                                                                       

Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.

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

 

44


CONSOLIDATED STATEMENTS OF CASH FLOWS

Energen Corporation

 

Years ended December 31, (in thousands)

  2007     2006     2005  

Operating Activities

             

Net income

    $ 309,233        $ 273,570        $ 173,012  

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

             

Depreciation, depletion and amortization

      161,377          142,086          131,719  

Deferred income taxes

      1,162          98,209          58,608  

Change in derivative fair value

      (970 )        (2,043 )        2,328  

Gain on sale of assets

      (506 )        (55,916 )        (1,928 )

Other, net

      20,035          4,255          (5,912 )

Net change in:

             

Accounts receivable, net

      71,810          9,249          (70,944 )

Inventories

      (13,461 )        1,084          (20,276 )

Accounts payable

      (74,927 )        64,178          39,330  

Amounts due customers

      21,247          (38,940 )        12,890  

Other current assets and liabilities

      (10,833 )        (12,812 )        16,297  
             

Net cash provided by operating activities

        484,167            482,920            335,124  

Investing Activities

             

Additions to property, plant and equipment

      (373,857 )        (302,177 )        (230,715 )

Acquisitions, net of cash acquired

      (56,323 )        (27,814 )        (179,268 )

Proceeds from sale of assets

      1,295          75,429          10,832  

Other, net

      (2,994 )        (2,337 )        (1,573 )
             

Net cash used in investing activities

        (431,879 )          (256,899 )          (400,724 )

Financing Activities

             

Payment of dividends on common stock

      (33,116 )        (32,004 )        (29,324 )

Issuance of common stock

      2,051          833          10,782  

Purchase of treasury stock

      -          (84,339 )        (2,459 )

Reduction of long-term debt

      (155,289 )        (15,898 )        (84,796 )

Proceeds from issuance of long-term debt

      45,000          -          160,000  

Debt issuance costs

      (494 )        -          (2,378 )

Net change in short-term debt

      76,000          (95,000 )        18,000  

Tax benefit on stock compensation

      10,937          1,980          -  

Other

      1,003          -          -  
             

Net cash provided by (used in) financing activities

        (53,908 )          (224,428 )          69,825  

Net change in cash and cash equivalents

      (1,620 )        1,593          4,225  

Cash and cash equivalents at beginning of period

      10,307          8,714          4,489  
             

Cash and cash equivalents at end of period

      $ 8,687          $ 10,307          $ 8,714  

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

 

45


STATEMENTS OF INCOME

Alabama Gas Corporation

 

Years ended December 31, (in thousands)

     2007               2006               2005          
       

Operating Revenues

   $ 609,468     $ 663,444     $ 600,700  

Operating Expenses

      

Cost of gas

     318,429       373,097       318,269  

Operations and maintenance

     129,351       126,948       126,041  

Depreciation

     47,136       44,244       42,351  

Income taxes

      

Current

     15,415       19,745       20,556  

Deferred

     6,221       2,257       1,804  

Taxes, other than income taxes

     41,810       44,881       41,117  
       

Total operating expenses

     558,362       611,172       550,138  
       

Operating Income

     51,106       52,272       50,562  

Other Income (Expense)

      

Allowance for funds used during construction

     611       951       792  

Other income

     1,665       1,490       1,371  

Other expense

     (868 )     (961 )     (701 )
       

Total other income

     1,408       1,480       1,462  

Interest Charges

      

Interest on long-term debt

     11,956       12,836       13,752  

Other interest charges

     3,740       3,618       1,308  
       

Total interest charges

     15,696       16,454       15,060  
       

Net Income

   $ 36,818     $ 37,298     $ 36,964  

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

 

46


BALANCE SHEETS

Alabama Gas Corporation

 

    December 31,     December 31,  

(in thousands)

  2007     2006  

ASSETS

   

Property, Plant and Equipment

   

