-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, NtLcOFzDvZnhVtWUBErtYe+XuLIsieW3GxGkel07oTKNWn0iruBxB9AbCZ3Mt4up uO4MvuWqUiYZlbee7q+zCQ== 0000950144-04-000685.txt : 20040202 0000950144-04-000685.hdr.sgml : 20040202 20040202115322 ACCESSION NUMBER: 0000950144-04-000685 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20040202 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ALABAMA GAS CORP CENTRAL INDEX KEY: 0000003146 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 630022000 STATE OF INCORPORATION: AL FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 033-70466 FILM NUMBER: 04558186 BUSINESS ADDRESS: STREET 1: 2101 SIXTH AVE NORTH CITY: BIRMINGHAM STATE: AL ZIP: 35203 BUSINESS PHONE: 2053262742 MAIL ADDRESS: STREET 1: 2101 SIXTH AVE NORTH CITY: BIRMINGHAM STATE: AL ZIP: 35203 10-K 1 g79764age10vk.txt ENERGEN CORPORATION 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, 2002 [] 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. ( ) Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2002:
Energen Corporation $931,042,350
Indicate number of shares outstanding of each of the registrant's classes of common stock as of March 5, 2003:
Energen Corporation 34,868,363 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 20, 2003 (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) which cannot be extracted until a recompletion or pay-add occurs. CASH FLOW HEDGE The designation of a derivative instrument to reduce the 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 commodity. The producer only 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 statigraphic horizon known to be productive. EXPLORATORY WELL A well drilled to a previously untested geologic structure to determine the presence of oil or gas. 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 Natural gas that is liquified by reducing the (LNG) 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 detectable 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 The portion of proved reserves which can be expected RESERVES (PUD) 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- Ratio expressing years of supply determined by PRODUCTION RATIO 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 company pipelines on a contract basis for others. THROUGHPUT Total volumes of natural gas sold or transported by the gas utility. WORKING INTEREST The ownership interest in the oil and gas properties which 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 2002 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS
PAGE ---- PART I Item 1. Business..............................................................................3 Item 2. Properties............................................................................9 Item 3. Legal Proceedings.....................................................................9 Item 4. Submission of Matters to a Vote of Security Holders...................................9 PART II Item 5. Market for Registrant's Common Stock and Related Stockholder Matters.................11 Item 6. Selected Financial Data..............................................................12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...........................................................................14 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.................................................................73 PART III Item 10. Directors and Executive Officers of the Registrants..................................74 Item 11. Executive Compensation...............................................................74 Item 12. Security Ownership of Certain Beneficial Owners and Management.......................74 Item 13. Certain Relationships and Related Transactions.......................................74 PART IV Item 14. Controls and Procedures..............................................................75 Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.....................75 Signatures .....................................................................................79 Certifications .....................................................................................81
2 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: 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 Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. The Company undertakes no 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, future business decisions, 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 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 risk, fluctuations in future oil and gas prices could materially affect the Company's financial position and results of operation; 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. PART I ITEM 1. BUSINESS GENERAL Energen Corporation is a Birmingham-based 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 major 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 3 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 and current reports on Form 8-K, and any amendments to these reports. These reports are provided as soon as reasonably practicable after such reports are electronically filed with or furnished to the Securities and Exchange Commission. FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS