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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, 2004

|  |  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___

Commission

 

 

IRS Employer

File

 

State of

Identification

Number

Registrant

Incorporation

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 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 (Section 229.405 of this chapter) 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 an accelerated filer (as defined in Rule 12b-2 of the Act).

Energen Corporation YES X NO __

Alabama Gas Corporation YES__ NO X

Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2004:

Energen Corporation

$1,729,509,607

Indicate number of shares outstanding of each of the registrant's classes of common stock as of March 3, 2005:

Energen Corporation

 

36,632,497 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, 2005 (Part III, Item 10-13)

INDUSTRY GLOSSARY

For a more complete definition of certain terms defined below, 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. The differential commonly is related to factors such as product quality, location and contract pricing.

 

 

Basin-Specific

A type of derivative contract whereby the contract's settlement price is based on specific geographic basin indices.

 

 

Behind Pipe Reserves

Oil or gas reserves located above or below the currently producing zone(s) that cannot be extracted until a recompletion or pay-add occurs.

 

 

Cash Flow Hedge

The designation of a derivative instrument to reduce exposure to variability in cash flows from the forecasted sale of oil, gas or natural gas liquids production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale.

 

 

Collar

A financial arrangement that effectively establishes a price range for the underlying commodity. The producer bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price.

 

 

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.

 

 

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.

 

 

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.

 

 

Odorization

A characteristic odor added to natural gas 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.

 

 

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 or before 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.

 

 

Secondary Recovery

The process of injecting water, gas, etc., into a formation in order to produce additional oil otherwise unobtainable by initial recovery efforts.

 

 

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

2004 FORM 10-K ANNUAL REPORT

 

 

 

TABLE OF CONTENTS

 

 

 

 

 

Page

 

PART I

 

 

 

 

Item 1.

Business

4

Item 2.

Properties

10

Item 3.

Legal Proceedings

10

Item 4.

Submission of Matters to a Vote of Security Holders

10

PART II

 

 

 

Item 5.

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

12

Item 6.

Selected Financial Data

13

Item 7.

Management's Discussion and Analysis of Financial Condition and

Results of Operations

15

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

28

Item 8.

Financial Statements and Supplementary Data

29

Item 9.

Changes in and Disagreements With Accountants on Accounting and

Financial Disclosure

76

Item 9A.

Controls and Procedures

76

PART III

 

 

 

Item 10.

Directors and Executive Officers of the Registrants

78

Item 11.

Executive Compensation

78

Item 12.

Security Ownership of Certain Beneficial Owners and Management and

Related Stockholder Matters


78

Item 13.

Certain Relationships and Related Transactions

78

Item 14.

Principal Accountant Fees and Services

78

PART IV

Item 15.

Exhibits and Financial Statement Schedules

79

Signatures

84

 

 

 

 

 

 

 

 

 

 

(This page intentionally left blank.)

 

 

 

 

 

 

 

 

 

 

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

and Alabama Gas Corporation (Alagasco).

 

Forward-Looking Statement and Risk Factors: 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, 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.

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 Corporation, the Company's oil and gas subsidiary, 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.

Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas prices could materially affect the Company's financial position and 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 re sult 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.

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, 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 positio n.

Inherent in gas distribution activities 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 we maintain 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 and the Company's financial position, results of operations and cash flows. Our utility customers are geographically concentrated in central and north Alabama. Significant economic, weather or other events that adversely affec t 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 acquisition, development, 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, principally in central and north Alabama. Its two subsidiaries are Energen Resources Corporation and Alabama Gas Corporation (Alagasco).

Energen was incorporated in Alabama in 1978 in connection with the reorganization of its oldest subsidiary, 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 a public company in 1953. Energen Resources was formed in 1971 as a subsidiary of Alagasco and became a subsidiary of Energen in the 1978 reorganization.

On December 5, 2001, the Board of Directors of the Company approved a change in the Company's fiscal year end from September 30 to December 31, effective January 1, 2002. Alagasco retained a September 30 fiscal year end for rate-setting purposes.

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 provided 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 21, Industry Segment Information, in the Notes to Financial Statements.

Narrative Description of Business

General: Energen's oil and gas operations focus on increasing production and adding proved reserves through the acquisition and development of oil and gas properties. To a lesser extent, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. Substantially 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 2004, Energen Resources' proved oil and gas reserves totaled 1,554 billion cubic feet equivalent (Bcfe). Substantially all of these reserves are located in the San Juan Basin in New Mexico, the Permian Basin in west Texas and the Black Warrior Basin in Alabama. Approximately 81 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. Natural gas represents approximately 66 percent of Energen Resources' proved reserves, with oil representing approximately 21 percent and natural gas liquids comprising the balance.

Growth Strategy: Energen has operated for more than nine years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $1 billion in property acquisitions, $680 million in related development, and $95 million in exploration and related development. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2009, is currently expected to approximate $1.5 billion, the majority of which represents unidentified acquisitions and related development.

Energen Resources' approach to the oil and gas business calls for the company to pursue onshore North American property acquisitions which offer proved undeveloped (PUD) and/or behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers operated natural gas properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources does not preclude possible acquisitions of properties with varying characteristics that otherwise meet its investment requirements.

Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties' PUD and behind-pipe reserve potential as well as engaging in other activities. These activities include development well drilling, 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' 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 which increase the number of available drilling locations; changes in the economic or operating environments which allow previously uneconomic locations to be added; technological advances which make reserve locations available for development; successful development of existing PUD locations which reclassify adjacent probable locations to PUD locations; increased knowledge of field geology and engineering parameters relative to oil and gas reservoirs; and changes in management's inte nt to develop certain opportunities.

During the three years ended December 31, 2004, the Company's development efforts have added 379 Bcfe of proved reserves from the drilling of 867 gross development wells and 351 well recompletions and pay-adds. In 2004, Energen Resources' successful development wells and other activities added approximately 70 Bcfe of proved reserves. The company drilled 288 gross development wells, performed some 111 well recompletions and pay-adds, and conducted other operational enhancements in 2004. Energen Resources' production from continuing operations totaled 87.6 Bcfe in 2004 and is estimated to total 94 Bcfe in 2005, including 91 Bcfe of estimated production from proved reserves owned at December 31, 2004.

Risk Management: Energen Resources attempts to lower the risks associated with its oil and natural gas business. A key component of the company's efforts to manage risk is its acquisition versus exploration orientation and its preference for long-lived reserves. In pursuing an acquisition, Energen Resources 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. Typically, Energen Resources does not hedge more than 80 percent of its estimated annual production and does not hedge more than two fiscal years forward. In the case of an acquisition, Energen Resources may hedge further forward to protect targeted returns.

Statement of Financial Accounting Standards (SFAS) No. 133 (as amended), "Accounting for Derivative Instruments and Hedging Activities," 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 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 operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in 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 as operating revenues in earnings in the period of ch ange.

The Company from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, 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.

See the Forward-Looking Statements and Risk Factors in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion with respect to price and other risks.

Environmental Matters: Energen Resources is subject to various environmental regulations. Management believes that Energen Resources is in compliance with currently applicable standards of the environmental agencies to which it is subject and anticipated environmental liabilities are minimal. To the extent that Energen Resources has operating agreements with various joint venture partners, environmental costs would be shared proportionately.

The State of New Mexico has recently issued new regulations related to below-grade storage pits. Such pits are used to temporarily hold produced fluids until they can be disposed of permanently. Under the new regulations, the storage pits must be constructed with secondary containment and leak detection, and all such pits will require an annual certification attesting that the storage pits do not leak. As a result of the new regulation, during 2004 the Company capitalized $0.5 million as part of its recent acquisition of properties in the San Juan Basin and expensed $1.6 million as a lease operating expense. The Company does not anticipate any further remediation charges on existing properties related to the new regulations.

Risk Factors: For a discussion of risks inherent in the Company's businesses, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

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 191 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 2004, Alagasco served an average of 425,673 residential customers and 35,248 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 9,965 miles of main and more than 11,651 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 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended RSE for a six-year period, through January 1, 2008. Under the APSC order, Alagasco's allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the returns on equity of all major energy utilities operating under a similar methodology. 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. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control 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 falls 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 is required. If the change in O &M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments.

The 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 substantially remove the effect 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, the impact of non-temperature weather conditions such as 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 th e 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.

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 200,000 additional thousand cubic feet per day (Mcfd) of natural gas to meet peak day demand.

As of December 31, 2004, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:

December 31, 2004

(Mcfd)

Southern firm transportation

154,892

Southern storage and no notice transportation

251,679

Transco firm transportation

100,000

Various intrastate transportation

21,240

 

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 deregulated 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 2004, approximately 300 of Alagasco's transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled more than $7.4 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 the 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 2004 substantially all of Alagasco's large commercial and industrial customer deliveries were 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 2004, 49 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 2004, Alagasco's average number of customers decreased slightly. For 2005, Alagasco will concentrate on maintaining its current penetration levels in the residential new construction market while increasing its focus on generating additional revenue in the small and large commercial and industrial market segments. Alagasco also will continue to pursue the purchase of municipal gas systems.

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 which substantially mitigates the effect of departures from normal temperature 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: 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, results of operations or cash flows.

Risk Factors: For a discussion of risks inherent in the Company's businesses, see Management's Discussion and Analysis of Financial Condition and Results of Operations as set forth in Item 7 of Part II of this Form 10-K.

Employees

The Company has 1,484 employees; Alagasco employs 1,196 and Energen Resources employs 288. The Company believes that its relations with employees are good.

ITEM 2. PROPERTIES

The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. Energen Resources maintains leased offices in Midland, Texas, in Farmington, New Mexico, in Oak Grove and Vance, Alabama and in Arcadia, Louisiana. For a description of Energen Resources' oil and gas properties, see the discussion under Item 1-Business. Information concerning Energen Resources' production and reserves is summarized in the table below and included in Note 20, Oil and Gas Operations (unaudited), included in the Notes to Financial Statements.

 

Year Ended

December 31, 2004

 

December 31, 2004

 

Production Volumes

(MMcfe)

Proved Reserves (MMcfe)

San Juan Basin

32,817

866,625

Permian Basin

28,691

377,055

Black Warrior Basin

16,743

232,964

North Louisiana/East Texas

8,885

72,492

Other

470

4,978

Total

87,606

1,554,114

The properties of Alagasco consist primarily of its gas distribution system, which includes more than 9,965 miles of main, more than 11,651 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, seven division offices, three payment centers, four district offices, nine service centers, and other related property and equipment, some of which are leased by Alagasco. For a further description of Alagasco's properties, see the discussion under Item 1-Business.

ITEM 3. LEGAL PROCEEDINGS

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

Various pending or threatened legal proceedings arising in the normal course of business are in progress currently and the Company has accrued a provision for estimated costs.

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 2004.

EXECUTIVE OFFICERS OF THE REGISTRANTS

Energen Corporation

Name

Age

Position (1)

Wm. Michael Warren, Jr.

57

Chairman of the Board, President and Chief Executive Officer (2)

Geoffrey C. Ketcham

54

Executive Vice President, Chief Financial Officer and Treasurer (3)

James T. McManus

46

President and Chief Operating Officer of Energen Resources (4)

Dudley C. Reynolds

52

President and Chief Operating Officer of Alagasco (5)

Grace B. Carr

49

Vice President and Controller (6)

J. David Woodruff, Jr.

48

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

 

Notes:      

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

(2) Mr. Warren has been employed by the Company in various capacities since 1983. In January 1992 he was elected President and Chief Operating Officer of Energen and all of its subsidiaries, in October 1995 he was elected Chief Executive Officer of Alagasco and Energen Resources, in February 1997 he was elected Chief Executive Officer of Energen and effective January 1, 1998, he was elected Chairman of the Board of Energen and each of its subsidiaries. Mr. Warren serves as a Director of Energen and each of its subsidiaries. He is also a Director of Protective Life Corporation.

(3) Mr. Ketcham has been employed by the Company in various financial and strategic planning capacities since 1981. He has served as Executive Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries since April 1991.

(4) 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.

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

(6) 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.

(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.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER OF PURCHASES OF EQUITY SECURITIES

Quarterly Market Prices and Dividends Paid Per Share

Quarter ended (in dollars)

High

Low

Close

Dividends Paid

March 31, 2002

26.49

21.69

26.45

.175

June 30, 2002

29.25

24.70

27.50

.175

September 30, 2002

27.53

21.65

25.31

.180

December 31, 2002

29.99

22.50

29.10

.180

March 31, 2003

32.06

28.08

32.06

.180

June 30, 2003

34.29

31.60

33.30

.180

September 30, 2003

37.09

31.35

36.18

.185

December 31, 2003

42.00

36.14

41.03

.185

March 31, 2004

44.72

39.87

41.25

.185

June 30, 2004

48.56

40.12

47.99

.185

September 30, 2004

51.95

45.86

51.55

.1925

December 31, 2004

60.07

50.87

58.95

.1925

 

Energen's common stock is listed on the New York Stock Exchange under the symbol EGN. On February 1, 2005, there were 7,566 holders of record of Energen's common stock. At the date of this filing, Energen Corporation owns all the issued and outstanding common stock of Alabama Gas Corporation.

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

 

 

Plan Category

 

Number of Securities to be Issued Upon Exercise of Outstanding Options

 

Weighted Average Exercise Price

 

Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans

Equity compensation plans approved by security holders

376,620

$26.47

1,393,886

Equity compensation plans not approved by security holders

-

-

-

Total

376,620

$26.47

1,393,886

 

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, 2004 through October 31, 2004

-

-

-

-

November 1, 2004 through November 30, 2004

636

$ 57.95

-

-

December 1, 2004 through December 31, 2004

258

$ 56.56

-

1,075,350

Total

894

$ 57.55

-

1,075,350

 

 

 

 

 

* Acquired in connection with tax withholdings on stock compensation plans.

** By resolution adopted May 24, 1994, and supplemented by a resolution adopted April 26, 2000, the Board of Directors authorized the Company to repurchase up to 1,782,200 shares of the Company's common stock. The resolutions do not have an expiration date.

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(dollars in thousands, except per share amounts)

Year Ended December 31, 2004

Year Ended December 31, 2003

Year Ended December 31, 2002

Three Months Ended December 31, 2001*

Year Ended September 30, 2001

Year Ended September 30, 2000

Year Ended September 30, 1999

INCOME STATEMENT

 

 

 

 

 

 

 

Operating revenues

$ 937,384

$ 842,221

$ 668,551

$ 143,632

$ 762,816

$ 542,012

$ 487,654

Income from continuing operations before cumulative effect of change in accounting principle

$ 127,450

$ 110,265

$ 70,396

$ 3,730

$ 62,417

$ 51,488

$ 41,729

Net income

$ 127,463

$ 110,654

$ 68,639

$ 3,658

$ 67,896

$ 53,018

$ 41,410

Diluted earnings per average common share from continuing operations before cumulative effect of change in accounting principle

 

$ 3.49

 

$ 3.09

 

$ 2.08

 

$ 0.12

 

$ 2.01

 

$ 1.70

 

$ 1.39

Diluted earnings per average common share

$ 3.49

$ 3.10

$ 2.03

$ 0.12

$ 2.18

$ 1.75

$ 1.38

BALANCE SHEET

 

 

 

 

 

 

 

Capitalization at year-end:

 

 

 

 

 

 

 

Common shareholders' equity

$ 803,666

$ 699,032

$ 582,810

$ 474,205

$ 480,767

$ 400,860

$ 361,504

Long-term debt

612,891

552,842

512,954

544,133

544,110

353,932

371,824

Total capitalization

$1,416,557

$1,251,874

$1,095,764

$1,018,338

$1,024,877

$ 754,792

$ 733,328

Total assets

$2,181,739

$1,778,232

$1,643,012

$1,342,346

$1,313,885

$1,286,341

$1,261,469

Property, plant and equipment, net

$1,783,059

$1,433,451

$1,351,554

$1,093,201

$1,084,052

$ 986,604

$ 933,333

COMMON STOCK DATA

 

 

 

 

 

 

 

Annual dividend rate at period-end

$ 0.77

$ 0.74

$ 0.72

$ 0.70

$ 0.70

$ 0.68

$ 0.66

Cash dividends paid per common share

$ 0.755

$ 0.73

$ 0.71

$ 0.175

$ 0.685

$ 0.665

$ 0.645

Book value per common share

$ 21.97

$ 19.30

$ 16.77

$ 15.18

$ 15.45

$ 13.21

$ 12.09

Market-to-book ratio at period-end (%)

268

213

174

162

145

225

167

Yield at period-end (%)

1.3

1.8

2.5

2.8

3.1

2.3

3.3

Return on average common equity (%)

17.1

17.1

12.4

13.0

15.8

13.7

11.7

Price-to-earnings (diluted) ratio at period-end

16.8

13.2

14.3

-

10.3

17.0

14.7

Shares outstanding at period-end (000)

36,583

36,224

34,745

31,249

31,125

30,351

29,904

Price Range:

 

 

 

 

 

 

 

High

$ 60.07

$ 42.00

$ 29.99

$ 25.20

$ 40.25

$ 30.38

$ 20.38

Low

$ 39.87

$ 28.08

$ 21.65

$ 21.50

$ 21.50

$ 14.69

$ 13.13

Close

$ 58.95

$ 41.03

$ 29.10

$ 24.65

$ 22.50

$ 29.75

$ 20.25

 

*On December 5, 2001, the Board of Directors of the Company approved a change in the Company's fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001, to December 31, 2001.