Utility plant

  $        1,108,392     $    1,060,562  

Less accumulated depreciation

  448,053     421,075  
     

Utility plant, net

  660,339     639,487  

Other property, net

  157     163  

Current Assets

   

Cash

  7,335     8,765  

Accounts receivable

   

Gas

  139,761     159,101  

Other

  6,336     10,708  

Allowance for doubtful accounts

  (11,500 )   (13,200 )

Inventories, at average cost

   

Storage gas inventory

  78,064     68,769  

Materials and supplies

  3,866     4,199  

Liquified natural gas in storage

  3,502     3,766  

Regulatory asset

  10,232     35,479  

Deferred income taxes

  25,179     25,222  

Prepayments and other

  2,247     3,557  
     

Total current assets

  265,022     306,366  

Other Assets

   

Regulatory asset

  32,238     38,385  

Prepaid pension costs and postretirement assets

  15,831     15,369  

Deferred charges and other

  7,226     6,326  

Total other assets

  55,295     60,080  
     

TOTAL ASSETS

  $            980,813     $    1,006,096  

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

 

47


BALANCE SHEETS

Alabama Gas Corporation

 

     December 31,    December 31,

(in thousands, except share data)

   2007    2006

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, 2007 and 2006, respectively

   20    20

Premium on capital stock

   31,682    31,682

Capital surplus

   2,802    2,802

Retained earnings

   261,979    250,560
     

Total common shareholder’s equity

   296,483    285,064

Long-term debt

   208,467    208,756
     

Total capitalization

   504,950    493,820

Current Liabilities

     

Notes payable to banks

   62,000    58,000

Accounts payable

   80,067    118,936

Affiliated companies

   4,934    18,130

Accrued taxes

   30,858    37,813

Customers’ deposits

   21,425    21,094

Amounts due customers

   20,534    14,382

Accrued wages and benefits

   10,062    9,714

Regulatory liability

   32,154    33,871

Other

   10,417    8,225
     

Total current liabilities

   272,451    320,165

Deferred Credits and Other Liabilities

     

Deferred income taxes

   59,790    54,166

Regulatory liability

   141,123    135,466

Customer advances for construction and other

   2,499    2,479
     

Total deferred credits and other liabilities

   203,412    192,111
     

Commitments and Contingencies

     
     

TOTAL LIABILITIES AND CAPITALIZATION

   $    980,813    $    1,006,096

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

 

48


STATEMENTS OF SHAREHOLDER’S EQUITY

Alabama Gas Corporation

 

           

(in thousands, except share data)

                                   
   Common Stock             

 
 

Total

Shareholder’s
Equity

 

 
 

     Number of

Shares

    

 

Par

Value

    

 

Premium on

Capital Stock

    

 

Capital

Surplus

    

 

Retained

Earnings

 

 

 

Balance December 31, 2004

   1,972,052    $ 20    $ 31,682    $ 2,802    $ 223,515     $ 258,019  

Net income

                 36,964       36,964  

Cash dividends

                               (23,522 )     (23,522 )

Balance December 31, 2005

   1,972,052      20      31,682      2,802      236,957       271,461  

Net income

                 37,298       37,298  

Cash dividends

                               (23,695 )     (23,695 )

Balance December 31, 2006

   1,972,052      20      31,682      2,802      250,560       285,064  

Net income

                 36,818       36,818  

Cash dividends

                               (25,399 )     (25,399 )

Balance December 31, 2007

   1,972,052    $ 20    $ 31,682    $ 2,802    $ 261,979     $ 296,483  

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

 

49


STATEMENTS OF CASH FLOWS

Alabama Gas Corporation

 

       

Years ended December 31, (in thousands)

     2007                   2006                   2005              

Operating Activities

      

Net income

   $ 36,818     $ 37,298     $ 36,964  

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

      

Depreciation and amortization

     47,136       44,244       42,351  

Deferred income taxes

     6,221       2,257       1,804  

Other, net

     3,036       (5,019 )     (3,025 )

Net change in:

      