The information required by this item is provided in Note 20, Industry Segment Information, in the Notes to Financial Statements. NARRATIVE DESCRIPTION OF BUSINESS - - OIL AND GAS OPERATIONS GENERAL: Energen's oil and gas operations focus on increasing production and adding proved reserves through the 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 production and all oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior Basin in Alabama for its partners and third parties. These services include overall project management and day-to-day decision-making relative to project operations. At the end of 2002, Energen Resources' inventory of proved oil and gas reserves totaled 1,262.9 billion cubic feet equivalent (Bcfe). Substantially all of the company's approximately 1.3 trillion cubic feet equivalent of reserves are located in the San Juan Basin in New Mexico, the Black Warrior Basin in Alabama, the Permian Basin in west Texas, and the north Louisiana/east Texas region. Approximately 82 percent of Energen Resources' year-end reserves are proved developed reserves. Energen Resources reserves are long-lived, with a year-end reserves-to-production ratio of 16. Natural gas represents approximately 64 percent of Energen Resources' proved reserves, with oil representing approximately 24 percent and natural gas liquids comprising the balance. GROWTH STRATEGY: Energen has operated for more than seven years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $715 million in property acquisitions, $435 million in related development, and $90 million in exploration and associated development. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2007, is currently expected to approximate $835 million. 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 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 development 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 4 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 intent to develop certain opportunities. Since the end of fiscal year 1999, the Company's development efforts have added approximately 298 Bcfe of proved reserves from the drilling of approximately 540 gross development wells and 408 well recompletions and pay-adds. In 2002, Energen Resources' successful development wells and other activities added approximately 162 Bcfe of proved reserves. The company drilled 232 gross development wells, performed some 95 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources' production from continuing operations totaled 77.4 Bcfe in 2002 and is estimated to total 85 Bcfe in 2003, including 82.4 Bcfe of estimated production from proved reserves owned at December 31, 2002. Most of Energen Resources' coalbed methane production generated nonconventional fuels tax credits through December 31, 2002. In 2002, Energen Resources' nonconventional fuels tax credits totaled $14.2 million. Nonconventional fuels tax credits are no longer generated due to tax law changes effective December 31, 2002. To mitigate the effects on corporate earnings in 2003, Energen Resources has replaced a portion of the tax credit benefit with long-term, revenue-generating property acquisitions and their related development activities and has increased the number of available drilling locations through unit downspacing in the Black Warrior Basin. RISK MANAGEMENT: Energen Resources attempts to lower the risk 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 in its evaluation models the then-current oil and gas futures prices, the prevailing swap curve and, for the longer-term, its own pricing assumptions. After a purchase, Energen Resources may use futures, swaps and/or fixed-price contracts to hedge commodity prices on flowing production for up to 36 months to help protect targeted returns from price volatility. On an on-going basis, Energen Resources may hedge up to 80 percent of its annual production in any given year depending on its pricing outlook. The Company adopted Statement of Financial Accounting Standards (SFAS) No. 133 (subsequently amended by SFAS Nos. 137 and 138), "Accounting for Derivative Instruments and Hedging Activities," 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 when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in earnings in the period of change. The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding New York Mercantile Exchange (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. See the Forward-Looking Statement and Risk in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion with respect to price and other risk. 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 that potential environmental liabilities are minimal. Also, to the extent that 5 Energen Resources has operating agreements with various joint venture partners, environmental costs would be shared proportionately. OTHER: 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. - - NATURAL GAS DISTRIBUTION GENERAL: Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate marketers and suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from producers, marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers' facilities. Alagasco's service territory is located in central and parts of north Alabama and includes approximately 188 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.3 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2002, Alagasco served an average of 425,630 residential customers and 35,601 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 9,723 miles of main and more than 11,395 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, in 1983, established the Rate Stabilization and Equalization (RSE) rate-setting process. 