 

SELECTED BUSINESS SEGMENT DATA

 

 

 

 

 

Energen Corporation

 

 

 

(dollars in thousands)

Year Ended December 31, 2004

Year Ended December 31, 2003

Year Ended December 31, 2002

Three Months Ended December 31, 2001*

Year Ended September 30, 2001

Year Ended September 30, 2000

Year Ended September 30, 1999

OIL AND GAS OPERATIONS

 

 

 

 

 

 

 

Operating revenues from continuing operations

 

 

 

 

 

 

 

Natural gas

$ 276,972

$ 235,649

$ 145,935

$ 34,290

$ 132,554

$ 113,168

$ 113,219

Oil

98,413

87,200

72,758

11,128

43,880

36,143

33,779

Natural gas liquids

30,902

25,890

21,857

4,282

24,540

21,443

6,683

Other

4,357

4,383

3,570

(2,746)

7,980

5,097

8,419

Total

$ 410,644

$ 353,122

$ 244,120

$ 46,954

$ 208,954

$ 175,851

$ 162,100

Production volumes from continuing operations

 

 

 

 

 

 

 

Natural gas (MMcf)

57,257

55,433

46,060

11,454

44,071

45,557

51,105

Oil (MBbl)

3,434

3,412

3,016

464

1,873

1,983

2,823

Natural gas liquids (MMgal)

68.2

66.6

71.9

18.0

58.7

56.0

29.4

Production volumes from continuing operations (MMcfe)

87,606

85,422

74,424

16,801

63,690

65,459

72,243

Total production volumes (MMcfe)

87,606

86,157

77,973

18,022

68,478

70,482

77,159

Proved reserves

 

 

 

 

 

 

 

Natural gas (MMcf)

1,019,436

886,307

803,748

714,395

627,051

777,456

740,001

Oil (MBbl)

54,500

52,528

49,833

19,128

20,878

24,518

24,719

Natural gas liquids (MBbl)

34,613

27,245

26,697

25,944

24,931

26,007

21,937

Total (MMcfe)

1,554,114

1,364,945

1,262,928

984,827

901,905

1,080,605

1,019,937

Other data from continuing operations

 

 

 

 

 

 

 

Lease operating expense (LOE)

 

 

 

 

 

 

 

LOE and other

$ 79,265

$ 67,920

$ 57,141

$ 11,474

$ 49,273

$ 49,866

$ 53,441

Production taxes

37,322

27,731

18,254

3,387

22,833

16,536

10,677

Total

$ 116,587

$ 95,651

$ 75,395

$ 14,861

$ 72,106

$ 66,402

$ 64,118

Depreciation, depletion and amortization

$ 81,079

$ 79,687

$ 68,009

$ 15,317

$ 50,907

$ 53,499

$ 57,402

Capital expenditures

$ 403,936

$ 163,338

$ 305,476

$ 25,052

$ 136,886

$ 67,090

$ 198,577

Operating income

$ 180,612

$ 153,591

$ 76,286

$ 3,496

$ 66,416

$ 45,853

$ 31,541

NATURAL GAS DISTRIBUTION

 

 

 

 

 

 

 

Operating revenues

 

 

 

 

 

 

 

Residential

$ 340,229

$ 320,938

$ 277,088

$ 63,724

$ 367,109

$ 233,839

$ 209,263

Commercial and industrial-small

138,686

126,638

104,247

22,445

147,636

88,521

77,254

Transportation

40,221

38,250

38,395

9,765

33,972

35,312

34,541

Other

7,604

3,273

4,701

744

5,145

8,489

4,496

Total

$ 526,740

$ 489,099

$ 424,431

$ 96,678

$ 553,862

$ 366,161

$ 325,554

Gas delivery volumes (MMcf)

 

 

 

 

 

 

 

Residential

25,383

27,248

26,358

5,128

31,064

26,069

24,751

Commercial and industrial-small

12,323

12,564

11,838

2,193

14,054

12,092

11,662

Transportation

54,385

55,623

59,644

12,973

53,989

70,534

66,356

Total

92,091

95,435

97,840

20,294

99,107

108,695

102,769

Average number of customers

 

 

 

 

 

 

 

Residential

425,673

427,413

425,630

422,461

428,663

429,368

425,937

Commercial, industrial and transportation

35,248

35,463

35,601

35,161

35,882

35,526

35,111

Total

460,921

462,876

461,231

457,622

464,545

464,894

461,048

Other data

 

 

 

 

 

 

 

Depreciation and amortization

$ 39,881

$ 37,171

$ 33,682

$ 8,151

$ 30,933

$ 28,708

$ 26,730

Capital expenditures

$ 58,208

$ 57,906

$ 65,815

$ 12,873

$ 56,090

$ 67,073

$ 46,029

Operating income

$ 66,199

$ 66,848

$ 59,370

$ 8,034

$ 50,288

$ 49,063

$ 46,565

 

 

 

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

CRITICAL ACCOUNTING POLICIES

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:

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 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, 2004. The independent reservoir engineers have issued reports covering approximately 98 percent of the Company's ending proved reserves and in their judgment these estimates are 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 the estimated increase (decrease) in 2005 depreciation and depletion expense associated with assumed changes in oil and gas reserve quantities from the reported amounts at December 31, 2004.

Percentage Change in Oil & Gas Reserves

 

From Reported Reserves as of December 31, 2004

(dollars in thousands)

+10%

+5%

-5%

-10%

Estimated change in depreciation expense for the year ended December 31, 2005, net of tax

$ (4,700)

$ (2,500)

$ 3,000

$ 6,000

 

Asset Impairments: Oil and gas developed and undeveloped 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 betwe en 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.

Derivatives: Energen Resources from time to time enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. Statement of Financial Accounting Standard (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 from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period operating revenues, rather than in the period in which the hedge transacti on is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes.

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 Pension Plans: The Company calculates net periodic pension expense and liabilities on an actuarial basis under the provisions of SFAS No. 87, "Employers' Accounting for Pensions." The key assumptions used in determining these calculations are disclosed in Note 5. 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 defined benefit pension plans requires assumptions regarding the appropriate weighted average discount rate, estimated weighted average rate of increase in the compensation level of its employee base and the expected long-term rate of return on the plans' assets. The selection and use of such assumptions affects the amount of expense recorded in the Company's financial statements related to its defined benefit pension plans. The discount rate for pension cost purposes is the rate at which pension obligations coul d be effectively settled. The discount rate used for actuarial purposes covering a majority of employees was 6 percent for the year ended December 31, 2004. A hypothetical 25 basis point change in the discount rate would impact total pension expense by approximately $765,000. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The return on assets used for actuarial purposes was 8.75 percent for the year ended December 31, 2004. A hypothetical 25 basis point change in the return on assets would impact total pension expense by approximately $285,000. The estimated weighted average rate of increase in the compensation level of the Company's employees was 4 percent for the year ended December 31, 2004. A hypothetical 25 basis point change in the estimated rate of increase in the compensation level of applicable employees would impact total pension expense by approximately $525,000. The discount rate, return on plan assets and estimated rate of compensation incre ase used in the actuarial assumptions for 2005 is 5.75 percent, 8.5 percent, and 4 percent, respectively.

RESULTS OF OPERATIONS

Consolidated Net Income

Energen Corporation's net income for the year ended December 31, 2004 totaled $127.5 million, or $3.49 per diluted share and compared favorably to the year ended December 31, 2003 net income of $110.7 million, or $3.10 per diluted share. This 12.6 percent increase in earnings per diluted share (EPS) largely reflected the result of significantly higher prices for natural gas, oil and natural gas liquids as well as the impact of a 2.2 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen's oil and gas subsidiary, Energen Resources Corporation. For the year ended December 31, 2004, Energen Resources earned $94.1 million, as compared with $78.9 million in the previous year. Alabama Gas Corporation (Alagasco), Energen's utility subsidiary, generated a 2.3 percent increase in net income, earning $33.8 million in the current year as compared with net income in the prior period of $33 million. For the year ended December 31, 2002, Energen reported earnings of $68.6 m illion, or $2.03 per diluted share.

2004 vs 2003: Energen Resources' net income rose 19.2 percent to $94.1 million in 2004. Energen Resources' income from continuing operations before the cumulative effect of a change in accounting principle totaled $94.1 million in 2004 as compared with $78.5 million in 2003. Discontinued operations in 2004 generated minimal income as compared with income of $0.4 million in 2003. The primary factors positively influencing income from continuing operations included an increase of approximately $31 million after-tax in commodity prices along with the impact of increased production volumes of $6 million after-tax. Increased production volumes were largely due to the August 1, 2004, purchase of San Juan Basin coalbed methane properties from a private company and additional drilling of existing properties in the San Juan and Black Warrior basins. These increases were partially offset by higher lease operating expense of approximately $7 million after-tax, higher production taxes of approx imately $6 million after-tax and increased administrative expenses of approximately $4 million after-tax.

Alagasco earned net income of $33.8 million in 2004 as compared with net income of $33 million in 2003. This increase in earnings reflected the utility's ability to earn on a higher level of equity. Alagasco's return on average equity (ROE) was 12.8 percent in 2004 compared with 13.5 percent in 2003.

2003 vs 2002: For the year ended December 31, 2003, Energen Resources' net income totaled $78.9 million as compared with $41.2 million for the 12 months ended December 31, 2002. Energen Resources' income from continuing operations before the cumulative effect of a change in accounting principle totaled $78.5 million in 2003 as compared with $43 million in 2002, primarily due to higher commodity prices of approximately $44 million after-tax along with the impact of increased gas and oil production volumes of approximately $24 million after-tax. Increases were primarily due to a full year's production from the April 2002 acquisition of oil properties in the Permian Basin, a new gas project in the Permian Basin and a coalbed methane down-spacing program. The primary negative influences on income from continuing operations were higher lease operating expense of approximately $7 million after-tax, higher production taxes of approximately $6 million after-tax and increased depreciation, d epletion and amortization (DD&A) expense of approximately $7 million after-tax. Results from 2002 included a $5.7 million after-tax non-cash benefit associated with the Company's previous hedge position with Enron and the recognition of $14.2 million in nonconventional fuels tax credits. The ability to generate new credits ended December 31, 2002.

Alagasco earnings increased to $33 million in 2003 from $27.6 million in 2002 largely as a result of the utility earning on a higher level of equity. It also reflected the impact of timing differences between quarters related to revenue recovery under the utility's rate-setting mechanism. Alagasco achieved a ROE of 13.5 percent in 2003 compared with 12.3 percent in 2002.

Operating Income

Consolidated operating income in 2004, 2003 and 2002 totaled $245.1 million, $217.9 million and $134 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources under Energen's diversified growth strategy, implemented in fiscal 1996. Alagasco also contributed to this growth in operating income consistent with increases in the levels of equity upon which it has been able to earn a return.

Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of increased natural gas, oil and natural gas liquids prices, an increase in volumes related to the purchase of San Juan Basin coalbed methane properties and additional drilling of coalbed methane wells in the San Juan and Black Warrior basins. Realized gas prices increased 13.9 percent to $4.84 per thousand cubic feet (Mcf), realized oil prices rose 12.1 percent to $28.66 per barrel and natural gas liquids prices increased 15.4 percent to an average price of $0.45 per gallon during 2004. Production from continuing operations increased 2.6 percent to 87.6 Bcfe during 2004. Natural gas production rose 3.3 percent to 57.3 billion cubic feet (Bcf), oil volumes increased slightly to 3,434 thousand barrels (MBbl) and production of natural gas liquids increased 2.4 percent to 68.2 million gallons (MMgal).

In 2003, revenues from oil and gas operations increased primarily as a result of increased commodity prices, a full year's production from the 2002 acquisition of oil properties in the Permian Basin, a new project in the Permian Basin that produced gas which had previously been reinjected into the reservoir, acquisitions in the San Juan Basin and a coalbed methane down-spacing program. Including the prior-period non-cash benefit from the former Enron hedges, realized gas prices increased 34.1 percent to $4.25 per Mcf, realized oil prices rose 5.9 percent to $25.56 per barrel and natural gas liquids prices increased 30 percent to an average price of $0.39 per gallon during the year ended December 31, 2003. Production from continuing operations rose 14.8 percent to 85.4 Bcfe in 2003. Natural gas production increased 20.3 percent to 55.4 Bcf, oil volumes rose 13.1 percent to 3,412 MBbl and natural gas liquids production declined 7.3 percent to 66.6 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 $6.6 million, $6.1 million and $4.8 million in 2004, 2003 and 2002, respectively.

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

2004

2003

2002

Operating revenues from continuing operations

Natural gas

$ 276,972

$ 235,649

$ 145,935

Oil

98,413

87,200

72,758

Natural gas liquids

30,902

25,890

21,857

Operating fees

6,648

6,077

4,847

Other

(2,291)

(1,694)

(1,277)

Total operating revenues from continuing operations

$ 410,644

$ 353,122

$ 244,120

Production volumes from continuing operations

 

 

 

Natural gas (MMcf)

57,257

55,433

46,060

Oil (MBbl)

3,434

3,412

3,016

Natural gas liquids (MMgal)

68.2

66.6

71.9

Average sales price including effects of hedging

 

 

 

Natural gas (per Mcf)

$ 4.84

$ 4.25

$ 3.17

Oil (per barrel)

$ 28.66

$ 25.56

$ 24.13

Natural gas liquids (per gallon)

$ 0.45

$ 0.39

$ 0.30

Average sales price excluding effects of hedging

 

 

 

Natural gas (per Mcf)

$ 5.68

$ 4.97

$ 2.96

Oil (per barrel)

$ 38.33

$ 29.19

$ 24.82

Natural gas liquids (per gallon)

$ 0.59

$ 0.44

$ 0.30

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144,"Accounting for Impairment or Disposal of Long-Lived Assets," which was adopted as of January 1, 2002. Energen Resources had no property sales during 2004. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million. Energen Resources recorded in 2002 a pre-tax gain of $0.9 million in total income from discontinued operations from the sale of properties and adjustments to the fair value of properties being held-for-sale.

Operations and maintenance (O&M) expense increased $19 million and $10.8 million in 2004 and 2003, respectively. Lease operating expense (excluding production taxes) in 2004 increased by $11.3 million primarily due to increased workover and maintenance expense, costs associated with new regulatory requirements (see Note 7), and higher transportation costs. In 2003, lease operating expense (excluding production taxes) increased $10.8 million primarily due to the acquisition of oil and gas properties, higher operational costs driven both by market conditions as well as an increased number of wells and due to increased drilling activity in the coalbed methane down-spacing program. Administrative expense increased $7.2 million and $2.8 million in 2004 and 2003, respectively, primarily due to labor related costs and additional costs related to property acquisitions. In 2004, exploration expense increased $1 million due to increased exploratory efforts. Exploration expense decreased $2.5 mil lion in 2003 largely due to a $3.2 million pre-tax writedown of unproved leasehold costs recorded during 2002 partially offset by increased exploratory efforts.

DD&A expense increased $1.4 million in 2004 and $11.7 million in 2003. Increased production volumes were the primary contributor to the increase in DD&A during 2003. The average depletion rates were $0.91 per Mcfe in 2004, $0.92 per Mcfe in 2003 and $0.89 per Mcfe in 2002.

Energen Resources' expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes of $37.3 million, $27.7 million and $18.3 million for 2004, 2003 and 2002, respectively. Increased severance taxes were the result of increased commodity prices and production.

Natural Gas Distribution: As discussed more fully in Note 2, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend the utility's rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the company and a hearing, the Commission votes to either modify or discontinue its operation.

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 operating margins essentially remain unaffected due to 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 $526.7 million, $489.1 million and $424.4 million in 2004, 2003 and 2002, respectively. Sales revenue in 2004 and 2003 rose largely due to an increase in the commodity cost of gas. During 2004, weather that was 6 percent warmer than in the prior year contributed to a 6.8 percent decline in residential sales volumes and a 1.9 percent decrease in small commercial and industrial volumes. Large transportation volumes decreased 2.2 percent. In 2003, weather was comparable to the previous year. Residential sales volumes increased 3.4 percent and small commercial and industrial volumes increased 6.1 percent largely due to increased gas usage per customer. Transportation volumes declined 6.7 percent primarily due to higher gas prices which resulted in alternate fuel use partially offset by certain nonrecurring gas deliveries. Higher commodity gas cost generated a 10.9 percent and a 23.3 percent increase in cost of gas in 2004 and 200 3, respectively.

O&M expense at the utility increased 6.9 percent in 2004 and 4.6 percent in 2003 primarily due to increased labor-related costs. The increase in O&M expense per customer for the rate years ended September 30, 2004, 2003 and 2002 were above the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utility's rate-setting mechanism; as a result, three quarters of the differences, or $1.2 million, $0.1 million and $0.3 million pre-tax, respectively, were returned to the customers through RSE (see Note 2).

Depreciation expense rose 7.3 percent in 2004 due to normal growth of the utility's distribution system. Depreciation expense rose 10.4 percent in 2003 consistent with the growth in the utility's depreciable base and with the replacement of support systems with higher depreciation rates than the average rates applicable to the

distribution system. 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)

2004

2003

2002

Natural gas transportation and sales revenues

$ 526,740

$ 489,099

$ 424,431

Cost of natural gas

(261,800)

(236,037)

(191,479)

Operations and maintenance

(121,896)

(114,078)

(109,115)

Depreciation

(39,881)

(37,171)

(33,682)

Income taxes

(19,703)

(19,675)

(17,825)

Taxes, other than income taxes

(36,964)

(34,965)

(30,785)

Operating income

$ 46,496

$ 47,173

$ 41,545

Natural gas sales volumes (MMcf)

 

 

 

Residential

25,383

27,248

26,358

Commercial and industrial-small

12,323

12,564

11,838

Total natural gas sales volumes

37,706

39,812

38,196

Natural gas transportation volumes (MMcf)

54,385

55,623

59,644

Total deliveries (MMcf)

92,091

95,435

97,840

 

Non-Operating Items

Consolidated: Interest expense in 2004 increased $0.5 million largely due to the issuance of $100 million Floating Rate Senior Notes by Energen in November 2004, a full year's interest on $50 million of long-term debt issued by Energen in October 2003 and increased short-term borrowings due to the acquisition of San Juan Basin coalbed methane properties in August 2004. In 2003, interest expense decreased $1.5 million primarily due to a $32.1 million Energen equity issuance completed in July 2003, current maturities of long-term debt, lower short-term interest rates and the $50 million of long-term debt issued by Energen in October 2003. The average daily outstanding balance under short-term credit facilities was $92.6 million in 2004. The average daily outstanding balance under short-term credit facilities was $81.1 million in 2003 as compared to $85.6 million in 2002.

Income tax expense increased in 2004 primarily due to higher pre-tax income. Income tax expense increased in 2003 primarily due to higher pre-tax income and a higher effective tax rate. The Company's effective tax rate in 2002 was lower than the statutory federal tax rate primarily due to the recognition of nonconventional fuels tax credits. The Company recognized $14.2 million of nonconventional fuels tax credits in 2002. The Company's ability to generate nonconventional fuels tax credits on qualified production ended December 31, 2002, with the expiration of the credit. As of December 31, 2004, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $56.7 million.

FINANCIAL POSITION AND LIQUIDITY

The Company's net cash from operating activities totaled $291.2 million, $243.1 million and $213.5 million in 2004, 2003 and 2002, respectively. In 2004, operating cash flow benefited from higher realized commodity prices and higher production volumes at Energen Resources. The Company's working capital needs were also impacted by financing of oil and gas acquisitions and current liabilities associated with Energen Resources' hedge position. Working capital needs at Alagasco were primarily affected by refinancing of debt, storage gas inventory and gas costs compared to the prior period. Operating cash flow in 2003 benefited from increased realized commodity prices at Energen Resources. Working capital needs at Alagasco in 2003 were affected by increased gas costs resulting in higher storage inventory balances. 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 2004, the Company made net investments of $453.4 million. Energen Resources invested $274.4 million in property acquisitions, $124.6 million for development costs including approximately $89 million to drill 288 gross development wells and $5.1 million for exploration. On August 2, 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million adding approximately 245 Bcfe of proved reserves. Utility expenditures in 2004 totaled $58.2 million and primarily represented system distribution expansion and support facilities. During 2003, the Company made net investments of $190.4 million. Energen Resources invested $40.5 million in property acquisitions, $121.9 million for development costs including approximately $89 million to drill 347 gross development wells and $0.4 million for exploration. Energen Resources sold certain properties during 2003, resulting in cash proceeds of $29.1 million. Utility expen ditures in 2003 totaled $57.9 million. Cash used in investing activities totaled $268.2 million in 2002. Energen Resources invested $184.2 million for property acquisitions, $122.5 million for the development of proved properties and $0.1 million for exploration. In April 2002, Energen Resources completed its purchase of oil and gas properties located in the Permian Basin in west Texas from First Permian, L.L.C. (First Permian) for approximately $120 million in cash and 3,043,479 shares of the Company's common stock. The acquisition added 227 Bcfe of proved reserves. Energen Resources drilled 232 gross development wells for approximately $77 million and sold certain properties during 2002, resulting in cash proceeds of $17.1 million. Utility expenditures in 2002 totaled $65.8 million.

During 2004, the Company added approximately 245 Bcfe of reserves from the San Juan basin acquisition. Energen Resources expects this acquisition to contribute approximately $4 million, net of development costs, to pretax cash flows in 2005. Over the five-year period ending December 31, 2009, the Company expects this acquisition to contribute approximately $190 million, net of development costs, to pretax cash flows. Energen Resources added 70 Bcfe of reserves from discoveries and other additions primarily the result of unit downspacing that increased the number of available drilling locations for certain wells in the Black Warrior and San Juan basins as well as drilling and recompletions in the Permian basin. Energen Resources added approximately 236 Bcfe and 389 Bcfe of reserves in 2003 and 2002, respectively.