Accounts receivable, net

     19,501       37,260       (48,623 )

Inventories

     (8,698 )     2,384       (20,056 )

Accounts payable

     (27,702 )     1,240       24,560  

Amounts due customers

     21,247       (38,940 )     12,890  

Other current assets and liabilities

     (4,000 )     3,190       9,371  
       

Net cash provided by operating activities

     93,559       83,914       56,236  

Investing Activities

      

Additions to property, plant and equipment

     (58,154 )     (75,107 )     (72,388 )

Net advances from (to) parent company

     -       3,215       (1,025 )

Other, net

     (2,460 )     (1,963 )     (1,551 )
       

Net cash used in investing activities

     (60,614 )     (73,855 )     (74,964 )

Financing Activities

      

Payment of dividends on common stock

     (25,399 )     (23,695 )     (23,522 )

Reduction of long-term debt

     (45,289 )     (5,898 )     (84,796 )

Proceeds from issuance of long-term debt

     45,000       -       160,000  

Debt issuance costs

     (494 )     -       (2,252 )

Net advances from parent company

     (13,196 )     18,130       -  

Net change in short-term debt

     4,000       3,000       (27,000 )

Other

     1,003       -       -  
       

Net cash provided (used) by financing activities

     (34,375 )     (8,463 )     22,430  

Net change in cash and cash equivalents

     (1,430 )     1,596       3,702  

Cash and cash equivalents at beginning of period

     8,765       7,169       3,467  
       

Cash and cash equivalents at end of period

   $ 7,335     $ 8,765     $ 7,169  

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

 

50


NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

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

A. Principles of Consolidation

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

B. Oil and Gas Operations

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

Operating Revenue: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no material production imbalances at December 31, 2007 and 2006.

Derivative Commodity Instruments: Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company. In cases where these arrangements exist, the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Company’s credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company in the event credit ratings are below investment grade.

Energen Resources applies Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended which requires all derivatives be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is

 

51


recognized in other comprehensive income as a component of shareholders’ equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 are recorded at fair value with gains or losses recognized in operating revenues in the period of change. All derivative transactions are included in operating activities on the Consolidated Statements of Cash Flows.

Additionally, the Company may also enter into derivatives that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding NYMEX hedge, put options and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change.

All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness in hedging the exposure to the hedged transaction’s variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2010.

Long-Lived Assets and Discontinued Operations: The Company applies SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” which requires the Company to reflect gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale be reported 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 in accordance with SFAS No. 144. 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.

C. Natural Gas Distribution

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. 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 on the straight-line method over the estimated useful lives of utility property at rates established by the Alabama Public Service Commission (APSC). Approved depreciation rates averaged approximately 4.5 percent in the years ended December 31, 2007, 2006 and 2005.

Inventories: Inventories, which consist primarily of gas stored underground, are stated at average 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, 2007 and 2006.

 

52


Regulatory Accounting: Alagasco is subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” In general, SFAS No. 71 requires utilities to capitalize or defer certain costs or revenues, based upon approvals received from regulatory authorities, to be recovered from or refunded to customers in future periods.

Derivative Commodity Instruments: On December 4, 2000, the APSC authorized Alagasco to engage in energy-risk management activities. Accordingly, Alagasco may enter into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any 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 as required by SFAS No. 71.

Taxes on revenues: Collections and payments of excise taxes 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)

   2007    2006    2005

Taxes on revenues

   $    31,067    $    33,983    $    30,899

The collection and payment of utility gross receipts tax and utility service use tax are presented on a net basis.

D. Income Taxes

The Company uses the liability method of accounting for income taxes in accordance with SFAS No. 109, “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.

E. 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 reviews the allowance for doubtful accounts monthly. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.

F. Cash Equivalents

The Company includes highly liquid marketable securities and debt instruments purchased with a maturity of three months or less in cash equivalents.

G. Earnings Per Share

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 (see Note 9, Reconciliation of Earnings Per Share).