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 as extended, 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 performs this real-time temperature adjustment calculation monthly, and the adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider that permits the pass-through to customers of changes in the cost of gas supply. 6 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 and has firm transportation contracts with two major interstate pipeline systems - Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe Line Corporation (Transco). On Southern's system, Alagasco has 251,679 thousand cubic feet (Mcfd) of No-Notice Firm Transportation service through October 31, 2008, and 134,332 Mcfd of Firm Transporation service, of which 40,000 Mcfd expires April 30, 2005, 1,959 Mcfd expires October 31, 2005 and the balance expires October 31, 2008. The Transco Firm Transportation contract, which expires October 31, 2005, provides for up to 100,000 Mcfd. As a result, Alagasco has a peak day firm interstate pipeline transportation capacity of 486,011 Mcfd. Alagasco has 12,464,074 Mcf of storage capacity on Southern's system, with a maximum withdrawal rate of 251,679 Mcfd from storage and a maximum injection rate of 95,878 Mcfd to storage. Alagasco also operates two liquified natural gas (LNG) facilities used to meet peak demand. Alagasco purchases gas from various gas producers and marketers, including affiliates of Southern, and from certain intrastate producers and marketers. Alagasco has contracts in place to purchase up to 233,230 Mcfd of firm supply, of which 234,332 Mcfd is supported by firm transportation on the Transco and Southern systems and approximately 21,450 Mcfd is purchased at the city gate under intrastate firm supply contracts. These firm supply volumes along with Alagasco's maximum withdrawal from storage of 251,679 Mcfd and LNG peak-shaving capacity of 200,000 Mcfd, give Alagasco a peak day firm supply of 684,909 Mcfd. Alagasco also utilizes the Southern pipeline systems to access spot market gas in order to supplement its firm system supply and serve its industrial and large commercial transportation customers. Deliveries of sales and transportation gas totaled 97,840 million cubic feet in 2002. 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 customers' gas load in the deregulated marketplace. Rate flexibility remains critical as the utility faces competition for the large customer 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 small commercial and industrial customers. In 2002, approximately 300 of Alagasco's transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled approximately $9.1 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 7 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 2002 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 approximately 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 2002, 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 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 2002, Alagasco's average number of customers declined slightly due to the previous year's high gas costs and industrial load loss resulting from an economic slowdown. The utility penetrated 86 percent of the new single-family housing market in its service area and 18 percent of the new multi-family housing market. For 2003, 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. A vehicle for supplementing Alagasco's normal growth continues to be Alagasco's municipal acquisition program. Since 1985, Alagasco has acquired 23 municipally owned systems adding more than 43,000 customers through initial system purchases and subsequent customer additions. Approximately 75 municipal systems remain in Alabama. Alagasco continues to pursue the purchase of municipal gas systems, and company management believes that such acquisitions could offer future growth opportunities. 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 eight former manufactured gas plant sites and five manufactured gas distribution sites. It still owns four of the plant sites and one of the distribution sites. 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 of any associated costs will not materially affect the Company's results of its operations or financial condition. OTHER: 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 1,533 employees; Alagasco employs 1,259; Energen Resources employs 261; and Energen's other subsidiaries employ 13. The Company believes that its relations with employees are good. 8 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 Houston and 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, reserves and development is summarized in the table below and included in Note 19, Oil and Gas Operations (unaudited), in the Notes to Financial Statements which is included in this Form 10-K.