The Company provided $164.6 million from financing activities in 2004. In November 2004, Energen issued $100 million of Floating Rate Senior Notes due November 15, 2007. Long-term debt was reduced by $40.1 million, including Alagasco's election in April 2004 to call $30 million of Medium-Term Notes maturing January 16, 2006 to December 15, 2023. In 2003, net cash used in financing activities totaled $55.4 million. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration which generated net proceeds of $32.1 million. Energen issued $50 million of long-term debt in October 2003. Long-term debt was reduced by $23 million for current maturities in 2003. In 2002, net cash provided by financing activities totaled $53 million. The Company utilized $85.9 million in short-term credit facilities to finance Energen Resources' acquisition strategy. Long-term debt was reduced by $21.2 million, including the retirem ent of the Series 1993 Notes for $7.8 million. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders and the issuance of common stock through the dividend reinvestment and direct stock purchase plan as well as the employee savings plans.

Capital Expenditures

Oil and Gas Operations: Energen Resources spent a total of $879 million for capital projects during the years ended December 31, 2004, 2003 and 2002. Property acquisition expenditures totaled $499.1 million, development activities totaled $368.9 million, and exploratory expenditures totaled $5.6 million.

Years ended December 31, (in thousands)

2004

2003

2002

Capital and exploration expenditures for:

Property acquisitions

$ 274,400

$ 40,486

$ 184,177

Development

124,588

121,889

122,494

Exploration

5,036

397

104

Other

1,988

1,548

1,880

Total

406,012

164,320

308,655

Less exploration expenditures charged to income

2,076

982

3,179

Net capital expenditures

$ 403,936

$ 163,338

$ 305,476

 

 Natural Gas Distribution: During the years ended December 31, 2004, 2003 and 2002, Alagasco invested $181.9 million for capital projects: $123.8 million for normal expansion, replacements and support of its distribution system and $58.1 million for support facilities, including the replacement of liquifaction equipment and the development and implementation of information systems.

Years ended December 31, (in thousands)

2004

2003

2002

Capital and expenditures for:

Renewals, replacements, system expansion and other

$ 40,876

$ 39,883

$ 43,029

Support facilities

17,332

18,023

22,786

Total

$ 58,208

$ 57,906

$ 65,815

 

FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue to implement its diversified growth strategy that focuses on expanding Energen Resources' oil and gas operations through the acquisition of producing properties with development potential while maintaining the strength of the Company's utility foundation. For the five calendar years ended December 31, 2004, Energen's EPS grew at an average compound rate of 17.5 percent a year. Over the next five years, Energen is targeting an average diluted EPS growth rate over each rolling five-year period of approximately 7 to 8 percent a year.

Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2009 is estimated to be approximately $1.5 billion, with $1.3 billion for property acquisitions and related development, $220 million for other development and $24 million for exploratory and other activities. During the five year period, Energen Resources anticipates spending approximately $145 million on development of previously identified proved undeveloped reserves and incurring approximately $15 million in exploratory exposure. To finance Energen Resources' investment program, the Company expects primarily to utilize its short-term credit facilities to supplement internally generated cash flow.

The Company may periodically issue long-term debt and equity to replace short-term obligations, enhance liquidity and provide for permanent financing. Energen currently has available short-term credit facilities aggregating $287 million to help finance its growth plans and operating needs.

In November 2004, the Company issued $100 million of long-term debt. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. In October 2003, the Company issued $50 million of long-term debt. These proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.

In 2005, Energen Resources plans to invest approximately $331 million, including $200 million in property acquisitions, $7 million in related acquisition development and $124 million in other development and exploratory activities. Included in this $124 million is approximately $84 million for the development of previously identified proved undeveloped reserves and approximately $3 million of exploratory exposure. Capital investment at Energen Resources in 2006 is expected to approximate $215 million for property acquisitions, $37 million for related acquisition development and $55 million for other development and exploration. Of this $55 million, development of previously identified proved undeveloped reserves is estimated to be $30 million and exploratory exposure is estimated to be $3 million.

Energen Resources' continued ability to invest in property acquisitions will be influenced significantly by industry trends, as the producing property acquisition market historically has been cyclical. Notwithstanding the estimated expenditures mentioned above, as an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time may pursue acquisitions that meet Energen's acquisition criteria which could result in capital expenditures different than those outlined above. These acquisitions or negotiations to sell, trade or otherwise dispose of properties may alter the aforementioned financing requirements.

During 2005, Alagasco plans to invest approximately $59 million in utility capital expenditures for normal distribution and support systems. Alagasco maintains an investment in storage gas that is expected to average approximately $48 million in 2005 but may vary depending upon the price of natural gas. Alagasco plans to invest approximately $57 million in utility capital expenditures during 2006. Over the Company's five-year planning period ending December 31, 2009, Alagasco anticipates capital investments of approximately $293 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. In January 2005, Alagasco issued $80 million in long-term debt to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance the $30 million in Medium-Term Notes recalled by Alagasco in April 2004. Alagasco also may refinance existing long-term debt.

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. These agencies have recently evaluated the business and financial profiles of the Company in light of the announcement of the aforementioned San Juan coalbed methane gas acquisition and a continued business strategy that focuses on expanding the oil and gas operations through the acquisition of properties. On January 11, 2005, Standard & Poor's affirmed its A- corporate credit rating on Energen; the outlook remained negative. Alagasco's credit rating is A- with a negative outlook. On September 27, 2004, Moody's Investors Service downgraded the debt rating of Energen to Baa2 senior unsecured from Baa1 and confirmed the debt rating of Alagasco as A1 senior unsecured. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-te rm markets, continued access could be adversely affected by future economic and business conditions and credit rating downgrades.

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, 2004.

 

 

Payments Due before December 31,

(in thousands)

Total

2005

2006-2007

2008-2009

2010 and Thereafter

 

 

 

 

 

 

Short-term debt

$ 135,000

$ 135,000

$ -

$ -

$ -

Long-term debt (1)

624,450

10,000

122,000

15,000

477,450

Interest payments on debt (2)

524,216

39,680

75,740

67,538

341,258

Purchase obligations (3)

183,739

47,758

93,628

35,182

7,171

Capital lease obligations

-

-

-

-

-

Operating leases

53,888

3,857

7,616

6,604

35,811

Total contractual cash obligations

$ 1,521,293

$ 236,295

$ 298,984

$ 124,324

$ 861,690

(1) Long-term cash obligations include $1.6 million of unamortized debt discounts as of December 31, 2004.

(2) Includes interest on fixed rate debt and an estimate of adjustable rate debt. The adjustable rate interest is calculated based on the indexed rate in effect at December 31, 2004.

(3) Certain of the Company's long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of $183.7 million through October 2013. 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 52.2 Bcf through December 2014.

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.

Alagasco had an agreement with a financial institution whereby it could sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program. Alagasco no longer sells its installment receivables effective February 1, 2004. Receivables sold under this agreement were considered financial instruments with off-balance sheet risk. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. The fair value of these guarantees is not significant to the Company and is recorded as a non-current other liability as further described in Note 8.

The Company has two defined non-contributory pension plans and provides certain post-retirement healthcare and life insurance benefits. The Company is not required to make any funding payments during 2005 for the pension plans and does not currently plan to make discretionary contributions. The Company may reevaluate discretionary payments to its pension plans pending the outcome of the September 30, 2005, measurement of pension obligations. Additionally, the Company expects to make discretionary payments of $2.8 million to post-retirement benefit program assets during 2005.

OUTLOOK

Oil and Gas Operations: Energen Resources plans to continue to implement its acquisition and development program with capital spending in 2005 and 2006 as outlined above. Production in 2005 is estimated to be approximately 94 Bcfe, including 91 Bcfe of estimated production from proved reserves owned at December 31, 2004. In 2006, production is estimated to reach approximately 101 Bcfe, including approximately 88 Bcfe produced from proved reserves currently owned.

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. 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.

Energen Resources from time to time 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. In addition, Alagasco from time to time enters into cash flow derivative commodity instruments to hedge its gas supply price exposure. 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 or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. In cases where this arrangement exists, generally the credit ratings must be maintained at investment grad e status to have available counterparty credit. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. Typically, Energen Resources does not hedge more than 80 percent of its estimated annual production and does not hedge more than two fiscal years forward. In the case of an acquisition, Energen Resources may hedge further forward to protect targeted returns.

Energen Resources entered into the following transactions for 2005 and subsequent years:

Production Period

Total Hedged Volumes

Average Contract Price

Description

Natural Gas

2005

18.8 Bcf

$6.01 Mcf

NYMEX Swaps

 

20.6 Bcf

$5.00 Mcf

Basin Specific Swaps

 

* 3.7 Bcf

$6.07 Mcf

NYMEX Swaps

 

* 6.4 Bcf

$5.47 Mcf

Basin Specific Swaps

2006

* 17.6 Bcf

$6.04 Mcf

Basin Specific Swaps

Natural Gas Basis Differential

2005

1.6 Bcf

**

Basis Swaps

 

* 2.2 Bcf

**

Basis Swaps

Oil

2005

1,740 MBbl

$34.37 Bbl

NYMEX Swaps

 

960 MBbl

$33.21 Bbl

West Texas Sour Swaps

2006

360 MBbl

$37.12 Bbl

NYMEX Swaps

 

*720 MBbl

$42.29 Bbl

West Texas Sour Swaps

Oil Basis Differential

2005

1,003 MBbl

**

Basis Swaps

Natural Gas Liquids

2005

50.4 MMGal

$0.54 Gal

Liquids Swaps

2006

30.2 MMGal

$0.56 Gal

Liquids Swaps

* Contracts entered into subsequent to December 31, 2004

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

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, 2004, the Company estimated that a 10 percent increase or decrease in the commodities prices would have resulted in a $39.8 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 variance in basis or the impact of related taxes on actual cash prices.

Natural Gas Distribution: The extension of RSE in June 2002 provides Alagasco the opportunity to continue earning an allowed ROE between 13.15 percent and 13.65 percent through January 1, 2008. 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, the utility's CCM is based in part on the number of customers and the rate of inflation. Continued low inflation, significantly higher gas prices resulting in increased bad debt expense and/or the lack of customer growth could impact the utility's ability to manage its O&M expense per customer sufficiently for the inflation-based cost control requirements of RSE and may result in an average return on equi ty lower than the allowed range of return. Over this period, Alagasco has the potential for net income growth as the investment in additional utility plant affects the level of equity required in the business. The utility continues to rely on rate flexibility to effectively prevent bypass of its distribution system.

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, 2004, Alagasco recorded an $8.1 million gain as an asset in prepayments and other with a corresponding current regulatory liability of $8.1 million. The gains 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 2005.

Forward-Looking Statements and Risk Factors: 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, 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.

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.

Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas 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.

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 affect materially 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, criminal act or otherwise, could leave Alagasco financial 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.< /P>

Inherent in gas distribution activities 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 we maintain 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 the Company's financial position, results of operations and cash flows. Our utility customers are geographically concentrated in central and north Alabama. Significant economic, weather or other events that adversely affect this region could adversely affect the Company.

Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil 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 three largest oil and gas purchasers account for approximately 23%, 16% and 11%, respectively, of Energen Resources' estimated 2005 production. Energen Resources' other purchasers each buy less than 11% of production.

RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)

SFAS No. 141, "Business Combinations," requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142, "Goodwill and Other Intangible Assets," establishes guidelines in accounting for goodwill and other intangible assets. The appropriate applications of SFAS No. 141 and SFAS No. 142 were considered to determine whether oil and gas mineral rights should be classified separately as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. In September 2004, the Board issued FASB Staff Position (FSP) No. 142-2, "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities," which excluded oil and gas companies; therefore, the Company will continue to report lease rights as tangible assets on the balance sheet.

On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Deferring recognition of the Medicare impact was permitted by FSP No. 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The FASB superseded FSP No. 106-1 with the issuance of FSP No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," in May 2004, which provided more specific authoritative guidance on the accounting for this federal subsidy. The Company adopted FSP No. 106-2 during the third quarter of 2004 and reduced its annual non-cash postretirement health expense by approximately $396,000. In addition, the adoption resulted in a reduction in the disclosed accumulated postretirement benefit obligation by $3.4 million. The adoption of FSP No. 106-2 did not requ ire changes to previously reported information.

The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 (as amended), which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation, effective January 1, 2003. In December 2004, the Board issued SFAS No. 123 (revised 2004), "Share-Based Payment," which requires the fair value base method of accounting for all public entities using an option-pricing model that reflects the specific economics of a company's transactions. This statement is effective for the first interim or annual reporting period beginning after June 15, 2005. The Company is currently reviewing the impact of this pronouncement on stock-based compensation.

In December 2004, the Board issued FSP No. 109-1, "Application of SFAS No. 109, Accounting for Income Taxes, to the provision within the American Jobs Creation Act of 2004 (the Act) that provides a tax deduction on qualified production activities." This Act includes a tax deduction of up to 9 percent (when fully phased-in) of the lesser of (a) qualified production activities income as defined in the Act, or (b) taxable income determined without regard to this deduction. This tax deduction would apply to qualified production activities of Energen Resources and would be limited to 50 percent of W-2 wages paid by the Company. Pursuant to FSP No. 109-1, the deduction will be reported in the period in which the deduction is claimed on the Company's tax return and will not have an effect on deferred tax assets or deferred tax liabilities. The Company estimates the impact of this tax legislation will reduce income tax expense by approximately $1 million during 2005.

During 2004, the Board proposed FSP No. 19-a, "Accounting for Suspended Well Costs," which allows exploratory wells to be capitalized when the well has a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. The impact of this proposed position on the Company is expected to be immaterial.

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.

 

 

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

30

 

Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002

32

 

Consolidated Balance Sheets as of December 31, 2004 and 2003

33

 

Consolidated Statements of Shareholders' Equity for the years ended December 31, 2004, 2003 and 2002

35

 

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002

36

 

Notes to Financial Statements

42

 

 

 

 

Alabama Gas Corporation

 

 

 

 

 

Report of Independent Registered Public Accounting Firm

30

 

Statements of Income for the years ended December 31, 2004, 2003 and 2002

37

 

 

 

 

Balance Sheets as of December 31, 2004 and 2003

38

 

Statements of Shareholder's Equity for the years ended December 31, 2004, 2003 and 2002

40

 

Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002

41

 

Notes to Financial Statements

42

 

 

 

2.

Financial Statement Schedules

 

 

 

 

 

Energen Corporation

 

 

Schedule II - Valuation and Qualifying Accounts

75

 

 

 

 

Alabama Gas Corporation

 

 

Schedule II - Valuation and Qualifying Accounts

75

Schedules other than those listed above are omitted because they are not required or not applicable, or the required information is shown in the financial statements or notes thereto.

 

 

 

 

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Energen Corporation:

We have completed an integrated audit of Energen Corporation's 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

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, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on t hese 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 of financial statements 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 10 of the Notes to Financial Statements, effective January 1, 2002 the Company adopted Statement of Financial Accounting Standard (SFAS) No. 143, "Accounting for Asset Retirement Obligations".

Internal control over financial reporting

Also, in our opinion, management's assessment, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework (issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework (issued by the COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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

PricewaterhouseCoopers LLP

Birmingham, Alabama

March 14, 2005

 

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, 2004 and 2003, and the results of its operations and its cash flows for each of the three years ended in the period ended December 31, 2004 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 auditing standards generally accepted in the United States of America, which 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.

 

PricewaterhouseCoopers LLP

Birmingham, Alabama

March 14, 2005

 

CONSOLIDATED STATEMENTS OF INCOME

Energen Corporation

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

2004

2003

2002

Operating Revenues

 

 

 

Oil and gas operations

$ 410,644

$ 353,122

$ 244,120

Natural gas distribution

526,740

489,099

424,431

Total operating revenues

937,384

842,221

668,551

 

 

 

 

Operating Expenses

 

 

 

Cost of gas

259,889

233,823

189,810

Operations and maintenance

234,224

208,219

191,656

Depreciation, depletion and amortization

120,960

116,858

101,691

Taxes, other than income taxes

74,970

63,543

49,619

Accretion expense

2,265

1,890

1,819

Total operating expenses

692,308

624,333

534,595

 

 

 

 

Operating Income

245,076

217,888

133,956

 

 

 

 

Other Income (Expense)

 

 

 

Interest expense

(42,743)

(42,262)

(43,713)

Other income

2,945

8,744

15,644

Other expense

(2,215)

(9,977)

(15,103)

Total other expense

(42,013)

(43,495)

(43,172)

 

 

 

 

Income From Continuing Operations Before Income Taxes and Cumulative Effect of Change in Accounting Principle

 203,063

 174,393

 90,784

Income tax expense

75,613

64,128

20,388

Income From Continuing Operations Before Cumulative Effect of Change in Accounting Principle

127,450

110,265

70,396

 

 

 

 

Discontinued Operations, net of taxes

 

 

 

Income (loss) from discontinued operations

18

973

(80)

Gain (loss) on disposal

(5)

(584)

543

Income From Discontinued Operations

13

389

463

 

 

 

 

Cumulative Effect of Change in Accounting Principle, net of taxes

-

-

(2,220)

 

 

 

 

Net Income

$ 127,463

$ 110,654

$ 68,639

 

 

 

 

Diluted Earnings Per Average Common Share

 

 

 

Continuing operations

$ 3.49

$ 3.09

$ 2.08

Discontinued operations

-

0.01

0.02

Cumulative effect of change in accounting principle

-

-

(0.07)

Net Income

$ 3.49

$ 3.10

$ 2.03

Basic Earnings Per Average Common Share

 

 

 

Continuing operations

$ 3.51

$ 3.11

$ 2.09

Discontinued operations

-

0.01

0.02

Cumulative effect of change in accounting principle

-

-

(0.07)

Net Income

$ 3.51

$ 3.12

$ 2.04

Diluted Average Common Shares Outstanding

36,558,626

35,716,876

33,838,299

Basic Average Common Shares Outstanding

36,273,256

35,434,486

33,604,601

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

CONSOLIDATED BALANCE SHEETS

 

 

Energen Corporation

 

 

 

December 31,

December 31,

(in thousands)

2004

2003

 

 

 

ASSETS

 

 

 

 

 

Current Assets

 

 

Cash and cash equivalents

$ 4,489

$ 2,127

Accounts receivable, net of allowance for doubtful accounts of $10,472 at December 31, 2004, and of $9,852 at December 31, 2003

 217,360

 176,756

Inventories, at average cost

 

 

Storage gas inventory

51,093

40,654

Materials and supplies

7,843

7,677

Liquified natural gas in storage

3,688

3,475

Deferred income taxes

36,285

38,145

Prepayments and other

29,150

18,032

Total current assets

349,908

286,866

Property, Plant and Equipment

 

 

Oil and gas properties, successful efforts method

1,591,119

1,197,340

Less accumulated depreciation, depletion and amortization

381,734

310,368

Oil and gas properties, net

1,209,385

886,972

Utility plant

941,862

883,225

Less accumulated depreciation

373,589

341,787

Utility plant, net

568,273

541,438

Other property, net

5,401

5,041

Total property, plant and equipment, net

1,783,059

1,433,451

Other Assets

 

 

Regulatory asset

19,650

18,082

Deferred charges and other

29,122

39,833

Total other assets

48,772

57,915

 

 

 

TOTAL ASSETS

$ 2,181,739

$ 1,778,232

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

 

  

CONSOLIDATED BALANCE SHEETS

 

 

Energen Corporation

 

 

 

December 31,

December 31,

(in thousands, except share data)

2004

2003

CAPITAL AND LIABILITIES

 

 

 

 

 

Current Liabilities

 

 

Long-term debt due within one year

$ 10,000

$ 10,000

Notes payable to banks

135,000

11,000

Accounts payable

159,871

135,319

Accrued taxes

34,541

28,551

Customers' deposits

19,549

17,884

Amounts due customers

10,363

8,571

Accrued wages and benefits

28,941

24,957

Regulatory liability

47,060

54,146

Other

53,293

37,303

 

 

 

Total current liabilities

498,618

327,731

 

 

 

Deferred Credits and Other Liabilities

 

 

Asset retirement obligation

34,841

26,515

Minimum pension liability

14,216

14,711

Regulatory liability

111,928

113,427

Deferred income taxes

95,417

33,200

Other

10,162

10,774

 