 

53


H. Stock-Based Compensation

The Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), using the modified prospective application method for new awards effective January 1, 2006. The Company previously adopted the fair value recognition provisions of SFAS No. 123 as amended, “Accounting for Stock-Based Compensation,” prospectively for stock-based compensation effective January 1, 2003. As a result, the adoption of SFAS No. 123R did not have a significant impact to the Company since the expensing provisions were voluntarily adopted in 2003.

SFAS No. 123R requires that all share-based compensation awards be measured at fair value at the date of grant and expensed over the requisite vesting period. SFAS No. 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Prior to the adoption of SFAS No. 123R, the Company accounted for forfeitures upon occurrence. This change in method did not have a significant impact to the Company upon adoption of SFAS No. 123R.

The Company previously recognized all stock-based employee compensation expense over the stated vesting periods for each award. For awards granted prior to January 1, 2006, the Company recorded any unrecognized expense on the date of an employee’s retirement. For new awards granted to retirement eligible employees effective January 1, 2006, the Company began recognizing the entire compensation expense in the period of grant. If this method of expense recognition had been applied to all awards during 2007, 2006 and 2005, compensation expense would have been reduced by approximately $1.1 million, $2.1 million and $0.8 million, respectively. The Company utilized the long-form method of calculating the available pool of windfall tax benefit. For 2007 and 2006, the Company recognized an excess tax benefit of $10.9 million and $2 million related to its stock-based compensation.

The following table illustrates the effect on net income and diluted and basic earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, superseded by SFAS No. 123R, to all outstanding and unvested employee share-based awards during 2005:

 

Year ended December 31, (in thousands)

   2005                

Net income

  

As reported

   $    173,012  

Stock based compensation expense included in reported net income, net of tax

   8,131  

Stock based compensation expense determined under the fair value based method, net of tax

   (6,238 )

Pro forma

   $    174,905  

Diluted earnings per average common share

  

As reported

   $          2.35  

Pro forma

   $          2.37  

Basic earnings per average common share

  

As reported

   $          2.37  

Pro forma

   $          2.39  

I. 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, estimates of physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that SFAS No. 71 will continue as the applicable accounting standard for the Company’s regulated operations and estimates used in determining the Company’s obligations under its employee pension plans and asset retirement obligations. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

 

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J. 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.

2. REGULATORY MATTERS

 

All of Alagasco’s utility operations are conducted in the state of Alabama. Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended with modifications in 2007, 2002, 1996, 1990, 1987 and 1985. On December 21, 2007, the APSC extended Alagasco’s rate-setting methodology, RSE, with certain modifications as outlined below, for a seven-year period through December 31, 2014. Under the terms of the extension, RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes.

Alagasco’s allowed range of return on equity remains 13.15 percent to 13.65 percent throughout the term of the order. Under RSE the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, 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. As of September 30, 2007 and 2005, Alagasco had a $3.6 million and a $3.3 million pre-tax, respectively, reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. Under the provisions of RSE, corresponding reductions in rates for 2007 were effective October 1, 2007 and December 1, 2007, and for 2005 effective December 1, 2005, Alagasco did not have a reduction in rates related to the return on average equity for rate year ended 2006. A $12 million, $14.3 million and $15.8 million annual increase in revenues became effective December 1, 2007, 2006, and 2005, respectively.

Prior to the December 21, 2007 extension, RSE limited the utility’s equity upon which a return is permitted to 60 percent of total capitalization. Subsequent to the extension, the equity on which a return will be permitted will be phased down to 57 percent by December 31, 2008 and 55 percent by December 31, 2009.

Prior to the extension, under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense per customer fell within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment was required. If the change in O&M expense per customer exceeded the index range, three-quarters of the difference was returned to customers. To the extent the change was less than the index range, the utility benefited by one-half of the difference through future rate adjustments. The changes to the O&M expense cost control measurement subsequent to the extension are as follows: annual changes in O&M expense will be measured on an aggregate basis rather than per customer; the percentage change in O&M expense must fall within a range of 0.75 points above or below the percentage change in the index range; certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded for the cost control measurement calculation; the O&M expense base for measurement purposes will continue to be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the index range in two successive years, in which case the base for the following year will be set at the top of the index range.