YEAR ENDED DECEMBER 31, 2002 DECEMBER 31, 2002 ----------------- ----------------- Production Volumes Reserves (MMcfe) (MMcfe) ----------------- ----------------- San Juan Basin 27,133 548,744 Permian Basin 23,878 357,455 Black Warrior Basin 13,494 257,662 North Louisiana/East Texas 11,376 82,086 Other 2,092 16,981 ------ --------- Total 77,973 1,262,928 ====== =========
The properties of Alagasco consist primarily of its gas distribution system, which includes more than 9,723 miles of main, more than 11,395 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, seven division offices, four payment centers, five 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 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. 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 2002. 9 EXECUTIVE OFFICERS OF THE REGISTRANTS ENERGEN CORPORATION
Name Age Position (1) - ---- --- ------------ Wm. Michael Warren, Jr. 55 Chairman of the Board President and Chief Executive Officer (2) Geoffrey C. Ketcham 52 Executive Vice President, Chief Financial Officer and Treasurer (3) James T. McManus 44 President and Chief Operating Officer of Energen Resources (4) Dudley C. Reynolds 50 President and Chief Operating Officer of Alagasco (5) Grace B. Carr 47 Vice President and Controller (6) J. David Woodruff, Jr. 46 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 as 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 as 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. 10 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
Quarter ended (in dollars) HIGH LOW CLOSE DIVIDENDS PAID - -------------------------- ---- --- ----- -------------- December 31, 1999 21.25 15.75 18.06 .165 March 31, 2000 18.94 14.69 15.94 .165 June 30, 2000 23.69 16.00 21.81 .165 September 30, 2000 30.38 21.00 29.75 .170 ------- ------ ------ ----- December 31, 2000 33.56 26.06 32.19 .170 March 31, 2001 35.30 27.50 35.30 .170 June 30, 2001 40.25 26.75 27.60 .170 September 30, 2001 28.21 21.50 22.50 .175 ------- ------ ------ ----- December 31, 2001 25.20 21.50 24.65 .175 ------- ------ ------ ----- 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 ------- ------ ------ -----
Energen's common stock is listed on the New York Stock Exchange under the symbol EGN. On February 14, 2003, there were approximately 7,930 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:
Number of Securities Remaining Number of Securities to Weighted Available for Future Issuance be Issued Upon Exercise Average Under Equity Compensation Plans Plan Category of Outstanding Options Exercise Price ------------- ---------------------- -------------- ------------------------------- Equity compensation plans approved by security holders 621,007 $20.38 2,326,897 Equity compensation plans not approved by security holders -- -- -- ------- ------ --------- Total 621,007 $20.38 2,326,897 ======= ====== =========
11 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
Three Months YEAR ENDED Ended Year Ended Year Ended Year Ended Year Ended Year Ended (dollars in thousands, DECEMBER 31, December 31, September 30, September 30, September 30, September 30, September 30, except per share amounts) 2002 2001* 2001 2000 1999 1998 1997 ------------ ------------- ------------ ------------- ------------- ------------- ------------- INCOME STATEMENT Operating revenues $ 677,175 $ 146,164 $ 777,374 $ 551,409 $ 492,942 $498,398 $446,684 Income from continuing operations before cumulative effect of change in accounting principle $ 70,586 $ 3,579 $ 66,087 $ 52,535 $ 41,453 $ 35,828 $ 28,736 Net income $ 68,639 $ 3,658 $ 67,896 $ 53,018 $ 41,410 $ 36,249 $ 28,997 Diluted earnings per average common share from continuing operations before cumulative effect of change in accounting principle $ 2.09 $ 0.12 $2.13 $ 1.73 $ 1.38 $ 1.22 $ 1.13 Diluted earnings per average common share $ 2.03 $ 0.12 $2.18 $ 1.75 $ 1.38 $ 1.23 $ 1.14 ---------- ----------- ---------- ---------- ---------- -------- -------- BALANCE SHEET Capitalization at year-end: Common shareholders' equity $ 582,810 $ 474,205 $ 480,767 $ 400,860 $ 361,504 $329,249 $301,143 Long-term debt 512,954 544,133 544,110 353,932 371,824 372,782 279,602 ---------- ----------- ---------- ---------- ---------- -------- -------- Total capitalization $1,095,764 $1,018,338 $1,024,877 $ 754,792 $ 733,328 $702,031 $580,745 ---------- ----------- ---------- ---------- ---------- -------- -------- Total assets $1,530,891 $1,240,356 $1,223,879 $1,203,041 $1,184,895 $993,455 $919,797 ---------- ----------- ---------- ---------- ---------- -------- -------- Property, plant and equipment, net $1,256,803 $1,005,679 $ 998,334 $ 907,829 $ 861,107 $756,344 $667,003 ========== ========== ========== ========== ========== ======== ======== COMMON STOCK DATA Annual dividend rate at period-end $ 0.72 $ 0.70 $ 0.70 $ 0.68 $ 0.66 $ 0.64 $ 0.62 Cash dividends paid per common share $ 0.71 $ 0.175 $ 0.685 $ 0.665 $ 0.645 $ 0.625 $ 0.605 Book value per common share $ 16.77 $ 15.18 $ 15.45 $ 13.21 $ 12.09 $ 11.23 $ 10.46 Market-to-book ratio at period-end (%) 174 162 145 225 167 169 170 Yield at period-end (%) 2.5 2.8 3.1 2.3 3.3 3.4 3.5 Return on average common equity excluding other comprehensive income(%)** 12.4 12.6 15.3 13.7 11.7 11.1 11.9 Return on average common equity (%) 12.4 13.0 15.8 13.7 11.7 11.1 11.9 Price-to-earnings (diluted) ratio at period-end 14.3 -- 10.3 17.0 14.7 15.4 15.6 Shares outstanding at period-end (000) 34,745 31,249 31,125 30,351 29,904 29,327 28,796 Price Range: High $ 29.99 $ 25.20 $ 40.25 $ 30.38 $ 20.38 $ 22.50 $ 18.88 Low $ 21.65 $ 21.50 $ 21.50 $ 14.69 $ 13.13 $ 15.13 $ 11.88 Close $ 29.10 $ 24.65 $ 22.50 $ 29.75 $ 20.25 $ 19.00 $ 17.78
Note: All information has been adjusted to reflect the 2-for-1 stock split effective March 2, 1998 *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. **The comparable generally accepted accounting principle measure is return on average common equity. 12 SELECTED BUSINESS SEGMENT DATA Energen Corporation
Three Months YEAR ENDED Ended Year Ended DECEMBER 31, December 31, September 30, (dollars in thousands) 2002 2001* 2001 ------------ ------------ ------------- OIL AND GAS OPERATIONS Operating revenues from continuing operations Natural gas $150,899 $35,324 $141,505 Oil 75,426 12,375 48,016 Natural gas liquids 22,849 4,533 26,011 Other 3,570 (2,746) 7,980 -------- ------- -------- Total $252,744 $49,486 $223,512 -------- ------- -------- Production volumes from continuing operations Natural gas (MMcf) 47,776 11,886 45,847 Oil (MBbl) 3,139 512 2,019 Natural gas liquids (MBbl) 1,792 450 1,477 -------- ------- -------- Production volumes from continuing operations (MMcfe) 77,360 17,656 66,823 -------- ------- -------- Total production volumes (MMcfe) 77,973 18,022 68,478 -------- ------- -------- Proved reserves Natural gas (MMcf) 803,748 714,395 627,051 Oil (MBbl) 49,833 19,128 20,878 Natural gas liquids (MBbl) 26,697 25,944 24,931 -------- ------- -------- Other data from continuing operations Depreciation and amortization $ 71,405 $16,351 $ 53,846 Capital expenditures $305,476 $25,052 $136,886 Operating income $ 78,416 $ 3,243 $ 72,425 -------- ------- -------- NATURAL GAS DISTRIBUTION Operating revenues Residential $277,088 $63,724 $367,109 Commercial and industrial-small 104,247 22,445 147,636 Transportation 38,395 9,765 33,972 Other 4,701 744 5,145 -------- ------- -------- Total $424,431 $96,678 $553,862 -------- ------- -------- Gas delivery volumes (MMcf) Residential 26,358 5,128 31,064 Commercial and industrial-small 