 

 

Total deferred credits and other liabilities

266,564

198,627

 

 

 

Commitments and Contingencies

 

 

Capitalization

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

 

-

 

-

Common shareholders' equity

Common stock, $0.01 par value; 75,000,000 shares authorized, 36,582,979 shares outstanding at December 31, 2004, and 36,223,531 shares outstanding at December 31, 2003

 

 

 366

 

 

 362

Premium on capital stock

380,965

367,765

Capital surplus

2,802

2,802

Retained earnings

459,992

360,001

Accumulated other comprehensive loss, net of tax

 

 

Unrealized loss on hedges

(25,466)

(21,714)

Minimum pension liability

(11,864)

(8,881)

Deferred compensation on restricted stock

(2,675)

(1,258)

Deferred compensation plan

28,919

17,063

Treasury stock, at cost; 500,476 shares and 417,011 shares at December 31, 2004 and 2003, respectively

(29,373)

(17,108)

Total common shareholders' equity

803,666

699,032

Long-term debt

612,891

552,842

Total capitalization

1,416,557

1,251,874

TOTAL CAPITAL AND LIABILITIES

$ 2,181,739

$ 1,778,232

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

 

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

Energen Corporation

(in thousands, except share amounts)

 

Common Stock

 

 

 

 

 

 

 

 

 

Number of Shares

Par Value

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

BALANCE DECEMBER 31, 2001

31,248,547

$ 312

$ 235,976

$ 2,802

$ 230,554

$ 7,168

$ (1,513)

$ 7,222

$ (8,316)

$ 474,205

Net income

 

 

 

 

68,639

 

 

 

 

68,639

Other comprehensive loss:

 

 

 

 

 

 

 

 

 

 

Current period change in fair value of derivative instruments, net of tax of ($9,893)

 

 

 

 

 

 

(15,473)

 

 

 

 

(15,473)

Reclassification adjustment, net of tax of ($2,724)

 

 

 

 

 

(4,260)

 

 

 

(4,260)

Minimum pension liability, net of tax of ($1,211)

 

 

 

 

 

(2,246)

 

 

 

(2,246)

Comprehensive income

 

 

 

 

 

 

 

 

 

46,660

Purchase of treasury shares

 

 

 

 

 

 

 

 

(133)

(133)

Shares issued for:

 

 

 

 

 

 

 

 

 

 

Stockissuance for acquisition

3,043,479

30

72,861

 

 

 

 

 

 

72,891

Dividend reinvestment plan

77,725

1

2,020

 

 

 

 

 

401

2,422

Employee benefit plans

375,726

4

9,203

 

 

 

 

 

742

9,949

Deferred compensation obligation

 

 

 

 

 

 

 

3,126

(3,126)

-

Amortization of restricted stock

 

 

 

 

 

 

743

 

 

743

Cash dividends - $0.71 per share

 

 

 

 

(23,927)

 

 

 

 

(23,927)

BALANCE DECEMBER 31, 2002

34,745,477

347

320,060

2,802

275,266

(14,811)

(770)

10,348

(10,432)

582,810

Net income

 

 

 

 

110,654

 

 

 

 

110,654

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

Current period change in fair value of derivative instruments, net of tax of ($29,019)

 

 

 

 

 

 

(45,388)

 

 

 

 

(45,388)

Reclassification adjustment, net of tax of $21,830

 

 

 

 

 

34,145

 

 

 

34,145

Minimum pension liability, net of tax of ($2,445)

 

 

 

 

 

(4,541)

 

 

 

(4,541)

Comprehensive income

 

 

 

 

 

 

 

 

 

94,870

Purchase of treasury shares

 

 

 

 

 

 

 

 

(1,046)

(1,046)

Shares issued for:

 

 

 

 

 

 

 

 

 

 

Stock offerings

1,000,000

10

32,121

 

 

 

 

 

 

32,131

Dividend reinvestment plan

53,990

1

1,865

 

 

 

 

 

491

2,357

Employee benefit plans

424,064

4

12,033

 

 

 

 

 

594

12,631

Deferred compensation obligation

 

 

 

 

 

 

 

6,715

(6,715)

-

Issuance of restricted stock

 

 

 

 

 

 

(1,564)

 

 

(1,564)

Amortization of restricted stock

 

 

 

 

 

 

1,076

 

 

1,076

Stock based compensation

 

 

270

 

 

 

 

 

 

270

Tax benefit from exercise of stock options

 

 

1,416

 

 

 

 

 

 

1,416

Cash dividends - $0.73 per share

 

 

 

 

(25,919)

 

 

 

 

(25,919)

BALANCE DECEMBER 31, 2003

36,223,531

362

367,765

2,802

360,001

(30,595)

(1,258)

17,063

(17,108)

699,032

Net income

 

 

 

 

127,463

 

 

 

 

127,463

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

Current period change in fair value of derivative instruments, net of tax of ($34,012)

 

 

 

 

 

 

(56,430)

 

 

 

 

(56,430)

Reclassification adjustment, net of tax of $32,286

 

 

 

 

 

52,678

 

 

 

52,678

Minimum pension liability, net of tax of ($1,608)

 

 

 

 

 

(2,983)

 

 

 

(2,983)

Comprehensive income

 

 

 

 

 

 

 

 

 

120,728

Purchase of treasury shares

 

 

 

 

 

 

 

 

(836)

(836)

Shares issued for:

 

 

 

 

 

 

 

 

 

 

Dividend reinvestment plan

1,275

-

53

 

 

 

 

 

-

53

Employee benefit plans

358,173

4

9,116

 

 

 

 

 

427

9,547

Deferred compensation obligation

 

 

 

 

 

 

 

11,856

(11,856)

-

Issuance of restricted stock

 

 

 

 

 

 

(2,807)

 

 

(2,807)

Amortization of restricted stock

 

 

 

 

 

 

1,390

 

 

1,390

Stock based compensation

 

 

465

 

 

 

 

 

 

465

Tax benefit from exercise of stock options

 

 

1,180

 

 

 

 

 

 

1,180

Tax benefit from vesting of restricted stock

 

 

95

 

 

 

 

 

 

95

Long-Range Performance Plan

 

 

2,291

 

 

 

 

 

 

2,291

Cash dividends - $0.755 per share

 

 

 

 

(27,472)

 

 

 

 

(27,472)

BALANCE DECEMBER 31, 2004

36,582,979

$ 366

$ 380,965

$ 2,802

$ 459,992

$ (37,330)

$ (2,675)

$ 28,919

$ (29,373)

$ 803,666

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

 

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

Energen Corporation

Years ended December 31, (in thousands)

2004

2003

2002

 

 

 

 

Operating Activities

 

 

 

Net income

$ 127,463

$ 110,654

$ 68,639

Adjustments to reconcile net income to net cash provided by (used in) operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

120,960

117,785

107,952

Deferred income taxes, net

67,423

54,632

10,915

Deferred investment tax credits, net

(308)

(448)

(448)

Change in derivative fair value

212

735

(9,205)

Gain on sale of assets

(135)

(9,987)

(3,738)

Loss on properties held for sale

-

10,404

2,815

Cumulative effect of change in accounting

 

 

 

principle, net of taxes

-

-

2,220

Net change in:

 

 

 

Accounts receivable

(39,645)

(24,811)

(27,104)

Inventories

(10,818)

(16,132)

27,344

Accounts payable

19,536

12,860

28,600

Amounts due customers

(1,166)

4,052

626

Other current assets and liabilities

19,518

(5,533)

1,712

Other, net

(11,908)

(11,084)

3,179

 

 

 

 

Net cash provided by operating activities

291,132

243,127

213,507

 

 

 

 

Investing Activities

 

 

 

Additions to property, plant and equipment

(177,705)

(179,107)

(166,075)

Acquisitions, net of cash acquired

(274,400)

(40,486)

(117,043)

Proceeds from sale of assets

461

29,149

17,094

Other, net

(1,770)

30

(2,198)

 

 

 

 

Net cash used in investing activities

(453,414)

(190,414)

(268,222)

 

 

 

 

Financing Activities

 

 

 

Payment of dividends on common stock

(27,472)

(25,919)

(23,927)

Issuance of common stock

9,600

47,119

12,371

Purchase of treasury stock

(836)

(1,046)

(133)

Reduction of long-term debt

(40,083)

(23,000)

(21,204)

Proceeds from issuance of long-term debt

100,000

49,778

-

Debt issuance costs

(565)

(322)

-

Net change in short-term debt

124,000

(102,000)

85,930

 

 

 

 

Net cash provided by (used in) financing activities

164,644

(55,390)

53,037

 

 

 

 

Net change in cash and cash equivalents

2,362

(2,677)

(1,678)

Cash and cash equivalents at beginning of period

2,127

4,804

6,482

 

 

 

 

Cash and cash equivalents at end of period

$ 4,489

$ 2,127

$ 4,804

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

 

STATEMENTS OF INCOME

Alabama Gas Corporation

Years ended December 31, (in thousands)

2004

2003

2002

 

 

 

 

Operating Revenues

$ 526,740

$ 489,099

$ 424,431

 

 

 

 

Operating Expenses

 

 

 

Cost of gas

261,800

236,037

191,479

Operations and maintenance

121,896

114,078

109,115

Depreciation

39,881

37,171

33,682

Income taxes

 

 

 

Current

9,690

6,577

8,764

Deferred, net

10,321

13,546

9,509

Deferred investment tax credits, net

(308)

(448)

(448)

Taxes, other than income taxes

36,964

34,965

30,785

 

 

 

 

Total operating expenses

480,244

441,926

382,886

 

 

 

 

Operating Income

46,496

47,173

41,545

 

 

 

 

Other Income (Expense)

 

 

 

Allowance for funds used during construction

1,247

948

1,336

Other income

1,979

4,132

5,520

Other expense

(2,195)

(5,269)

(6,280)

 

 

 

 

Total other income (expense)

1,031

(189)

576

 

 

 

 

Interest Charges

 

 

 

Interest on long-term debt

10,672

12,815

13,153

Other interest charges

3,065

1,152

1,404

 

 

 

 

Total interest charges

13,737

13,967

14,557

 

 

 

 

Net Income

$ 33,790

$ 33,017

$ 27,564

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

 

 

BALANCE SHEETS

 

 

Alabama Gas Corporation

 

 

 

December 31,

December 31,

(in thousands)

2004

2003

 

 

 

ASSETS

 

 

Property, Plant and Equipment

 

 

Utility plant

$ 941,862

$ 883,225

Less accumulated depreciation

373,589

341,787

 

 

 

Utility plant, net

568,273

541,438

 

 

 

Other property, net

325

331

 

 

 

Current Assets

 

 

Cash

3,467

1,440

Accounts receivable

 

 

Gas

142,736

134,376

Merchandise

2,328

1,210

Other

9,624

4,859

Affiliated companies

2,190

-

Allowance for doubtful accounts

(9,600)

(9,100)

Inventories, at average cost

 

 

Storage gas inventory

51,093

40,654

Materials and supplies

4,281

5,527

Liquified natural gas in storage

3,688

3,475

Regulatory asset

-

251

Deferred income taxes

15,233

17,650

Prepayments and other

21,901

15,015

 

 

 

Total current assets

246,941

215,357

 

 

 

Other Assets

 

 

Regulatory asset

19,650

18,082

Deferred charges and other

4,558

19,285

 

 

 

Total other assets

24,208

37,367

 

 

 

TOTAL ASSETS

$ 839,747

$ 794,493

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

 

BALANCE SHEETS

 

 

Alabama Gas Corporation

 

 

 

December 31,

December 31,

(in thousands, except share data)

2004

2003

 

 

 

CAPITAL AND LIABILITIES

 

 

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 outstanding at December 31, 2004 and 2003, respectively

 

20

 

20

Premium on capital stock

31,682

31,682

Capital surplus

2,802

2,802

Retained earnings

223,515

215,869

 

 

 

Total common shareholder's equity

258,019

250,373

Long-term debt

129,450

169,533

 

 

 

Total capitalization

387,469

419,906

 

 

 

Current Liabilities

 

 

Long-term debt due within one year

10,000

-

Notes payable to banks

82,000

11,000

Accounts payable

 

 

Trade

81,591

56,020

Affiliated companies

-

37,290

Accrued taxes

27,410

22,145

Customers' deposits

19,549

17,884

Amounts due customers

10,363

8,571

Accrued wages and benefits

7,724

6,247

Regulatory liability

47,060

54,146

Other

11,906

9,039

 

 

 

Total current liabilities

297,603

222,342

 

 

 

Deferred Credits and Other Liabilities

 

 

Deferred income taxes

40,070

32,178

Minimum pension liability

-

3,788

Regulatory liability

111,928

113,427

Customer advances for construction and other

2,677

2,852

 

 

 

Total deferred credits and other liabilities

154,675

152,245

 

 

 

Commitments and Contingencies

 

 

 

 

 

TOTAL CAPITAL AND LIABILITIES

$    839,747 

$    794,493 

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

 

STATEMENTS OF SHAREHOLDER'S EQUITY

Alabama Gas

 

 

 

 

 

 

 Corporation

 

 

 

 

 

 

(in thousands, except share amounts)

 

Common Stock

 

 

 

Total

 

Number of Shares

Par Value

Premium on Capital Stock

Capital Surplus

Retained Earnings

Shareholder's Equity

 

 

 

 

 

 

 

Balance December 31, 2001

1,972,052

$ 20

$ 31,682

$ 2,802

$ 172,147

$ 206,651

Net income

 

 

 

 

27,564

27,564

Cash dividends

 

 

 

 

(16,859)

(16,859)

 

 

 

 

 

 

 

Balance December 31, 2002

1,972,052

20

31,682

2,802

182,852

217,356

Net income

 

 

 

 

33,017

33,017

 

 

 

 

 

 

 

Balance December 31, 2003

1,972,052

20

31,682

2,802

215,869

250,373

Net income

 

 

 

 

33,790

33,790

Cash dividends

 

 

 

 

(26,144)

(26,144)

 

 

 

 

 

 

 

Balance December 31, 2004

1,972,052

$ 20

$ 31,682

$ 2,802

$ 223,515

$ 258,019

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

 

STATEMENTS OF CASH FLOWS

Alabama Gas Corporation

Years ended December 31, (in thousands)

2004

2003

2002

 

 

 

 

Operating Activities

 

 

 

Net income

$ 33,790

$ 33,017

$ 27,564

Adjustments to reconcile net income to net cash

provided by (used in) operating activities:

 

 

 

 

 

Depreciation and amortization

39,881

37,171

33,682

Deferred income taxes, net

10,321

13,546

9,509

Deferred investment tax credits

(308)

(448)

(448)

Net change in:

 

 

 

Accounts receivable

(12,784)

(15,923)

(17,151)

Inventories

(9,406)

(17,268)

27,099

Accounts payable

25,823

49

21,697

Amounts due customers

(1,166)

4,052

626

Other current assets and liabilities

8,128

(4,140)

(6,666)

Other, net

(8,968)

(13,774)

(1,447)

 

 

 

 

Net cash provided by operating activities

85,311

36,282

94,465

 

 

 

 

Investing Activities

 

 

 

Additions to property, plant and equipment

(56,922)

(56,255)

(64,257)

Net advances from (to) parent company

(39,480)

35,858

(1,622)

Other, net

(1,655)

(263)

(814)

 

 

 

 

Net cash used in investing activities

(98,057)

(20,660)

(66,693)

 

 

 

 

Financing Activities

 

 

 

Payment of dividends on common stock

(26,144)

-

(16,859)

Reduction of long-term debt

(30,083)

(15,000)

(5,467)

Net change in short-term debt

71,000

(2,000)

(6,000)

 

 

 

 

Net cash provided (used) by financing activities

14,773

(17,000)

(28,326)

 

 

 

 

Net change in cash and cash equivalents

2,027

(1,378)

(554)

Cash and cash equivalents at beginning of period

1,440

2,818

3,372

 

 

 

 

Cash and cash equivalents at end of period

$ 3,467

$ 1,440

$ 2,818

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

 

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

A. Principles of Consolidation

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

B. Oil and Gas Operations

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

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, 2004.

Derivative Commodity Instruments: Energen Resources from time to time 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's debt. In cases where this arrangement exists, generally the credit ratings must be maintained at investment grade status to have available counterparty credit.

Energen Resources applies Statement of Financial Accounting Standard (SFAS) No. 133 (as amended), "Accounting for Derivative Instruments and Hedging Activities," which 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 Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is recognized in operating revenues 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 ope rating revenues in the period of change.

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, 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, 2006.

C. Natural Gas Distribution

Utility Plant and Depreciation: Property, plant and equipment is 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 is 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, 2004, 2003 and 2002.

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 tarriff 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, 2004.

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 from time to time enters 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)

2004

2003

2002

Taxes on revenues

$ 27,002

$ 25,218

$ 21,591

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 allocated 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 off 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).

H. Stock-Based Compensation

The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), "Accounting for Stock-Based Compensation," prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to six years; therefore, the cost related to stock-based employee compensation included in the determination of net income is different than that which would have been recognized if the fair value method had been applied to all awards.

The following table illustrates the effect on net income and diluted earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period:

Years ended December 31, (in thousands)

2004

2003

2002

Net income

 

 

 

As reported

$ 127,463

$ 110,654

$ 68,639

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

7,219

4,553

1,811

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

(5,658)

(3,904)

(2,413)

Pro forma

$ 129,024

$ 111,303

$ 68,037

Diluted earnings per average common share

 

 

 

As reported

$ 3.49

$ 3.10

$ 2.03

Pro forma

$ 3.53

$ 3.12

$ 2.01

Basic earnings per average common share

 

 

 

As reported

$ 3.51

$ 3.12

$ 2.04

Pro forma

$ 3.56

$ 3.14

$ 2.02

The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded, which are included in the pro forma results above. For purposes of this valuation the following assumptions were used to derive the fair values: a seven-year time of exercise; an annualized volatility rate of 32.72 percent and 34.67 percent for the years ended December 31, 2004 and 2003, respectively; a risk-free interest rate of 3.64 percent and 2.36 percent for the years ended December 31, 2004 and 2003, respectively; and a dividend yield of 1.81 percent on options without dividend equivalents for the year ended December 31, 2004. Options with dividend equivalents assume no dividend yield for all periods presented. The weighted-average grant-date fair value for options granted without dividend equivalents during the year ended December 31, 2004 was $14.21.The weighted-average grant-date fair value for options granted with dividend equivalents during the year ended December 31, 2003 was $ 12.10. There were no options granted in the year ended December 31, 2002.

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. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.

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 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended Alagasco's rate-setting methodology, RSE, without change, for a six-year period through January 1, 2008. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operations. 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, subject to change in the event that the Commissi on, following a generic rate of return hearing, adjusts the equity returns of all major energy utilities operating under a similar methodology. 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 13.15 percent to 13.65 percent. 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. Alagasco did not have an reduction in rates related to the return on average equity for rate years ended 2004 and 2002. As of September 30, 2003, Alagasco had a $3 million reduction in revenues to bring the return on average equity within the allowed range of return. A $12.3 million, $11.2 million and $12.7 million annual increase in revenues became effective December 1, 2004, 2003, a nd 2002, respectively. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control 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 falls 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 is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. The increase in O&M expense per customer was above the index range for the rate year ended September 30, 2004, 2003 and 2002; as a result, the utility returned to customers $1.2 million, $0.1 million and $0.3 million, respectively, through rate adjustments under the provisions of RSE.

Alagasco calculates a temperature adjustment to customers' monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco's earnings. Adjustments to customers' bills are made in the same billing 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 certain limitations including regulatory limits on adjustments to increase customers' bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high 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. During the year ended December 31, 2004, Alagasco charged $0.3 million against the ESR related to extraordinary maintenance cost resulting from certain weather events within Alagasco's service territory. 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 a chieved. The ESR balances of $3.7 million at December 31, 2004 and $3.5 million at December 31, 2003, are included in the consolidated financial statements.