Alagasco’s O&M expense fell within the index range for the rate years ended September 30, 2007 and 2005. The increase in O&M expense per customer was above the index range for the rate year ended September 30, 2006; as a result, the utility had a $1.5 million pre-tax decrease in revenues with the related rate reduction effective December 1, 2006.

Alagasco calculates a temperature adjustment to customers’ monthly bills to moderate the impact of departures from normal temperatures on Alagasco’s earnings. Adjustments to customers’ bills are made in the same billing

 

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cycle in which the weather variation occurs. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. This adjustment, however, is subject to regulatory limitations on increases to customers’ bills. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment such as the impact of wind velocity or cloud cover and the elasticity of demand as a result of higher commodity prices. 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.

The APSC approved an Enhanced Stability Reserve (ESR), beginning rate year 1998 with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on average equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR of no more than $40,000 monthly until the maximum funding level is achieved. ESR balances of $4 million at December 31, 2007 and 2006, respectively, are included in the consolidated financial statements. Subsequent to the 2007 extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR.

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 over approximately 23 years. At December 31, 2007 and 2006, the net acquisition adjustments were $8.1 million and $9.3 million, respectively.

3. LONG-TERM DEBT AND NOTES PAYABLE

 

Long-term debt consisted of the following:

     

(in thousands)

   December 31, 2007    December 31, 2006

Energen Corporation:

     

Medium-term Notes, Series A and B, interest ranging from
6.95% to 7.625%, for notes due July 15, 2008, to February 15, 2028

   $    315,000    $    325,000

5% Notes, due October 1, 2013

   50,000    50,000

Floating Rate Senior Notes

   -    100,000

Alabama Gas Corporation:

     

Medium-term Notes, Series A, interest of 7.57%, due September 20, 2011

   5,000    15,000

6.75% Notes

   -    34,445

5.20% Notes, due January 15, 2020

   40,000    40,000

5.70% Notes, due January 15, 2035

   38,467    39,311

5.368% Notes, due December 1, 2015

   80,000    80,000

5.90% Notes, due January 15, 2037

   45,000    -

Total

   573,467    683,756

Less amounts due within one year

   10,000    100,000

Less unamortized debt discount

   1,102    1,266

Total

   $    562,365    $    582,490

 

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

 

Years ending December 31, (in thousands)
          2008                        2009                        2010                        2011                        2012          
$    10,000    -    $    150,000    $    5,000    $    1,000

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

 

Years ending December 31, (in thousands)
          2008                        2009                        2010                        2011                        2012          
-    -    -    $    5,000    -

The Company is in compliance with the financial covenants under its various long-term debt agreements. Except as discussed below, debt covenants also address routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. The Company’s outstanding debt is subject to a cross default provision under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee. In the event Alagasco or Energen Resources had a debt default of more than $10 million it would also be considered an event of default by Energen under the 1996 Indenture. All of the Company’s debt is unsecured. No conditions exist under long-term debt agreements which could restrict the Company’s ability to pay dividends.

In May 2007, Energen voluntarily called $100 million Floating Rate Senior Notes due November 15, 2007. In April 2007, Energen voluntarily redeemed $10 million of Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026. Associated with this redemption, the Company incurred a call premium of 4.045%. In January 2007, Alagasco issued $45 million of long-term debt with an interest rate of 5.9% due January 15, 2037. Alagasco used these long-term debt proceeds to redeem the $34.4 million of 6.75% Notes, maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026.