11,838 2,193 14,054 Transportation 59,644 12,973 53,989 -------- ------- -------- Total 97,840 20,294 99,107 -------- ------- -------- Average number of customers Residential 425,630 422,461 428,663 Commercial, industrial and transportation 35,601 35,161 35,882 -------- ------- -------- Total 461,231 457,622 464,545 -------- ------- -------- Other data Depreciation and amortization $ 33,682 $ 8,151 $ 30,933 Capital expenditures $ 65,815 $12,873 $ 56,090 Operating income $ 59,370 $ 8,034 $ 50,288 -------- ------- -------- Year Ended Year Ended Year Ended Year Ended September 30, September 30, September 30, September 30, (dollars in thousands) 2000 1999 1998 1997 ------------- ------------- ------------- ------------- OIL AND GAS OPERATIONS Operating revenues from continuing operations Natural gas $118,271 $116,555 $93,958 $59,474 Oil 39,220 35,207 20,472 13,199 Natural gas liquids 22,662 7,207 6,977 5,762 Other 5,095 8,419 7,051 5,265 -------- -------- -------- -------- Total $185,248 $167,388 $128,458 $83,700 -------- -------- -------- -------- Production volumes from continuing operations Natural gas (MMcf) 47,441 52,754 42,432 28,995 Oil (MBbl) 2,140 2,937 1,378 734 Natural gas liquids (MBbl) 1,411 757 817 502 -------- -------- -------- -------- Production volumes from continuing operations (MMcfe) 68,756 74,919 55,599 36,412 -------- -------- -------- -------- Total production volumes (MMcfe) 70,482 77,159 57,353 36,980 -------- -------- -------- -------- Proved reserves Natural gas (MMcf) 777,456 740,001 542,039 544,283 Oil (MBbl) 24,518 24,719 19,845 9,128 Natural gas liquids (MBbl) 26,007 21,937 17,292 12,378 -------- -------- -------- -------- Other data from continuing operations Depreciation and amortization $ 56,226 $ 59,322 $ 54,192 $ 35,729 Capital expenditures $ 67,090 $198,577 $120,991 $239,718 Operating income $ 47,568 $ 31,089 $ 20,299 $ 14,295 -------- -------- -------- -------- NATURAL GAS DISTRIBUTION Operating revenues Residential $233,839 $209,263 $241,964 $237,022 Commercial and industrial-small 88,521 77,254 89,361 87,477 Transportation 35,312 34,541 35,246 33,080 Other 8,489 4,496 3,369 5,405 -------- -------- -------- -------- Total $366,161 $325,554 $369,940 $362,984 -------- -------- -------- -------- Gas delivery volumes (MMcf) Residential 26,069 24,751 31,079 28,357 Commercial and industrial-small 12,092 11,662 13,705 12,554 Transportation 70,534 66,356 70,563 65,622 -------- -------- -------- -------- Total 108,695 102,769 115,347 106,533 -------- -------- -------- -------- Average number of customers Residential 429,368 425,937 423,602 422,878 Commercial, industrial and transportation 35,526 35,111 34,782 34,485 -------- -------- -------- -------- Total 464,894 461,048 458,384 457,363 -------- -------- -------- -------- Other data Depreciation and amortization $28,708 $26,730 $25,153 $23,486 Capital expenditures $67,073 $46,029 $54,168 $43,277 Operating income $49,063 $46,565 $41,663 $38,792 -------- -------- -------- --------
13 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 judgements 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. Estimates of physical quantities of oil and gas reserves are determined by Company engineers and, in some cases, by third-party experts. 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. The Company's production of undeveloped reserves require 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 will 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 expenses or due to an immediate writedown of the property's book value if an impairment is warranted. The table below reflects the estimated effect on depreciation and depletion expense for 2003 of changes in oil and gas reserve quantities from the reported amounts at December 31, 2002.