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, 2004 and 2003, the net acquisition adjustments were $11.5 million and $12.6 million, respectively.

3. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

(in thousands)

December 31, 2004

December 31, 2003

Energen Corporation:

 

 

Medium-term Notes, interest ranging from 6.95% to 8.09%, for notes redeemable September 25, 2006, to February 15, 2028

$ 335,000

$ 345,000

5% Notes, redeemable October 1, 2013

50,000

50,000

Floating Rate Senior Notes (2.68% at December 31, 2004), redeemable November 15, 2007

100,000

-

Alabama Gas Corporation:

 

 

Medium-term Notes, interest ranging from 6.70% to 7.97%, for notes redeemable July 15, 2005, to September 23, 2026

65,000

95,000

6.25% Notes, redeemable September 1, 2016

39,725

39,758

6.75% Notes, redeemable September 1, 2031

34,725

34,775

Total

624,450

564,533

Less amounts due within one year

10,000

10,000

Less unamortized debt discount

1,559

1,691

Total

$ 612,891

$ 552,842

 

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

Years ending December 31, (in thousands)

2005

2006

2007

2008

2009

$ 10,000

$ 15,000

$ 107,000

$ 15,000

-

 

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

Years ending December 31, (in thousands)

2005

2006

2007

2008

2009

$ 10,000

$ 5,000

$ 7,000

$ 5,000

-

At December 31, 2004, the Company was not subject to restrictions on the payment of dividends. The Company is in compliance with the covenants under the various long-term debt agreements. Except as discussed below, debt covenants address routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Payments with respect to Alagasco's 6.25% Notes and 6.75% Notes are insured by Ambac Assurance Corporation. Under the insurance agreement, Alagasco cannot dispose of distribution plant assets if, after such disposition, its distribution plant will be less than $200 million. Alagasco's distribution plant exceeded $200 million at December 31, 2004. In addition, $300 million of 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.

Energen and Alagasco had short-term credit lines and other credit facilities of $287 million available as of December 31, 2004, for working capital needs. Alagasco has been authorized to borrow up to $100 million of the available credit lines by the APSC. The following is a summary of information relating to notes payable to banks:

(in thousands)

December 31, 2004

December 31, 2003

Energen outstanding

$ 53,000

$ -

Alagasco outstanding

82,000

11,000

Notes payable to banks

135,000

11,000

Available for borrowings

152,000

256,000

Total

$ 287,000

$ 267,000

Maximum amount outstanding at any month-end

$ 220,000

$ 83,000

Average daily amount outstanding

$ 92,622

$ 81,121

 Weighted average interest rates based on:

 

 

Average daily amount outstanding

2.29%

1.71%

Amount outstanding at year-end

2.85%

1.42%

Alagasco maximum amount outstanding at any month-end

$ 82,000

$ 11,000

Alagasco average daily amount outstanding

$ 26,301

$ 9,592

Alagasco weighted average interest rates based on:

 

 

Average daily amount outstanding

2.29%

1.53%

Amount outstanding at year-end

2.83%

1.42%

Energen's total interest expense was $42,743,000, $42,262,000 and $43,713,000 for the years ended December 31, 2004, 2003 and 2002, respectively. Total interest expense at Alagasco was $13,737,000, $13,967,000 and $14,557,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

4. INCOME TAXES

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

Years ended December 31, (in thousands)

2004

2003

2002

Taxes estimated to be payable currently:

 

 

 

Federal

$ 7,343

$ 8,904

$ 7,263

State

1,155

1,294

535

Total current

8,498

10,198

7,798

Taxes deferred:

 

 

 

Federal

58,956

47,805

9,062

State

8,159

6,125

3,528

Total deferred

67,115

53,930

12,590

Total income tax expense from continuing operations

$ 75,613

$ 64,128

$ 20,388

For the year ended December 31, 2004, Energen recorded a current income tax expense of $8,000 related to income from discontinued operations. For the year ended December 31, 2003, Energen recorded a current income tax benefit of $5,000 and a deferred income tax expense of $254,000 related to income from discontinued operations. For the year ended December 31, 2002, Energen recorded a current income tax expense of $2,418,000 and a deferred income tax benefit of $2,123,000 related to income from discontinued operations.

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

(Years ended December 31, (in thousands)

2004

2003

2002

Taxes estimated to be payable currently:

 

 

 

Federal

$ 8,581

$ 5,827

$ 7,763

State

1,109

750

1,001

Total current

9,690

6,577

8,764

Taxes deferred:

 

 

 

Federal

8,834

11,549

7,974

State

1,179

1,549

1,087

Total deferred

10,013

13,098

9,061

Total income tax expense from continuing operations

$ 19,703

$ 19,675

$ 17,825

 

Temporary differences and carryforwards which gave rise to a significant portion of Energen's and Alagasco's deferred tax assets and liabilities for 2004 and 2003 were as follows:

Energen Corporation

 

 

(in thousands)

December 31, 2004

December 31, 2003

 

Current

Noncurrent

Current

Noncurrent

Deferred tax assets:

 

 

 

 

Minimum tax credit

$ -

$ 56,688

$ -

$ 59,313

Pension and other costs

Unbilled and deferred revenue

Enhanced stability reserve and other

regulatory costs

Allowance for doubtful accounts

Insurance accruals

Compensation accruals

Inventories

Other comprehensive income

-

10,017

1,888

3,880

2,102

6,408

775

14,377

7,883

-

-

-

-

-

-

7,621

-

10,578

1,346

3,611

2,946

3,639

1,001

12,548

8,093

-

-

-

-

-

-

6,116

Other, net

2,769

592

2,851

556

Total deferred tax assets

42,216

72,784

38,520

74,078

Deferred tax liabilities:

 

 

 

 

Depreciation and basis differences

Pension and other costs

Minimum pension liability

-

5,909

-

160,318

-

7,883

-

341

-

99,185

-

8,093

Other, net

22

-

34

-

Total deferred tax liabilities

5,931

168,201

375

107,278

Net deferred tax assets (liabilities)

$ 36,285

$ (95,417)

$ 38,145

$ (33,200)

Alabama Gas Corporation

 

 

(in thousands)

December 31, 2004

December 31, 2003

 

Current

Noncurrent

Current

Noncurrent

Deferred tax assets:

 

 

 

 

Pension and other costs

$ -

$ 7,883

$ -

$ 8,093

Unbilled and deferred revenue

10,017

-

10,578

-

Enhanced stability reserve and other

regulatory costs

1,888

-

1,346

-

Allowance for doubtful accounts

3,630

-

3,441

-

Insurance accruals

2,672

-

2,503

-

Compensation accruals

3,779

-

2,216

-

Inventories

775

-

835

-

Other, net

1,462

527

1,241

486

Total deferred tax assets

24,223

8,410

22,160

8,579

Deferred tax liabilities:

 

 

 

 

Depreciation and basis differences

Pension and other costs

Minimum pension liability

-

8,970

-

40,597

-

7,883

-

4,498

-

32,664

-

8,093

Other, net

20

-

12

-

Total deferred tax liabilities

8,990

48,480

4,510

40,757

Net deferred tax assets (liabilities)

$ 15,233

$ (40,070)

$ 17,650

$ (32,178)

The Company files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2004, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $56.7 million. No valuation allowance with respect to deferred taxes is deemed necessary, as the Company anticipates generating adequate future taxable income to realize the benefits of all deferred tax assets on the consolidated balance sheets.

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

Years ended December 31, (in thousands)

2004

2003

2002

Income tax expense from continuing operations at statutory federal income tax rate

$ 71,072

$ 61,038

$ 31,774

Increase (decrease) resulting from:

 

 

 

Nonconventional fuels tax credits

-

-

(14,165)

Enhanced oil recovery tax credits

(456)

(469)

-

Deferred investment tax credits

(308)

(448)

(448)

State income taxes, net of federal income tax benefit

6,011

5,108

2,453

Other, net

(706)

(1,101)

774

Total income tax expense from continuing operations

$ 75,613

$ 64,128

$ 20,388

Effective income tax rate (%)

37.24

36.77

22.46

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

Years ended December 31, (in thousands)

2004

2003

2002

Income tax expense from continuing operations at statutory federal income tax rate

$ 18,723

$ 18,442

$ 15,886

Increase (decrease) resulting from:

 

 

 

Deferred investment tax credits

(308)

(448)

(448)

State income taxes, net of federal income tax benefit

1,504

1,480

1,236

Other, net

(216)

201

1,151

Total income tax expense from continuing operations

$ 19,703

$ 19,675

$ 17,825

Effective income tax rate (%)

36.83

37.34

39.27

5. EMPLOYEE BENEFIT PLANS

The Company has two defined benefit non-contributory pension plans: Plan A covers a majority of the employees and Plan B covers employees under certain labor union agreements. Benefits are based on years of service and final earnings for Plan A. Plan B provides benefits based on years of service and flat dollar amounts. The Company's policy is to use the projected unit credit actuarial method for funding and financial reporting purposes. For its pension plans, Energen used a September 30 measurement date.

The status of the plans was as follows:

(in thousands)

Plan A

 

2004

2003

Accumulated benefit obligation (September 30)

$ 111,017

$ 94,476

 

 

 

Projected benefit obligation:

 

 

Balance at beginning of period

$ 115,633

$ 101,399

Service cost

5,424

3,955

Interest cost

6,654

6,640

Actuarial loss

16,659

15,449

Benefits paid

(9,256)

(11,810)

Balance at end of period (September 30)

135,114

115,633

Plan assets:

 

 

Fair value of plan assets at beginning of period

89,936

67,594

Actual return on plan assets

10,341

14,252

Employer contributions

773

19,900

Benefits paid

(9,256)

(11,810)

Fair value of plan assets at end of period (September 30)

91,794

89,936

Amounts recognized in the consolidated balance sheets:

Funded status of plan

(43,320)

(25,697)

Prepaid pension costs

(8,615)

(14,087)

Unrecognized actuarial loss

50,377

37,991

Unrecognized prior service cost

1,558

1,793

Employer contributions (October 1 to December 31)

20,594

-

Accrued pension asset (December 31)

$ 20,594

$ -

 

 

(in thousands)

Plan B

 

2004

2003

Accumulated benefit obligation (September 30)

$ 25,114

$ 24,287

 

 

 

Projected benefit obligation:

 

 

Balance at beginning of period

$ 24,287

$ 21,988

Service cost

583

491

Interest cost

1,383

1,417

Actuarial loss

357

2,190

Benefits paid

(1,496)

(1,799)

Balance at end of period (September 30)

25,114

24,287

Plan assets:

 

 

Fair value of plan assets at beginning of period

20,835

15,688

Actual return on plan assets

2,533

2,946

Employer contributions

3,246

4,000

Benefits paid

(1,496)

(1,799)

Fair value of plan assets at end of period (September 30)

25,118

20,835

Amounts recognized in the consolidated balance sheets:

Funded status of plan

4

(3,452)

Prepaid pension costs

(6,516)

(3,609)

Unrecognized actuarial loss

4,925

5,120

Unrecognized prior service cost

1,587

1,941

Employer contributions (October 1 to December 31)

1,106

3,200

Accrued pension asset (December 31)

$ 1,106

$ 3,200

Weighted average rate assumptions used to determine the projected benefit obligations at the measurement date:

 

Plan A

 

September 30, 2004

September 30, 2003

Discount rate

5.75%

6.00%

Rate of compensation increase

4.00%

4.00%

 

Plan B

 

September 30, 2004

September 30, 2003

Discount rate

5.75%

6.00%

 

The components of net pension expense were:

 

Plan A

Years ended December 31, (in thousands)

2004

2003

2002

Components of net periodic benefit cost:

 

 

 

Service cost

$ 5,425

$ 3,955

$ 3,074

Interest cost

6,654

6,640

6,173

Expected long-term return on assets

(7,801)

(6,858)

(6,145)

Prior service cost amortization

235

235

235

Net periodic benefit cost

1,732

628

-

Transition amortization

-

-

(196)

Net periodic expense

$ 6,245

$ 4,600

$ 3,141

 

Plan B

Years ended December 31, (in thousands)

2004

2003

2002

Components of net periodic benefit cost:

 

 

 

Service cost

$ 583

$ 491

$ 396

Interest cost

1,383

1,417

1,422

Expected long-term return on assets

(2,089)

(1,561)

(1,619)

Prior service cost amortization

354

354

354

Actuarial loss

108

-

-

Transition amortization

-

-

43

Net periodic expense

$ 339

$ 701

$ 596

Net pension expense for Alagasco was $5,175,000, $4,370,000 and $3,224,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

Weighted average rate assumptions to determine net periodic benefit costs for the period ending:

 

Plan A

 

December 31, 2004

December 31, 2003

December 31, 2002

Discount rate

6.00%

6.75%

7.50%

Expected long-term return on plan assets

8.75%

9.00%

9.00%

Rate of compensation increase

4.00%

4.50%

4.50%

 

Plan B

 

December 31, 2004

December 31, 2003

December 31, 2002

Discount rate

6.00%

6.75%

7.50%

Expected long-term return on plan assets

8.75%

9.00%

9.00%

 

The Company's weighted-average pension plan asset allocations by asset category were as follows:

 

Plan A

 

December 31, 2004

December 31, 2003

Asset category:

Equity securities

60%

64%

Debt securities

30%

34%

Other

10%

2%

Total

100%

100%

 

 

 

Plan B

 

December 31, 2004

December 31, 2003

Asset category:

Equity securities

75%

71%

Debt securities

21%

27%

Other

4%

2%

Total

100%

100%

Plan A and Plan B equity securities do not include the Company's common stock. The Company is not required to make pension contributions in 2005 and does not currently plan to make discretionary contributions to Plan A or Plan B assets. The Company will reevaluate discretionary contributions in the fourth quarter of 2005 based on the outcome of the September 30, 2005 measurement of pension obligations.

Pension plan benefit payments, which reflect expected future service, are anticipated to be paid as follows:

(in thousands)

Plan A

Plan B

 

 

 

2005

$ 7,810

$ 2,007

2006

$ 8,092

$ 2,090

2007

$ 8,882

$ 2,087

2008

$ 9,702

$ 2,108

2009

$ 11,049

$ 2,421

2010-2014

$ 70,483

$ 11,427

Under SFAS No. 87, "Employers' Accounting for Pensions," Energen recognized an additional minimum pension liability for the accumulated benefit obligation in excess of plan assets at December 31, 2004 and 2003, of $27.8 million and $25.7 million, respectively, based on the Company's September 30 measurement date. Alagasco established a regulatory asset of $19.7 million and $18.1 million as of December 31, 2004 and 2003, respectively, for the portion of the total benefit obligation to be recovered through rates in future periods in accordance with SFAS No. 71. An intangible asset was recorded for the unrecognized prior service cost of $1.6 million and $3.7 million at December 31, 2004 and 2003, respectively. The balance of $4.3 million and $2.5 million at December 31, 2004 and 2003, respectively, was recorded as a component of accumulated other comprehensive income, net of tax. The Company made discretionary contributions of $21.7 million in the fourth quarter of 2004 and $3.2 million in th e fourth quarter of 2003.

The Company has supplemental retirement plans with certain key executives providing payments on retirement, termination, death or disability. Expense under these agreements for the years ended December 31, 2004, 2003 and 2002 was $1,929,000, $386,000, and $314,000, respectively. For its supplemental retirement plans, the Company used a September 30 measurement date. At September 30, 2004 and 2003, the accumulated post-retirement benefit obligation related to these agreements was $18.3 million and $15.8 million, respectively, and the projected benefit obligation was $25.5 million and $23.2 million, respectively. The Company recorded a minimum pension liability for supplemental retirement plans of $14.2 million and $9.9 million at December 31, 2004 and 2003, respectively. An intangible asset was recorded for the unrecognized prior service cost of $2.5 million and $76,000 at December 31, 2004 and 2003, respectively, and the balance was recorded as a component of accumulated other comprehensiv e income, net of tax, of $7.6 million and $6.4 million at December 31, 2004 and 2003, respectively. An accrued post-retirement benefit liability of $3.5 million and $5.3 million was recorded at December 31, 2004 and 2003, respectively. The Company has established and funded a trust of $6.1 million and $5.9 million as of December 31, 2004 and December 31, 2003, respectively. While intended for payment of this benefit, the trust's assets remain subject to the claims of the Company's creditors. The Company is not required to make contributions to the supplemental retirement plans during 2005 but expects to fund approximately $215,000 during 2005.

In addition to providing pension benefits, the Company provides certain post-retirement health care and life insurance benefits. Substantially all of the Company's employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability. For its post-retirement benefit programs, the Company used a September 30 measurement date.

The status of the post-retirement benefit programs was as follows:

(in thousands)

Salaried Employees

 

September 30, 2004

September 30, 2003

Projected post-retirement benefit obligation:

 

 

Balance at beginning of period

$ 39,475

$ 31,008

Service cost

1,339

823

Interest cost

2,303

2,045

Actuarial loss (gain)

(5,580)

7,262

Benefits paid

(2,413)

(1,663)

Balance at end of period (September 30)

35,124

39,475

Plan assets:

 

 

Fair value of plan assets at beginning of period

29,290

24,127

Actual return on plan assets

3,838

5,064

Employer contributions

3,011

1,762

Benefits paid

(2,413)

(1,663)

Fair value of plan assets at end of period (September 30)

33,726

29,290

Amounts recognized in the consolidated balance sheets:

 

Funded status of plan

(1,398)

(10,185)

Unrecognized actuarial loss (gain)

(5,557)

2,235

Unrecognized net transition obligation

6,444

7,126

Employer contributions (October 1 to December 31)

706

650

Accrued benefit asset (liability) (December 31)

$ 195

$ (174)

(in thousands)

Union Employees

 

September 30, 2004

September 30, 2003

Projected post-retirement benefit obligation:

 

 

Balance at beginning of period

$ 33,809

$ 30,609

Service cost

498

412

Interest cost

1,913

2,010

Plan amendment

-

(158)

Actuarial loss (gain)

2,891

3,256

Benefits paid

(2,247)

(2,320)

Balance at end of period (September 30)

36,864

33,809

Plan assets:

 

 

Fair value of plan assets at beginning of period

28,628

23,895

Actual return on plan assets

3,902

5,829

Employer contributions

1,475

1,224

Benefits paid

(2,247)

(2,320)

Fair value of plan assets at end of period (September 30)

31,758

28,628

Amounts recognized in the consolidated balance sheets:

 

Funded status of plan

(5,106)

(5,181)

Unrecognized actuarial loss (gain)

(6,036)

(8,066)

Unrecognized prior service costs

58

63

Unrecognized net transition obligation (asset)

11,241

12,526

Employer contributions (October 1 to December 31)

321

500

Accrued benefit asset (liability) (December 31)

$ 478

$ (158)

 

Weighted average rate assumptions used to determine post-retirement benefit obligations at the measurement date:

 

Salaried Employees

 

September 30, 2004

September 30, 2003

Discount rate

5.75%

6.00%

Rate of compensation increase

4.00%

4.00%

 

Union Employees

 

September 30, 2004

September 30, 2003

Discount rate

5.75%

6.00%

Net periodic post-retirement benefit expense included the following:

 

Salaried Employees

Years ended December 31, (in thousands)

2004

2003

2002

Components of net periodic benefit cost:

 

 

 

Service cost

$ 1,339

$ 823

$ 831

Interest cost

2,303

2,045

2,120

Expected long-term return on assets

(1,626)

(1,298)

(1,678)

Actuarial loss (gain)

-

-

(434)

Transition amortization

682

682

682

Net periodic expense

$ 2,698

$ 2,252

$ 1,521

 

Union Employees

Years ended December 31, (in thousands)

2004

2003

2002

Components of net periodic benefit cost:

 

 

 

Service cost

$ 498

$ 412

$ 807

Interest cost

1,913

2,010

2,800

Expected long-term return on assets

(2,627)

(2,102)

(2,472)

Actuarial loss (gain)

(414)

(283)

(93)

Prior service cost

4

16

12

Transition amortization

1,285

1,285

1,285

Net periodic expense

$ 659

$ 1,338

$ 2,339

Net periodic post-retirement benefit expense for Alagasco was $2,573,000, $2,902,000 and $3,493,000 for the years ended December 31, 2004, 2003 and 2002, respectively.