As of December 31, 2007, the Company had short-term credit lines and other credit facilities with various financial institutions aggregating $415 million of which Energen had available $255 million, Alagasco had available $110 million and $50 million available to either Company for working capital needs. Alagasco has been authorized by the APSC to borrow up to $200 million at any one time outstanding under short-term lines of credit. As of December 31, 2007, the Company is in compliance with the financial covenants under the various short-term loan agreements. Certain of the Company’s credit facilities in the aggregate amount of $85 million, including $75 million for Energen and $10 million for Alagasco, have a covenant that the ratio of consolidated debt to consolidated capitalization will not exceed 0.65:1. The following is a summary of information relating to notes payable to banks:

 

(in thousands)

   December 31, 2007    December 31, 2006

Energen outstanding

   $        72,000    $                -

Alagasco outstanding

   62,000    58,000

Notes payable to banks

   134,000    58,000

Available for borrowings

   281,000    307,000

Total

   $      415,000    $    365,000

Energen maximum amount outstanding at any month-end

   $      134,000    $    117,000

Energen average daily amount outstanding

   $        67,734    $      63,658

Energen weighted average interest rates based on:

     

Average daily amount outstanding

   5.35%    5.32%

Amount outstanding at year-end

   4.64%    5.70%

Alagasco maximum amount outstanding at any month-end

   $        62,000    $      58,000

Alagasco average daily amount outstanding

   $        29,518    $      37,104

Alagasco weighted average interest rates based on:

     

Average daily amount outstanding

   5.39%    5.43%

Amount outstanding at year-end

   4.62%    5.70%

 

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Energen’s total interest expense was $47,100,000, $48,652,000 and $46,800,000 for the years ended December 31, 2007, 2006 and 2005, respectively. Total interest expense for Alagasco was $15,696,000, $16,454,000 and $15,060,000 for the years ended December 31, 2007, 2006 and 2005, respectively.

4. INCOME TAXES

 

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

 

Years ended December 31, (in thousands)

     2007      2006      2005

Taxes estimated to be payable currently:

        

Federal

   $     149,787    $ 47,799    $ 29,765

State

     16,480      9,022      6,078

Total current

     166,267      56,821      35,843

Taxes deferred:

        

Federal

     838      93,605      59,685

State

     324      4,604      1,963

Total deferred

     1,162      98,209      61,648

Total income tax expense from continuing operations

   $ 167,429    $     155,030    $     97,491

For the years ended December 31, 2007 and 2006, Energen recorded a current income tax expense of $12,000 and $29,000, respectively, related to income from discontinued operations. For the year ended December 31, 2005, Energen recorded a current income tax expense of $3,117,000 and a deferred tax benefit of $3,040,000 related to income from discontinued operations.

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

 

Years ended December 31, (in thousands)

     2007      2006      2005

Taxes estimated to be payable currently:

        

Federal

   $     13,604    $     17,472    $     18,430

State

     1,811      2,273      2,126

Total current

     15,415      19,745      20,556

Taxes deferred:

        

Federal

     5,510      1,999      1,597

State

     711      258      207

Total deferred

     6,221      2,257      1,804

Total income tax expense

   $ 21,636    $ 22,002    $ 22,360

 

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

 

 

Energen Corporation

(in thousands)

     December 31, 2007       December 31, 2006  
     Current       Noncurrent       Current       Noncurrent  

Deferred tax assets:

        

Minimum tax credit

   $ -     $             -     $ -     $ 1,267  

Unbilled and deferred revenue

     10,648       -       10,269       -  

Enhanced stability reserve and
other regulatory costs

     1,497       -       2,009       -  

Allowance for doubtful accounts

     4,567       -       5,216       -  

Insurance accruals

     2,564       -       2,693       -  

Compensation accruals

     8,655       -       8,460       -  

Inventories

     1,230       -       889       -  

Other comprehensive income

     23,995       27,275       -       17,017  

Gas supply adjustment accruals

     1,486       -       1,309       -  

State net operating losses and other
carryforwards

     -       3,024       -       2,698  

Other

     2,789       153       2,705       602