Percentage Change in Oil & Gas Reserves From Reported Reserves as of December 31, 2002 (dollars in thousands) +10% +5% -5% -10% ------- ------- ------- ------- Estimated change in depreciation expense for the year ended December 31, 2003, net of tax $(4,300) $(2,100) $ 2,400 $ 5,200 ------- ------- ------- -------
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 from the properties. If a material event occurs, Energen Resources makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, the Company will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flow. 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 estimate and can have a positive or negative 14 impact on the Company's need for impairment or of 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. NATURAL GAS DISTRIBUTION REGULATED OPERATIONS: Alagasco applies SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," to its regulated operations. This standard requires a cost to be capitalized as a regulatory asset that otherwise would be charged to expense if it is probable that the cost is recoverable in the future through regulated rates. Likewise, if current recovery is provided for a cost that will be incurred in the future, SFAS No. 71 requires the cost to be recognized as a regulatory liability. The Company anticipates SFAS No. 71 will continue as the applicable accounting standard for its regulated operations. Alagasco's rate setting methodology, Rate Stabilization and Equalization, has been in effect since 1983. CONSOLIDATED EMPLOYEE BENEFIT PLANS: Determining the Company's obligations to employees under its defined benefit pension plan requires the use of estimates. The calculation of the liability related to the Company's defined benefit pension plan requires assumptions regarding the appropriate weighted average discount rate, estimated 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 plan. The discount rate for pension cost purposes is the rate at which pension obligations could be effectively settled. At December 31, 2002 the discount rate used for actuarial purposes was 6.75 percent. A hypothetical basis point change in the discount rate would impact total pension expense by approximately $560,000. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. At December 31, 2002, the return on assets used for actuarial purposes was 9 percent. A hypothetical 25 basis point change in the return on assets would impact total pension expense by approximately $245,000. CHANGE IN YEAR END 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. Alagasco will continue on a September 30 fiscal year for rate-setting purposes (rate year) and will report on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. RESULTS OF OPERATIONS CONSOLIDATED NET INCOME Energen Corporation's net income for the year ended December 31, 2002 totaled $68.6 million, or $2.03 per diluted share compared to fiscal year ended September 30, 2001 net income of $67.9 million, or $2.18 per diluted share. This 7 percent decrease in earnings per diluted share (EPS) reflects an increase in the number of shares outstanding related to the acquisition of oil and gas properties in the Permian Basin in April 2002. Energen Resources Corporation, Energen's oil and gas subsidiary, had a slight decrease in earnings for the 12 months ended December 31, 2002, as compared with the 12 months ended September 30, 2001. Alabama Gas Corporation (Alagasco), Energen's utility subsidiary, generated a 6 percent increase in net income in the same period comparisons. For the 12 months ended September 30, 2000, Energen reported earnings of $53 million, or $1.75 per diluted share. 2002 VS 2001: For the year ended December 31, 2002, Energen Resources' net income totaled $41.2 million as compared with $42.6 million for the 12 months ended September 30, 2001. Net income in the current year included a non-cash benefit of $5.7 million after-tax ($0.17 per diluted share) associated with its previous hedge position with Enron North America Corp. (Enron) and a one-time charge of $2.2 million after-tax ($0.07 per diluted share), reflecting the cumulative effect on prior years of the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." Energen Resources' income from continuing operations in 2002 totaled $43.2 million as compared with $40.8 million in fiscal 2001, primarily due to a 15.8 percent increase in production volumes related to an acquisition of oil properties in the Permian Basin in April 2002. The primary negative influences on income from 15 operations were increased lease operating expense and increased depreciation, depletion and amortization (DD&A) expense. Alagasco's earnings increased to $27.6 million in 2002 from $26 million in fiscal year 2001 as a result of the utility having increased earnings on a higher level of equity. Alagasco achieved a return on average equity (ROE) of 12.3 percent in both 2002 and 2001. 