Weighted average rate assumptions to determine net periodic benefit costs for the years ending:

 

Salaried Employees

 

December 31, 2004

December 31, 2003

December 31, 2002

Discount rate

5.94%

6.75%

7.50%

Expected long-term return on plan assets

8.75%

9.00%

9.00%

Rate of compensation increase

4.00%

4.50%

4.50%

 

Union Employees

 

December 31, 2004

December 31, 2003

December 31, 2002

Discount rate

5.94%

6.75%

7.50%

Expected long-term return on plan assets

8.75%

9.00%

9.00%

 

 

Assumed post-65 health care cost trend rates used to determine the post-retirement benefit obligation at the measurement date:

 

Salaried Employees

 

September 30, 2004

September 30, 2003

Health care cost trend rate assumed for next year

11.00%

10.00%

Rate to which the cost trend rate is assumed to decline

5.00%

6.00%

Year that rate reaches ultimate rate

2010

2008

 

Union Employees

 

September 30, 2004

September 30, 2003

Health care cost trend rate assumed for next year

11.00%

10.00%

Rate to which the cost trend rate is assumed to decline

5.00%

6.00%

Year that rate reaches ultimate rate

2010

2008

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

(in thousands)

Salaried Employees

 

1-Percentage Point Increase

1-Percentage Point Decrease

Effect on total of service and interest cost

$ 520

$ (399)

Effect on net post-retirement benefit obligation

$ 2,627

$ (2,158)

(in thousands)

Union Employees

 

1-Percentage Point Increase

1-Percentage Point Decrease

Effect on total of service and interest cost

$ 217

$ (175)

Effect on net post-retirement benefit obligation

$ 2,838

$ (2,358)

The Company's weighted-average post-retirement benefit program asset allocations by asset category were as follows:

 

Salaried Employees

 

December 31, 2004

December 31, 2003

Asset category:

Equity securities

70%

91%

Debt securities

20%

7%

Other

10%

2%

Total

100%

100%

 

Union Employees

 

December 31, 2004

December 31, 2003

Asset category:

Equity securities

70%

92%

Debt securities

20%

7%

Other

10%

1%

Total

100%

100%

Equity securities for the post-retirement benefit programs do not include the Company's common stock. The Company expects to make discretionary contributions of $2.8 million to post-retirement benefit program assets during 2005.

 The following post-retirement benefit payments, which reflect expected future service are anticipated to be paid:

(in thousands)

Salaried Employees

Union Employees

 

 

 

2005

$ 1,779

$ 2,080

2006

$ 1,881

$ 2,183

2007

$ 2,015

$ 2,337

2008

$ 2,162

$ 2,502

2009

$ 2,286

$ 2,620

2010-2014

$ 13,309

$ 14,648

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

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

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

The Company has a long-term disability plan covering most salaried employees. The Company had expense for the years ended December 31, 2004, 2003 and 2002 of $938,000, $265,000 and $304,000, respectively.

On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Deferring recognition of the Medicare impact was permitted by FSP No. 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The FASB superseded FSP No. 106-1 with the issuance of FSP No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," in May 2004, which provided more specific authoritative guidance on the accounting for this federal subsidy. The Company adopted FSP No. 106-2 during the third quarter of 2004 and reduced its annual non-cash postretirement health expense by approximately $396,000. In addition, the adoption resulted in a reduction in the disclosed accumulated postretirement benefit obligation by $3.4 million. The adoption of FSP No. 106-2 did not requ ire changes to previously reported information.

6. COMMON STOCK PLANS

A majority of Company employees are eligible to participate in the Energen Employee Savings Plan (ESP) by electing to contribute a portion of their compensation to the ESP. The Company matches a percentage of the contributions and may make additional contributions of Company common stock (new issue or treasury shares) or funds for the purchase of Company common stock. Prior to January 1, 2004, employees were allowed to invest their elective contributions in Company stock. The Company stock is no longer an investment option for new elective contributions. Vested employees may diversify 100% of their ESP Company stock account into other ESP investment options regardless of whether the Company stock was acquired through elective contribution, Company match, Company contribution or reinvestment of earnings. At December 31, 2004, total shares reserved for issuance equaled 540,054. Expense associated with Company contributions to the ESP was $4,210,000, $4,199,000 and $3,963,000 for the year s ended December 31, 2004, 2003 and 2002, respectively.

In 1992 the Company adopted the Energen Corporation 1992 Long-Range Performance Plan which provided for the award of up to 1,000,000 performance units, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of a four-year award period. Under the Plan, a portion of the performance units is payable with Company common stock. According to the provisions of the 1992 plan, performance units were not available for award after September 30, 2001. In October 2001, the Company added provisions for the award of future performance units under the 1997 Stock Incentive Plan. Under the 1997 Stock Incentive Plan, 68,150 and 117,500 performance units were awarded in the years ended December 31, 2004 and 2003, respectively. The Company recorded expense of $8,708,000, $5,653,000 and $2,136,000 for the years ended December 31, 2004, 2003 and 2002, respectively, under the Plans.

The 1997 Stock Incentive Plan, along with the Energen Corporation 1988 Stock Option Plan, provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plans provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. In addition, the 1997 Stock Incentive Plan provides for the grant of restricted stock with 65,760 and 53,475 shares awarded in the years ended December 31, 2004 and 2003, respectively. The sale or transfer of the shares is limited during certain periods. The Company recorded expense of $1,390,000, $1,076,000 and $743,000 for the years ended December 31, 2004, 2003 and 2002, respectively, related to restricted stock. Under the 1988 Stock Option Plan, 540,000 shares of Company common stock reserved for issuance have been granted. At December 31, 2004, the remaining shares reserved for issuance totaled 1,263,604 under the 1997 Stock Incentive Plan. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.

Transactions under the plans are summarized as follows:

 

1997 Stock Incentive Plan

1988 Stock Option Plan

 

 

Shares

Weighted Average Exercise Price

 

Shares

Weighted Average Exercise Price

Outstanding at December 31, 2001

508,262

$ 21.87

158,114

$ 13.81

Exercised

(20,379)

18.46

(22,600)

9.19

Forfeited

(2,390)

24.44

-

-

Outstanding at December 31, 2002

485,493

22.00

135,514

14.58

Granted

122,080

29.71

-

-

Exercised

(122,153)

21.97

(32,514)

15.16

Outstanding at December 31, 2003

485,420

23.95

103,000

14.39

Granted

41,380

42.75

-

-

Exercised

(174,980)

21.66

(74,000)

14.24

Forfeited

(4,200)

24.52

-

-

Outstanding at December 31, 2004

347,620

$ 27.44

29,000

$ 14.78

Exercisable at December 31, 2001

249,349

$ 19.66

158,114

$ 13.81

Exercisable at December 31, 2002

299,619

$ 20.56

135,514

$ 14.58

Exercisable at December 31, 2003

243,000

$ 21.70

103,000

$ 14.39

Exercisable at December 31, 2004

248,550

$ 21.24

29,000

$ 14.78

Remaining reserved for issuance at December 31, 2004

1,263,604

-

-

-

Total options granted under the 1997 Stock Option Plan during 2004 and 2003 included 41,380 shares and 66,780 shares which had a weighted average grant-date fair value of $14.21 and $12.10, respectively. The Company recorded expense of $465,000 and $269,000 during the years ended December 31, 2004 and 2003 on these shares.

The following table summarizes information about options outstanding as of December 31, 2004:

1997 Stock Incentive Plan

1988 Stock Option Plan

Range of Exercise Prices

 

Shares

Weighted Average Remaining Contractual Life

Range of Exercise Prices

 

Shares

Weighted Average Remaining Contractual Life

$18.25-$18.81

55,362

3.91 years

$11.06

14,000

0.92 years

$27.44

64,600

5.83 years

$18.25

15,000

2.92 years

$22.63

66,398

6.83 years

-

-

-

$29.71

119,880

8.08 years

-

-

-

$42.75

41,380

9.08 years

-

-

-

$18.25-$42.75

347,620

6.88 years

$11.06-$18.25

29,000

1.95 years

Of the total shares granted during 2004 and 2003, 12,500 and 55,300, respectively, had stock appreciation rights. The 2004 grants were issued under the 2004 Stock Appreciation Rights Plan which provides for the payment of cash incentives measured by long-term appreciation in the Company's stock. The 2003 grants were issued under the 1997 Stock Incentive Plan as discussed above which provided for the issuance of stock appreciation rights. Expense associated with stock appreciation rights of $916,000 and $209,000 was recorded for the years ended December 31, 2004 and 2003, respectively.

In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan to pay part of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 5,400 and 7,500 shares were awarded during the years ended December 31, 2004 and 2003, respectively, leaving 124,539 shares reserved for issuance as of December 31, 2004.

The Company's Dividend Reinvestment and Direct Stock Purchase Plan includes a direct stock purchase feature which allows purchases by non-shareholders. As of December 31, 2004, 549,146 common shares were reserved under this Plan.

By resolution adopted May 25, 1994, and supplemented by a resolution adopted April 26, 2000, the Board authorized the Company to repurchase up to 1,782,200 shares of the Company's common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2004 and 2002. For the year ended December 31, 2003, the Company repurchased 650 shares pursuant to its repurchase authorization. As of December 31, 2004, a total of 1,075,350 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company's stock compensation plans. For the years ended December 31, 2004, 2003 and 2002, the Company acquired 18,022 shares, 29,232 shares and 5,319 shares, respectively, in connection with its stock compensation plans.

On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan) designed to protect shareholders from coercive or unfair takeover tactics. Under certain circumstances, the 1998 Plan provides shareholders with the right to acquire the Company's Series 1998 Junior Participating Preferred Stock (or, in certain cases, securities of an acquiring person) at a significant discount. Terms and conditions are set forth in a Rights Agreement between the Company and its Rights Agent. Under the 1998 Plan, one right is associated with each outstanding share of common stock. Rights outstanding under the 1998 Plan at December 31, 2004, were convertible into 362,235 shares of Series 1998 Junior Participating Preferred Stock (1/100 share of preferred stock for each full right) subject to adjustment upon occurrence of certain take-over related events. No rights were exercised or exercisable during the period. The price at which the rights would be exercised is $70 per right, subject to adjust ment upon occurrence of certain take-over related events. In general, absent certain take-over related events as described in the Plan, the rights may be redeemed prior to the July 27, 2008, expiration for $0.01 per right.

In 1997 the Company adopted the 1997 Deferred Compensation Plan to allow officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company's common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants' accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust's assets remain subject to the claims of the Company's creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related def erred compensation obligation in the Consolidated Statements of Shareholders' Equity.

7. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Certain of Alagasco's long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $183.7 million through October 2013. 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 52.2 Bcf through December 2014.

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. 

The State of New Mexico recently issued new regulations related to below-grade storage pits. Such pits are used to temporarily hold produced fluids until they can be disposed of permanently. Under the new regulations, the storage pits must be constructed with secondary containment and leak detection, and all such pits will require an annual certification attesting that the storage pits do not leak. As a result of the new regulation, during 2004, the Company capitalized $0.5 million as part of its recent acquisition of properties in the San Juan Basin and expensed $1.6 million as a lease operating expense. The Company does not anticipate any further remediation charges on existing properties related to the new regulations.

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 results of financial position, results of operations or cash flows of Alagasco.

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

Various pending or threatened legal proceedings arising in the normal course of business are in progress currently, and the Company has accrued a provision for estimated costs.

Lease Obligations: Alagasco leases the Company's headquarters building over a 25-year term and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Energen's total lease payments related to leases included as operating lease expense were $10,638,000, $8,412,000 and $8,273,000 for the years ended December 31, 2004, 2003 and 2002. Minimum future rental payments required after 2004 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

Years Ending December 31, (in thousands)

2005

2006

2007

2008

2009

2010 and thereafter

$ 3,857

$ 3,935

$ 3,681

$ 3,303

$ 3,301

$ 35,811

Alagasco's total payments related to leases included as operating expense were $2,728,000, $2,602,000 and $2,362,000 for the years ended December 31, 2004, 2003 and 2002. Minimum future rental payments required after 2004 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

 

Years Ending December 31, (in thousands)

2005

2006

2007

2008

2009

2010 and thereafter

$ 3,186

$ 3,266

$ 3,239

$ 3,171

$ 3,178

$ 35,811

 

8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial Instruments: The stated value of cash and cash equivalents, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen's long-term debt, including the current portion, with a carrying value of $624,450,000, would be $702,692,000 at December 31, 2004. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, with a carrying value of $139,450,000, would be $162,535,000 at December 31, 2004. The fair values were based on the market value of debt with similar maturities and current interest rates.

Alagasco had an agreement with a financial institution whereby it could sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program. Effective February 1, 2004, Alagasco no longer sells its installment receivables. Alagasco sold installment receivables of $302,000, $4,992,000 and $5,010,000 in the years ended December 31, 2004, 2003 and 2002, respectively. At December 31, 2004 and 2003, the balances of these installment receivables were $4,076,000 and $8,167,000, respectively. Receivables sold under this agreement were considered financial instruments with off-balance sheet risk. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. The fair value of these guarantees is not significant to the Company and is recorded as a non-current other liability.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the consolidated balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At December 31, 2004, the fixed price purchased under theses guarantees had a maximum term outstanding through November 2005 with an aggregate purchase price of $10.5 million and a market value of $9.2 million.

Price Risk: The Company adopted SFAS No. 133 on October 1, 2000. This statement 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 Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, 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 in operating revenues when the forecasted transaction affects earnings.

The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. 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.

Energen Resources from time to time enters into cash flow derivative commodity instruments to hedge its price exposure on its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco from time to time enters into cash flow derivative commodity instruments to hedge its gas supply price exposure. Such instruments may include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange 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 or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. In cases where this arrangement exists, generally the credit ratings must be maintained at investment grade status to have available counterparty credit.

Energen Resources had certain agreements with Enron North America Corp. (Enron) as the counterparty as of October 1, 2001. As prescribed by SFAS No. 133, the value of the outstanding Enron contracts which qualified for cash flow hedge accounting treatment was reflected on the balance sheet as an asset and the effective portion of the derivative was reported as other comprehensive income (OCI), a component of shareholders' equity. These outstanding contracts ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. The Company recorded an expense to O&M for the writedown to fair value of the asset related to the effected derivative contracts. The deferred revenues related to the non-performing hedges were recorded in accumulated other comprehensive income until such time as they were reclassified to earnings in operating revenues as originally forecasted to occur. As a result, net income in the year ended December 31, 2002, reflected a total non-cas h benefit of $5.7 million, net of tax, related to the Enron hedge position.

At December 31, 2004, the Company had current losses on the fair value of derivatives of $40.7 million included in accounts payable and $3.2 million of non-current losses included in deferred credits and other liabilities on the consolidated balance sheet. At December 31, 2003, the Company had current gains on the fair value of derivatives of $0.6 million included in prepayments and other, current losses of $34.6 million included in accounts payable and $3.5 of non-current losses included in deferred credits and other liabilities on the consolidated balance sheet. As of December 31, 2004 and 2003, the Company was not required to post collateral with its counterparties.

As of December 31, 2004, $23.5 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to operating revenues in earnings during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. Gains and losses on derivative instruments that are not accounted for as cash flow hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. The Company recorded a $1.3 million after-tax loss in 2004 for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, the Company recorded an after-tax loss of $3.5 million in 2004 on contracts which did not meet the definition of cash flow hedges unde r SFAS No. 133. As of December 31, 2004, the Company had 0.31 Bcf of gas hedges with a fair value pretax gain of $0.3 million which expire during 2005 that did not meet the definition of a cash flow hedge but are considered by the Company to be viable economic hedges. The Company had $15.6 million and $13.9 million included in current and noncurrent deferred income taxes on the consolidated balance sheet related to other comprehensive income as of December 31, 2004 and 2003, respectively.

As of December 31, 2004, Energen Resources entered into the following transactions for 2005 and subsequent years:

Production Period

Total Hedged Volumes

Average Contract Price

Description

Natural Gas

2005

18.8 Bcf

$6.01 Mcf

NYMEX Swaps

 

20.6 Bcf

$5.00 Mcf

Basin Specific Swaps

Natural Gas Basis Differential

2005

1.6 Bcf

**

Basis Swaps

Oil

2005

1,740 MBbl

$34.37 Bbl

NYMEX Swaps

 

960 MBbl

$33.21 Bbl

West Texas Sour Swaps

2006

360 MBbl

$37.12 Bbl

NYMEX Swaps

Oil Basis Differential

2005

1,003 MBbl

**

Basis Swaps

Natural Gas Liquids

2005

50.4 MMGal

$0.54 Gal

Liquids Swaps

2006

30.2 MMGal

$0.56 Gal

Liquids Swaps

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

All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, 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 Resourc es has hedged exposures to the variability of cash flows is through December 31, 2006.

At December 31, 2004, Alagasco recorded an $8.1 million gain as an asset in prepayments and other with a corresponding current regulatory liability of $8.1 million representing the fair value of derivatives. At December 31, 2003, Alagasco recognized a current gain of $13.2 million in prepayments and other and a noncurrent gain of $8.7 million in deferred charges and other. Alagasco recognized a corresponding current regulatory liability of $13.2 million and a noncurrent regulatory liability of $8.7 million. Alagasco also recorded a loss of $0.3 million in accounts payable and a corresponding regulatory asset.

Concentration of Credit Risk: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, in that the Company's oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality for its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 460,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

9. RECONCILIATION OF EARNINGS PER SHARE

Years ended December 31,

 

 

 

 

 

 

 

 

 

(in thousands, except per share amounts)

2004

 

2003

2002

 

Income

Shares

Per Share Amount

Income

Shares

Per Share Amount

Income

Shares

Per Share Amount

Basic EPS

$127,463

36,273

$3.51

$ 110,654

35,434

$ 3.12

$ 68,639

33,605

$ 2.04

Effect of dilutive securities

 

 

 

 

 

 

 

 

 

Long-range performance shares

106

 

 

73

 

 

88

 

Stock options

 

166

 

 

201

 

 

143

 

Restricted stock

 

14

 

 

9

 

 

2

 

Diluted EPS

$127,463

36,559

$ 3.49

$ 110,654

35,717

$ 3.10

$ 68,639

33,838

$ 2.03

 

For the years ended December 31, 2004 and 2003, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS. For the year ended December 31, 2002, the Company had 136,300 options and 20,464 shares of non-vested restricted stock that were excluded from the computation of diluted EPS, as their effect was anti-dilutive.

10. ASSET RETIREMENT OBLIGATIONS

In 2002, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Upon adoption of SFAS No. 143, the Company recognized a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalized an equal amount as a cost of the asset as of January 1, 2002. Upon initial application of the Statement, the Company recorded a cumulative effect of a change in accounting principle to recognize a liability for existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost. For the year ended December 31, 2002, Energen Resources recognized additional capitalized costs of $20.1 million, depreciation expense of $1.7 million, accretion expense of $1.8 million, a deferred tax asset of $1.3 million and an after-tax charge of $2.2 million for the cumulative effect on prior years. 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 will record the resulting gain or loss.

In 2004, 2003 and 2002, Energen Resources recognized activity representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)

 

Balance of ARO as of January 1, 2002

$ 20,493

Liabilities incurred during the year ended December 31, 2002

4,923

Accretion expense

1,819

Balance of ARO as of December 31, 2002

$ 27,235

Liabilities incurred during the year ended December 31, 2003

1,139

Liabilities settled during the year ended December 31, 2003

(3,749)

Accretion expense

1,890

Balance of ARO as of December 31, 2003

$ 26,515

Liabilities incurred during the year ended December 31, 2004

1,172

Liabilities settled during the year ended December 31, 2004

(413)

Revision in estimated cash flows

5,302

Accretion expense

2,265

Balance of ARO as of December 31, 2004

$ 34,841

The Company's gas distribution system operates under various property easement agreements primarily related to public rights of way. In some instances, the entity granting the easement retains the option to require certain actions in the event the Company abandons the asset. Since the Company expects its gas distribution assets to be operated in perpetuity and historical abandonment costs resulting from such easement agreements have been de minimis, no asset retirement obligation has been recorded. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. In accordance with SFAS No. 71, the accumulated asset removal costs of $110.9 million and $103.7 million for December 31, 2004 and 2003, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the consolidated balance sheets.

11. SUPPLEMENTAL CASH FLOW INFORMATION

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

Years ended December 31, (in thousands)

2004

2003

2002

Interest paid, net of amount capitalized

$ 40,557

$ 39,963

$ 43,085

Income taxes paid

$ 8,352

$ 10,929

$ 9,838

Noncash investing activities:

 

 

 

First Permian, L.L.C. stock issuance

$ -

$ -

$ 72,891

Capitalized depreciation

$ 94

$ 123

$ 223

Allowance for funds used during construction

$ 1,247

$ 948

$ 1,336

Under SFAS No. 143, the Company recorded a non-cash adjustment for accretion expense of $2.3 million and $1.9 million during 2004 and 2003, respectively. During 2002, additional capitalized costs of $20.1 million, a non-current liability of $27.2 million, accretion expense of $1.8 million, depreciation expense of $1.7 million, and a deferred tax asset of $1.3 million were recorded, all of which are non-cash adjustments related to Energen's cash flow activities.

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

Years ended December 31, (in thousands)

2004

2003

2002

Interest paid, net of amount capitalized

$ 11,248

$ 12,477

$ 14,012

Income taxes paid

$ 11,034

$ 12,754

$ 15,519

Noncash investing activities:

 

 

 

Capitalized depreciation

$ 94

$ 123

$ 223

Allowance for funds used during construction

$ 1,192

$ 1,529

$ 1,336

 

12. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS

On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which retains the previous asset impairment requirements of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses in the sale of certain oil and gas properties and writedowns of certain 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 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 develope d or undeveloped properties. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. Energen Resources had no property sales during 2004 or properties reclassified as held-for-sale as of December 31, 2004. In 2003, Energen Resources recorded a pre-tax writedown to fair value based upon expected market value of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region. These properties were subsequently sold during 2003 for a pre-tax gain of $0.4 million. During 2002, Energen Resources recorded a pre-tax writedown of $2.8 million on certain non-strategic gas properties located in the Gulf Coast region, adjusting the carrying amount of the properties to their fair value based upon expected future discounted cash flows. In November 2002, the Company sold these properties for approximately the carrying amount. The gain on disposals for the years ended December 31, 2003 and 2002, totaled $9.4 million and $3.7 million largely due to sales of propert y located in the San Juan and Permian basins.

The following are the results of operations from discontinued operations:

Years ended December 31,

(in thousands, except per share data)

2004

2003

2002

 

 

 

 

Oil and gas revenues

$    4

$    3,586

$    10,362

 

 

 

 

Pretax income (loss) from discontinued operations

$    29

$    1,594

$      (133)

Income tax expense (benefit)

11

621

(53)

Income (Loss) from Discontinued Operations

18

973

(80)

 

 

 

 

Impairment charge on held-for-sale property

-

(10,404)

(2,815)

Gain (loss) on disposal

(8)

9,448

3,706

Income tax expense (benefit)

(3)

(372)

348

Gain (Loss) on Disposal

(5)

(584)

543

 

 

 

 

Total Income from Discontinued Operations

$        13

$        389

$        463

 

 

 

 

Diluted Earnings Per Average Common Share

 

 

 

Income from Discontinued Operations

$   -

$   0.03

$      -

Gain (Loss) on Disposal

   -

   (0.02)

   0.02

Total Income from Discontinued Operations

$       -

$       0.01

$       0.02

 

 

 

 

Basic Earnings Per Average Common Share

 

 

 

Income from Discontinued Operations

$   -

$   0.03

$    -

Gain (Loss) on Disposal

   -

   (0.02)

   0.02

Total Income from Discontinued Operations

$       -

$       0.01

$       0.02

 

13. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

The Company's business is seasonal in character. The following data summarizes quarterly operating results. The summarized quarterly information may differ from amounts previously reported due to changes in the classification of properties reported as discontinued operations as required by SFAS No. 144 (see Note 12).

 

Year Ended December 31, 2004

(in thousands, except per share amounts)

First

Second

Third

Fourth

Operating revenues

$ 351,429

$ 188,177

$ 166,498

$ 231,280

Operating income

$ 106,040

$ 46,136

$ 32,302

$ 60,598

Income from continuing operations

$ 60,197

$ 22,268

$ 13,732

$ 31,253

Net income

$ 60,185

$ 22,270

$ 13,740

$ 31,268

Diluted earnings per average common share

 

 

 

 

Continuing operations

$ 1.65

$ 0.61

$ 0.37

$ 0.85

Net income

$ 1.65

$ 0.61

$ 0.37

$ 0.85

Basic earnings per average common share

 

 

 

 

Continuing operations

$ 1.66

$ 0.61

$ 0.38

$ 0.86

Net income

$ 1.66

$ 0.61

$ 0.38

$ 0.86

 

Year Ended December 31, 2003

(in thousands, except per share amounts)

First

Second

Third

Fourth

Operating revenues

$ 309,658

$ 184,030

$ 146,141

$ 202,392

Operating income

$ 96,120

$ 50,046

$ 28,897

$ 42,825

Income from continuing operations

$ 53,323

$ 24,459

$ 11,457

$ 21,026

Net income

$ 54,581

$ 23,347

$ 11,896

$ 20,830

Diluted earnings per average common share

 

 

 

 

Continuing operations

$ 1.52

$ 0.69

$ 0.32

$ 0.58

Net income

$ 1.56

$ 0.66

$ 0.33

$ 0.57

Basic earnings per average common share

 

 

 

 

Continuing operations

$ 1.54

$ 0.70

$ 0.32

$ 0.58

Net income

$ 1.57

$ 0.67

$ 0.33

$ 0.58

 

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

 

Year Ended December 31, 2004

(in thousands)

First

Second

Third

Fourth

Operating revenues

$ 255,202

$ 92,744

$ 62,162

$ 116,632

Operating income (loss)

$ 62,014

$ 4,575

$ (10,130)

$ 9,740

Net income (loss)

$ 36,319

$ 559

$ (7,745)

$ 4,657

 

Year Ended December 31, 2003

(in thousands)

First

Second

Third

Fourth

Operating revenues

$ 221,139

$ 94,248

$ 58,147

$ 115,565

Operating income (loss)

$ 57,200

$ 6,988

$ (9,575)

$ 12,235

Net income (loss)

$ 33,447

$ 2,135

$ (7,781)

$ 5,216

14. ACQUISITION OF OIL AND GAS PROPERTIES

On August 2, 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million. The effective date of the acquisition was August 1, 2004. Energen Resources acquired an estimated 245 Bcfe of proved natural gas and natural gas liquids reserves. Approximately 51 percent of the proved reserves were estimated to be behind pipe and undeveloped. Approximately 80 percent of the acquisition reserves are gas with natural gas liquids comprising the balance. Energen used its short-term credit facilities and internally generated cash flows to finance the acquisition. A portion of the short-term debt incurred to finance the acquisition was repaid when Energen issued $100 million of Floating Rate Senior Notes in November 2004.

On April 8, 2002, Energen Resources completed its purchase of oil and gas properties located in the Permian Basin in west Texas from First Permian, L.L.C. (First Permian), for approximately $120 million cash and 3,043,479 shares of the Company's common stock. The common stock was valued at $23.95 per share, the average stock price at the time Energen signed the related Purchase and Sale Agreement. The total acquisition approximated $184 million.

Summarized below are the consolidated results of operations for the year ended December 31, 2004, 2003 and 2002, on an unaudited pro forma basis as if the purchase of assets in the San Juan basin had occurred at the beginning of 2003 and the purchase of assets in the Permian basin had occurred in the beginning of 2002. The pro forma information is based on the Company's consolidated results of operations for the years ended December 31, 2004, 2003 and 2002, and on the data provided by the seller, after giving effect to the issuance of 3,043,479 shares of common stock. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor are they indicative of results of the future operations of the combined enterprises.

Years ended December 31,

(Unaudited) (in thousands, except per share data)

2004

2003

2002

Operating revenues

$  949,730

$  860,994

$  675,156

Income from continuing operations before cumulative effect of a change in accounting principle

$  128,254

$  111,442

$   71,265

Net income

$  128,267

$  111,831

$  69,508

Diluted earnings per average common share

$ 3.51

$ 3.13

$ 2.05

Basic earnings per average common share

$ 3.54

$ 3.16

$ 2.07

 

15. REGULATORY ASSETS AND LIABILITIES

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

Energen Corporation

 

 

(in thousands)

December 31, 2004

December 31, 2003

 

Current

Noncurrent

Current

Noncurrent

Regulatory assets:

 

 

 

 

Pension asset

$ -

$ 19,650

$ -

$ 18,082

Risk management activities

-

-

251

-

Total regulatory assets

$ -

$ 19,650

$ 251

$ 18,082

Regulatory liabilities:

 

 

 

 

Enhanced stability reserve

Gas supply adjustment

Risk management activities

RSE

Unbilled service margin

Asset removal costs, net

Other

$ 3,671 6,964

8,097

1,251

27,077

-

-

$ -

-

-

-

-

110,912

1,016

$ 3,481 8,744

13,184

2,619

26,118

-

-

$ -

-

8,650

-

-

103,727

1,050

Total regulatory liabilities

$ 47,060

$ 111,928

$ 54,146

$ 113,427

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

16. EQUITY AND DEBT OFFERINGS

In November 2004, Energen issued $100 million of Floating Rate Senior Notes (Senior Notes) due November 15, 2007. The interest rate is the three-month LIBOR Rate plus .35%, reset quarterly. At December 31, 2004, the interest rate was 2.68 percent on the Senior Notes. In October 2003, Energen issued $50 million of long-term debt due October 1, 2013. The 5% coupon notes were priced at 99.557 percent to yield 5.057 percent. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. The sale of shares began May 9, 2003, and concluded on July 16, 2003, generating net proceeds of $32.1 million. These proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.

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 April 2004, Alagasco elected to call a total of $30 million of Medium-Term Notes maturing January 16, 2006, to December 15, 2023. During the second quarter of 2004, the Company recorded a pre-tax loss on debt extinguishment of $0.9 million for the call premiums and unamortized issuance costs.

In July 2004, Energen and Alagasco increased their short-term credit lines available for working capital needs to $287 million. Alagasco has been authorized by the APSC to borrow up to a total of $100 million of these available short-term credit lines.

17. TRANSACTIONS WITH RELATED PARTIES

Alagasco purchased natural gas from affiliates of $2,112,000, $3,195,000 and $1,820,000 for the years ended December 31, 2004, 2003 and 2002, respectively. These amounts are included in gas purchased for resale. All transactions are at market based pricing.

The Company's cash management program matches short-term cash surpluses with needs of its affiliates, thus minimizing total borrowing from outside sources. Alagasco had net receivables from affiliates of $2,190,000 at December 31, 2004 and net payables to affiliates of $37,290,000 at December 31, 2003. Interest income /expense between affiliates is calculated monthly based on a weighted average interest rate. The weighted average interest rate during 2004 and 2003 was 2.29 percent and 1.71 percent, respectively. The Company allocates certain corporate costs to Energen Resources and Alagasco based on the nature of the expense to be allocated using various factors including, but not limited to, total assets, earnings, or number of employees.

18. OTHER INCOME AND EXPENSE

The following table details Energen's other income and expense amounts on the consolidated income statements:

Years ended December 31, (in thousands)

2004

2003

2002

Allowance for funds used during construction

$ 1,247

$ 948

$ 1,336

Merchandise revenues

671

7,696

14,155

Other

1,027

100

153

Total other income

$ 2,945

$ 8,744

$ 15,644

 

 

 

 

Cost of goods sold

$ 1,701

$ 8,549

$ 10,215

Other merchandise expense

514

1,428

4,888

Total other expense

$ 2,215

$ 9,977

$ 15,103

The following table details Alagasco's other income and expense amounts on the income statements:

Years ended December 31, (in thousands)

2004

2003

2002

Allowance for funds used during construction

$ 1,247

$ 948

$ 1,336

Merchandise revenues

637

3,876

4,184

Other

1,342

256

-

Total other income

$ 3,226

$ 5,080

$ 5,520

 

 

 

 

Cost of goods sold

$ 1,701

$ 5,142

$ 2,702

Other merchandise expense

494

127

3,578

Total other expense

$ 2,195

$ 5,269

$ 6,280

The sale of merchandise inventory items are reflected in other income and expense. Effective February 1, 2004, Alagasco no longer participates in direct sales of natural gas merchandise. Alagasco continues to work closely with various contractors and retail companies to meet the merchandise requirements of its customers.

19. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)

SFAS No. 141, "Business Combinations," requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142, "Goodwill and Other Intangible Assets," establishes guidelines in accounting for goodwill and other intangible assets. The appropriate applications of SFAS No. 141 and SFAS No. 142 were considered to determine whether oil and gas mineral rights should be classified separately as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. In September 2004, the Board issued FASB Staff Position (FSP) No. 142-2, "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil and Gas Producing Entities," which excluded oil and gas companies; therefore, the Company will continue to report lease rights as tangible assets on the balance sheet.

On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Deferring recognition of the Medicare impact was permitted by FSP No. 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." The FASB superseded FSP No. 106-1 with the issuance of FSP No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," in May 2004, which provided more specific authoritative guidance on the accounting for this federal subsidy. The Company adopted FSP No. 106-2 during the third quarter of 2004 and reduced its annual non-cash postretirement health expense by approximately $396,000. In addition, the adoption resulted in a reduction in the disclosed accumulated postretirement benefit obligation by $3.4 million. The adoption of FSP No. 106-2 did not requ ire changes to previously reported information.

The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 (as amended), which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation, effective January 1, 2003. In December 2004, the Board issued SFAS No. 123 (revised 2004), "Share-Based Payment," which requires the fair value base method of accounting for all public entities using an option-pricing model that reflects the specific economics of a company's transactions. This statement is effective for the first interim or annual reporting period beginning after June 15, 2005. The Company is currently reviewing the impact of this pronouncement on stock-based compensation.

In December 2004, the Board issued FSP No. 109-1, "Application of SFAS No. 109, Accounting for Income Taxes, to the provision within the American Jobs Creation Act of 2004 (the Act) that provides a tax deduction on qualified production activities." This Act includes a tax deduction of up to 9 percent (when fully phased-in) of the lesser of (a) qualified production activities income as defined in the Act, or (b) taxable income determined without regard to this deduction. This tax deduction would apply to qualified production activities of Energen Resources and would be limited to 50 percent of W-2 wages paid by the Company. Pursuant to FSP No. 109-1, the deduction will be reported in the period in which the deduction is claimed on the Company's tax return and will not have an effect on deferred tax assets or deferred tax liabilities. The Company estimates the impact of this tax legislation will reduce income tax expense by approximately $1 million during 2005.

During 2004, the Board proposed FSP No. 19-a, "Accounting for Suspended Well Costs," which allows exploratory wells to be capitalized when the well has a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. The impact of this proposed position on the Company is expected to be immaterial.

20. OIL AND GAS OPERATIONS (Unaudited)

The following schedules detail historical financial data of the Company's oil and gas operations. Certain reclassifications have been made to conform the prior years' financial statements to the current-year presentation. Terms appearing in the schedules prescribed by the Securities and Exchange Commission (SEC) are briefly described as follows:

Exploration Expenses are costs primarily associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired and expired leaseholds.

Development Costs include costs necessary to gain access to, prepare and equip development wells in areas of proved reserves.

Production (Lifting) Costs include costs incurred to operate and maintain wells.

Gross Revenues are reported after deduction of royalty interest payments.

Gross Well or Acre is a well or acre in which a working interest is owned.

Net Well or Acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one.

Dry Well is 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.

Productive Well is an exploratory or a development well that is not a dry well.

Capitalized Costs

(in thousands)

December 31, 2004

December 31, 2003

Proved

$ 1,587,512

$ 1,191,528

Unproved

3,607

5,812

Total capitalized costs

1,591,119

1,197,340

Accumulated depreciation, depletion, and amortization

381,734

310,368

Capitalized costs, net

$ 1,209,385

$ 886,972

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

Years ended December31, (in thousands)

2004

2003

2002

Property acquisition:

 

 

 

Proved

$ 273,735

$ 40,219

$ 173,984

Unproved

665

267

10,193

Exploration

5,060

468

527

Development

125,211

122,094

122,494

Total costs incurred

$ 404,671

$ 163,048

$ 307,198

 

Results of Continuing Operations: The following table sets forth results of the Company's oil and gas continuing operations:

Years ended December 31, (in thousands)

2004

2003

2002

Gross revenues

$ 412,935

$ 354,816

$ 245,397

Production (lifting costs)

116,587

95,651

75,395

Exploration expense

2,100

1,053

3,595

Depreciation, depletion and amortization

79,302

78,241

66,594

Accretion expense

2,265

1,890

1,819

Income tax expense

80,370

66,385

23,128

Results of continuing operation from producing activities

$ 132,311

$ 111,596

$ 74,866

Average Sales Price, Production Cost and Depreciation Rate From Continuing Operations

Years ended December 31,

2004

2003

2002

Average sales price including the effects of hedging:

 

 

Gas (Mcf)

$ 4.84

$ 4.25

$ 3.17

Oil (per barrel)

$ 28.66

$ 25.56

$ 24.13

Natural gas liquids (per barrel)

$ 19.03

$ 16.32

$ 12.77

Average sales price excluding the effects of hedging:

 

 

Gas (Mcf)

$ 5.68

$ 4.97

$ 2.96

Oil (per barrel)

$ 38.33

$ 29.19

$ 24.82

Natural gas liquids (per barrel)

$ 24.66

$ 18.40

$ 12.77

Average production (lifting) cost (per Mcfe)

$ 1.33

$ 1.12

$ 1.01

Average production tax (per Mcfe)

$ 0.43

$ 0.32

$ 0.25

Average depreciation rate (per Mcfe)

$ 0.91

$ 0.92

$ 0.89

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

Years ended December 31,

2004

2003

2002

Exploratory:

 

 

 

Productive

7.5

0.7

0.1

Dry

0.4

0.3

0.1

Total

7.9

1.0

0.2

Development:

 

 

 

Productive

145.5

194.2

145.9

Dry

1.0

3.0

4.3

Total

146.5

197.2

150.2

As of December 31, 2004, the Company was participating in the drilling of 8 gross development wells, with the Company's interest equivalent to 4.49 wells.

Productive Wells and Acreage: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2004, and developed and undeveloped acreage as of the latest practicable date prior to year-end:

 

 

Gross

Net

Gas Wells

 

3,678

1,960

Oil Wells

 

2,258

1,049

Developed Acreage

 

786,795

554,321

Undeveloped Acreage

 

81,294

45,239

There were 27 wells with multiple completions in 2004. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in the Permian and San Juan basins.

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

Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, Miller and Lents, Ltd., and T. Scott Hickman and Associates, Inc., independent oil and gas reservoir engineers, have reviewed the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2004. Ryder Scott Company reviewed the reserve estimates for the Black Warrior Basin and substantially all of the Permian Basin reserves. Miller and Lents, Ltd. reviewed the reserves for the north Louisiana/east Texas regions. T. Scott Hickman and Associates, Inc. reviewed the reserves for the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 98 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.

Year ended December 31, 2004

Gas MMcf

Oil MBbl

NGL MBbl

Proved reserves at beginning of period

886,307

52,528

27,245

Revisions of previous estimates

(42,052)

594

(5)

Purchases

194,607

24

8,422

Discoveries and other additions

37,832

4,788

575

Production

(57,258)

(3,434)

(1,624)

Proved reserves at end of period

1,019,436

54,500

34,613

Proved developed reserves at end of period

810,083

47,792

28,079

Year ended December 31, 2003

Gas MMcf

Oil MBbl

NGL MBbl

Proved reserves at beginning of period

803,748

49,833

26,697

Revisions of previous estimates

(10,847)

1,237

(826)

Purchases

93,700

1,172

-

Discoveries and other additions

80,124

5,051

4,068

Production

(55,796)

(3,458)

(1,602)

Sales

(24,622)

(1,307)

(1,092)

Proved reserves at end of period

886,307

52,528

27,245

Proved developed reserves at end of period

714,866

40,802

23,552

Year ended December 31, 2002

Gas MMcf

Oil MBbl

NGL MBbl

Proved reserves at beginning of period

714,395

19,128

25,944

Revisions of previous estimates

(3,916)

(1,303)

624

Purchases

6,263

36,779

-

Discoveries and other additions

141,435

1,367

2,030

Production

(48,051)

(3,193)

(1,794)

Sales

(6,378)

(2,945)

(107)

Proved reserves at end of period

803,748

49,833

26,697

Proved developed reserves at end of period

672,633

36,782

24,009

During 2004, Energen Resources had no property sales.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company's crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. At December 31, 2004, 2003 and 2002, the Company had a deferred hedging loss of $41.1 million, $35.6 million and $17.2 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.

Years ended December 31, (in thousands)

2004

2003

2002

Future gross revenues

$ 8,791,050

$ 7,211,830

$ 5,455,802

Future production costs

2,797,556

2,189,464

1,754,700

Future development costs

222,519

204,513

183,818

Future net cash flows before income taxes

5,770,975

4,817,853

3,517,284

Discount at 10% per annum

3,228,215

2,685,843

1,930,739

Discounted future net cash flows before income taxes

2,542,760

2,132,010

1,586,545

Discounted future income tax expense

651,342

558,931

342,288

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

$ 1,891,418

$ 1,573,079

$ 1,244,257

Reserves and associated values were calculated using year-end prices and current costs. The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

 

Years ended December 31, (in thousands)

Year Ended December 31, 2004

Year Ended December 31, 2003

Year Ended December 31, 2002

Balance at beginning of year

$ 1,573,079

$ 1,244,257

$ 571,442

Revisions to reserves proved in prior years:

 

 

 

Net changes in prices, production costs and future development costs

147,380

365,816

658,956

Net changes due to revisions in quantity estimates

(58,378)

(14,804)

(8,380)

Development costs incurred, previously estimated

83,404

80,878

49,418

Accretion of discount

213,201

158,655

58,200

Other

9,093

39,134

(9,725)

Total revisions

394,700

629,679

748,469

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

133,714

200,880

213,625

Sales of oil and gas produced, net of production costs

(417,846)

(311,189)

(162,151)

Purchases

300,183

74,201

218,799

Sales

-

(48,107)

(14,203)

Net change in income taxes

(92,412)

(216,642)

(331,724)

Net change in standardized measure of discounted future net cash flows

318,339

328,822

672,815

Balance at end of year

$ 1,891,418

$ 1,573,079

$ 1,244,257

 

 

21. INDUSTRY SEGMENT INFORMATION

The Company is principally engaged in two business segments: the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1. Certain reclassifications have been made to conform the prior years' financial statements to the current year presentation.

 

(in thousands)

Year Ended December 31, 2004

Year Ended December 31, 2003

Year Ended December 31, 2002

Operating revenues from continuing operations

 

 

 

Oil and gas operations

$ 412,555

$ 355,336

$ 245,789

Natural gas distribution

526,740

489,099

424,431

Eliminations and other

(1,911)

(2,214)

(1,669)

Total

$ 937,384

$ 842,221

$ 668,551

Operating income (loss) from continuing operations

 

 

 

Oil and gas operations

$ 180,612

$ 153,591

$ 76,286

Natural gas distribution

66,199

66,848

59,370

Subtotal

$ 246,811

$ 220,439

$ 135,656

Eliminations and corporate expenses

(1,735)

(2,551)

(1,700)

Total

$ 245,076

$ 217,888

$ 133,956

Depreciation, depletion and amortization expense from continuing operations

Oil and gas operations

$ 81,079

$ 79,687

$ 68,009

Natural gas distribution

39,881

37,171

33,682

Total

$ 120,960

$ 116,858

$ 101,691

Interest expense

 

 

 

Oil and gas operations

$ 29,660

$ 28,577

$ 29,635

Natural gas distribution

13,737

13,967

14,557

Subtotal

$ 43,397

$ 42,544

$ 44,192

Eliminations and other

(654)

(282)

(479)

Total

$ 42,743

$ 42,262

$ 43,713

Income tax expense (benefit) from continuing operations

Oil and gas operations

$ 57,070

$ 46,616

$ 3,820

Natural gas distribution

19,703

19,675

17,825

Subtotal

$ 76,773

$ 66,291

$ 21,645

Other

(1,160)

(2,163)

(1,257)

Total

$ 75,613

$ 64,128

$ 20,388

Capital expenditures

 

 

 

Oil and gas operations

$ 403,936

$ 163,338

$ 305,476

Natural gas distribution

58,208

57,906

65,815

Other

-

-

5

Total

$ 462,144

$ 221,244

$ 371,296

Identifiable assets

 

 

 

Oil and gas operations

$ 1,315,967

$ 959,815

$ 926,839

Natural gas distribution

837,557

794,493

715,330

Subtotal

$ 2,153,524

$ 1,754,308

$ 1,642,169

Eliminations and other

28,215

23,924

843

Total

$ 2,181,739

$ 1,778,232

$ 1,643,012

Property, plant and equipment, net

 

 

 

Oil and gas operations

$ 1,214,461

$ 891,682

$ 838,526

Natural gas distribution

568,598

541,769

512,849

Other

-

-

179

Total

$ 1,783,059

$ 1,433,451

$ 1,351,554

 

 

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

Energen Corporation

Years ended December 31, (in thousands)

2004

2003

2002

 

 

 

 

ALLOWANCE FOR DOUBTFUL ACCOUNTS

Balance at beginning of year

$ 9,852

$ 8,874

$ 11,783

 

 

 

 

Additions:

 

 

 

Charged to income

4,819

5,820

5,482

Recoveries and adjustments

(290)

(616)

(495)

 

 

 

 

Net additions

4,529

5,204

4,987

 

 

 

 

Less uncollectible accounts written off

(3,909)

(4,226)

(7,896)

 

 

 

 

Balance at end of year

$ 10,472

$ 9,852

$ 8,874

 

Alabama Gas Corporation

Years ended December 31, (in thousands)

2004

2003

2002

 

 

 

 

ALLOWANCE FOR DOUBTFUL ACCOUNTS

Balance at beginning of year

$ 9,100

$ 8,200

$ 11,100

 

 

 

 

Additions:

 

 

 

Charged to income

4,819

5,668

5,410

Recoveries and adjustments

(403)

(601)

(565)

 

 

 

 

Net additions

4,416

5,067

4,845

 

 

 

 

Less uncollectible accounts written off

(3,916)

(4,167)

(7,745)

 

 

 

 

Balance at end of year

$ 9,600

$ 9,100

$ 8,200

 

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

None

ITEM 9A. CONTROLS AND PROCEDURES

a. Conclusion Regarding Disclosure Controls and Procedures

Our chief executive officer and chief financial officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

b. Management's Report On Internal Control Over Financial Reporting

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

 

 

i

 

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Energen Corporation;

 

 

ii

 

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Energen Corporation are being made only in accordance with authorization of management and directors of Energen Corporation; and

  

 

iii

 

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

 

Internal control over financial reporting includes the controls themselves, monitoring (including internal auditing practices) and actions taken to correct deficiencies as identified.

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

Management assessed the effectiveness of Energen Corporation's internal control over financial reporting as of December 31, 2004. Management based this assessment on criteria for effective internal control over financial reporting described in "Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management's assessment included an evaluation of the design of Energen Corporation's internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management determined that, as of December 31, 2004, Energen Corporation maintained effective internal control over financial reporting.

PricewaterhouseCoopers LLP, our independent registered public accounting firm, that audited the consolidated financial statements of Energen Corporation included in this report, have issued an attestation report on management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2004 as stated in the report which appears herein.

 

March 14, 2005

c. Changes in Internal Control Over Financial Reporting

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

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2005. The definitive proxy statement will be filed on or about March 24, 2005.

ITEM 11. EXECUTIVE COMPENSATION

The information regarding executive compensation is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2005.

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

a. Security Ownership of Certain Beneficial Owners

The information regarding the security ownership of the beneficial owners of more than five percent of Energen's common stock is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2005.

b. Security Ownership of Management

The information regarding the security ownership of management is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2005.

c. Securities Authorized for Issuance Under Equity Compensation Plans

The information regarding securities authorized for issuance under equity compensation plans is included in Part 2 under Item 5.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information regarding certain relationships and related transactions is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2005.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 27, 2005.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

a. Documents Filed as Part of This Report

(1) Financial Statements

The consolidated financial statements of Energen and the financial statements of Alagasco are included in Item 8 of this Form 10-K

(2) Financial Statement Schedules

The financial statement schedules are included in Item 8 of this Form 10-K

(3) Exhibits

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

 

Energen Corporation

Alabama Gas Corporation

INDEX TO EXHIBITS

Item 14(a)(3)

Exhibit

Number Description

*3(a) Restated Certificate of Incorporation of Energen Corporation (composite, as amended February 2, 1998) which was filed as Exhibit 3(a) to Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)

*3(b) Articles of Amendment to Restated Certificate of Incorporation of Energen, designating Series 1998 Junior Participating Preferred Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energen's Post Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-00395)

*3(c) Bylaws of Energen Corporation (as amended through October 30, 2002) which was filed as Exhibit 4(c) to Energen's Registration Statement on Form S-8 (Registration No. 33-46641)

*3(d) Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1995 (file No. 1-7810)

*3(e) Bylaws of Alabama Gas Corporation (as amended through October 30, 2002) which was filed as Exhibit 3(e) to Energen's Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 1-7810)

*4(a) Rights Agreement, dated as of July 27, 1998, between Energen Corporation and First Chicago Trust Company of New York, Rights Agent, which was filed as Exhibit 1 to Energen's Registration Statement on Form 8-A, dated July 10, 1998 (File No. 1-7810)

*4(b) Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September 1, 1996 (the "Energen 1996 Indenture"), and which was filed as Exhibit 4(i) to the Registrant's Registration Statement on Form S-3 (Registration No. 333-11239)

*4(b)(i) Officers' Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810)

*4(b)(ii) Officers' Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810)

*4(b)(iii) Amended and Restated Officers' Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filed as Exhibit 4(d)(iii) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810)

*4(b)(iv) Officers' Certificate, dated October 3, 2003, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 5% Notes due October 1, 2013, which was filed as Exhibit 4 to Energen's Current Report on Form 8-K, dated October 3, 2003 (File No. 1-7810)

*4(b)(v) Officers' Certificate, dated November 19, 2004, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Floating Rate Senior Notes due November 15, 2004, which was filed as Exhibit 4.2 to Energen's Current Report on Form 8-K, dated November 19, 2004 (File No. 1-7810)

*4(d) Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia, National Association, Trustee, ("Alagasco 1993 Indenture"), which was filed as Exhibit 4(k) to Alabama Gas' Registration Statement on Form S-3 (Registration No. 33-70466)

*4(d)(i) Officers' Certificate, dated August 30, 2001, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 6.25 percent Notes due September 1, 2016, which was filed as Exhibit 4.01 to Alabama Gas' Current Report on Form 8-K filed September 27, 2001

*4(d)(ii) Officers' Certificate, dated August 30, 2001, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 6.75 percent Notes due September 1, 2031, which was filed as Exhibit 4.02 to Alabama Gas' Current Report on Form 8-K filed September 27, 2001

*4(d)(iii) Officers' Certificate, dated January 14, 2005, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 5.70 percent Notes due January 15, 2035, which was filed as Exhibit 4.3 to Alabama Gas' Current Report on Form 8-K filed January 14, 2005

*4(d)(iv) Officers' Certificate, dated January 14, 2005, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 5.20 percent Notes due January 15, 2020, which was filed as Exhibit 4.4 to Alabama Gas' Current Report on Form 8-K filed January 14, 2005

*10(a) Form of Service Agreement Under Rate Schedule CSS (No. S10710), between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(a) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810)

*10(b) Form of Service Agreement Under Rate Schedule FT-NN (No. 866941), between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810)

*10(c) Form of Service Agreement Under Rate Schedule FT (No. 866940) between Southern Natural Gas Company and Alabama Gas Corporation which was file as Exhibit 10(d) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810)

*10(d) Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(b) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810)

*10(e) Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alabama Gas Corporation, dated August 1, 1991 which was filed as Exhibit 3(e) to Energen's Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 1-7810)

*10(f) Form of Executive Retirement Supplement Agreement between Energen Corporation and it's executive officers (as revised October 2000) which was filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810)

*10(g) Form of Severance Compensation Agreement between Energen Corporation and it's executive officers which was filed as Exhibit 10(d) to Energen's Annual Report on Form 10-K for the year ended September 30, 1999 (File No. 1-7810)

*10(h) Energen Corporation 1988 Stock Option Plan (as amended November 25, 1997) which was filed as Exhibit 10(e) to Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)

*10(i) Energen Corporation 1992 Long-Range Performance Share Plan (as amended effective October 1, 1999) which was filed as Exhibit 10(f) to Energen's Annual Report on Form 10-K for the year ended September 30, 1999 (File No. 1-7810)

*10(j) Energen Corporation 1997 Stock Incentive Plan (as amended effective October 1, 2001) which was filed as Exhibit 10(h) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810)

*10(k) Form of Stock Option Agreement under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(a) to Energen's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (File No. 1-7810)

*10(l) Form of Restricted Stock Agreement under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(b) to Energen's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (File No. 1-7810)

*10(m) Form of Performance Share Award under the Energen Corporation 1997 Stock Incentive Plan which was filed as Exhibit 10(c) to Energen's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (File No. 1-7810)

10(n) Energen Corporation 1997 Deferred Compensation Plan (as amended effective January 1, 2001)

10(o) Amendment No. 1 to the Energen Corporation 1997 Deferred Compensation Plan (as amended January 1, 2001)

*10(p) Energen Corporation 1992 Directors Stock Plan (as amended April 25, 1997) which was filed as Exhibit 10(i) to Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810)

*10(q) Energen Corporation Annual Incentive Compensation Plan, as amended effective October 1, 2001 which was filed as Exhibit 10(k) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810)

*10(r) Energen Corporation Officer Split Dollar Life Insurance Plan, effective October 1, 1999 which was filed as Exhibit 10(l) to Energen's Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810)

*10(s) Form of Split Dollar Life Insurance Plan Agreement under Energen Corporation Officer Split Dollar Life Insurance Plan which was filed as Exhibit 10(m) to Energen's Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810)

*10(t) Officer Split Dollar Tax Matters Agreement which was filed as Exhibit 10(n) to Energen's Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810)

10(u) Energen Board of Directors resolution adopted as of May 14, 2004, terminating the Energen Corporation Officer Split Dollar Life Insurance Plan

21 Subsidiaries of Energen Corporation

23(a) Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)

23(b) Consent of Registered Public Accounting Firm (PricewaterhouseCoopers LLP)

23(c) Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company)

23(d) Consent of Independent Oil and Gas Reservoir Engineers (Miller and Lents, Ltd.)

23(e) Consent of Independent Oil and Gas Reservoir Engineers (T. Scott Hickman and Associates, Inc.)

31(a) Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a)

31(b) Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a)

32 Certification pursuant to Section 1350

 

*Incorporated by reference

SIGNATURE

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

 

ENERGEN CORPORATION

(Registrant)

 

ALABAMA GAS CORPORATION

(Registrant)

 

March 14, 2005

 

By   /s/ Wm. Michael Warren, Jr.         

 

 

Wm. Michael Warren, Jr.

 

 

Chairman, President and Chief Executive Officer of Energen, Chairman and Chief Executive Officer of Alabama Gas Corporation

 

 

 

 

 

 

 

 

 

 

 

 

SIGNATURES

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

 

March 14, 2005

 

By   /s/ Wm. Michael Warren, Jr.         

 

 

Wm. Michael Warren, Jr.

 

 

Chairman, President and Chief Executive Officer of

 

 

Energen, Chairman and Chief Executive Officer of

 

 

Alabama Gas Corporation

 

 

 

 

 

 

March 14, 2005

 

By   /s/ Geoffrey C. Ketcham                        

 

 

Geoffrey C. Ketcham

 

 

Executive Vice President, Chief Financial Officer and Treasurer of Energen and Alabama Gas Corporation

 

 

 

 

 

 

 

 

 

March 14, 2005

 

By   /s/ Grace B. Carr                         

 

 

Grace B. Carr

 

 

Vice President and Controller of Energen

 

 

 

 

 

 

March 14, 2005

 

By   /s/ Paula H. Rushing                 

 

 

Paula H. Rushing

 

 

Vice President-Finance of Alabama Gas

 

 

Corporation

 

 

 

 

 

 

March 14, 2005

 

By   /s/ Julian W. Banton                       

 

 

Julian W. Banton

 

 

Director

 

 

 

 

 

 

March 14, 2005

 

By   /s/ James S. M. French                    

 

 

James S. M. French

 

 

Director

 

 

 

 

 

 

March 14, 2005

 

By   /s/ T. Michael Goodrich                    

 

 

T. Michael Goodrich

 

 

Director

 

 

 

 

 

 

March 14, 2005

 

By   /s/ Judy M. Merritt                     

 

 

Judy M. Merritt

 

 

Director

 

 

 

 

 

 

March 14, 2005

 

By   /s/ David W. Wilson                   

 

 

David W. Wilson

 

 

Director

 

Exhibit 23(a)

 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-86056 and File No. 333-119926) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 33-26111, File No. 33-45107 and File No. 333-84170) of Energen Corporation of our report dated March 14, 2005 relating to the consolidated financial statements, financial statement schedule, management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

 

 

PricewaterhouseCoopers LLP

Birmingham, Alabama

March 15, 2005

 

 

 

 

Exhibit 23(b)

 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-121077) of Alabama Gas Corporation of our report dated March 14, 2005 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

 

 

PricewaterhouseCoopers LLP

Birmingham, Alabama

March 15, 2005

 

  

Exhibit 23(c)

 

CONSENT

We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2004, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-86056 and File No. 333-119926) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 33-26111, File No. 33-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2004, which appears in this Form 10-K.

 

Ryder Scott Company, L.P.

Houston, Texas

March 14, 2005

  

 

Exhibit 23(d)

 

CONSENT

We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2004, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-86056 and File No. 333-119926) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 33-26111, File No. 33-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2004, which appears in this Form 10-K.

 

Miller and Lents, Ltd.

Houston, Texas

March 14, 2005

 

  

Exhibit 23(e)

 

CONSENT

We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2004, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-86056 and File No. 333-119926) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, File No. 33-48505, File No. 33-26111, File No. 33-45107 and File No. 333-84170) of Energen Corporation to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2004, which appears in this Form 10-K.

 

T. Scott Hickman & Associates, Inc.

Midland, Texas

March 4, 2005