2001 VS 2000: Energen Resources' net income in fiscal 2001 rose 55.2 percent to $42.6 million. Energen Resources' income from continuing operations in fiscal 2001 totaled $40.8 million as compared with $26.9 million in fiscal 2000, primarily due to a 23.3 percent increase in realized sales prices for natural gas, oil and natural gas liquids production. The significantly higher realized commodity prices more than compensated for the negative impact of increased lease operating expense and a 1.9 Bcfe production decrease. Earnings in fiscal year 2000 were negatively affected by a $2.2 million ($0.07 per diluted share) after-tax writedown under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," for certain oil and gas properties resulting from a downward reserve revision. Alagasco's earnings declined 1.2 percent from $26.3 million in fiscal 2000 to $26 million in fiscal year 2001. This slight decrease in income was primarily a result of increased bad debt expense from significantly colder weather and higher natural gas prices during the fiscal 2001 winter as well as industrial load loss resulting from an economic slowdown. Alagasco achieved a return on average equity (ROE) of 12.3 percent in 2001 as compared to 13.4 percent in 2000. THREE MONTHS ENDED DECEMBER 31, 2001 VS THREE MONTHS ENDED DECEMBER 31, 2000: Energen's net income totaled $3.7 million ($0.12 per diluted share) for the three months ended December 31, 2001, compared to net income of $13.7 million ($0.44 per diluted share) recorded in the same period of 2000. Energen Resources realized net income from continuing operations of $1.1 million in the December 31, 2001 transition quarter as compared with $9.3 million in the same quarter in the previous year largely due to a one-time non-cash write-off of $5.5 million after-tax ($0.17 per diluted share) associated with its hedge position with Enron. Also negatively impacting net income in the transition quarter were increased DD&A expense, a $1.7 million writedown on property held for sale and lower natural gas liquids prices. Energen's natural gas utility, Alagasco, reported net income of $2.7 million in the transition quarter as compared to $4 million in the same period in the previous year primarily due to increased bad debt expense as well as a decline in cycle and industrial gas usage. OPERATING INCOME Consolidated operating income in 2002, 2001 and 2000 totaled $136 million, $121 million and $95 million, respectively. This significant growth in operating income was 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 an increase in the level of equity upon which it has been able to earn a return. OIL AND GAS OPERATIONS: Revenues from oil and gas operations rose significantly in the current year largely as a result of increased production volumes related to the acquisition of oil properties in the Permian Basin. During 2002, production from continuing operations increased 15.8 percent to 77.4 Bcfe. Natural gas production increased 4.2 percent to 47.8 Bcf and oil volumes rose 55.5 percent to 3,139 MBbl. Production of natural gas liquids increased 21.3 percent to 1,792 MBbl. Including the non-cash benefit from the former Enron hedges, realized gas prices rose 2.3 percent to $3.16 per Mcf, while realized oil prices increased 1.1 percent to $24.03 per barrel. Natural gas liquids prices fell 27.6 percent to an average price of $12.75 per barrel. In fiscal 2001, revenues from oil and gas continuing operations increased largely as a result of significantly higher commodity prices as compared to the previous fiscal year. Realized gas prices rose 24.1 percent to $3.09 per Mcf, while realized oil prices increased 29.7 percent to $23.78 per barrel. Natural gas liquids prices increased 9.7 percent to an average price of $17.61 per barrel. During 2001, production from continuing operations declined slightly to 66.8 Bcfe as natural gas production decreased 3.4 percent to 45.8 Bcf and oil volumes declined 5.7 percent to 2,019 MBbl. Production of natural gas liquids increased 4.7 percent to 1,477 MBbl. This 1.9 Bcfe 16 decrease in production largely was due to normal production declines in Energen Resources' coalbed methane and south Louisiana properties. Drilling in the San Juan and Permian basins and in the north Louisiana/east Texas area served to replace aggregate production in these areas. 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 $4.8 million, $7.6 million and $4.3 million in 2002, 2001 and 2000, respectively.
DECEMBER 31, September 30, September 30, Years ended (in thousands, except sales price data) 2002 2001 2000 ------------ ------------- ------------- Revenues from continuing operations Natural gas production $ 150,899 $ 141,505 $ 118,271 Oil production 75,426 48,016 39,220 Natural gas liquids production 22,849 26,011 22,662 Operating fees 4,847 7,618 4,262 Other (1,277) 362 833 -------- -------- -------- Total revenues from continuing operations $ 252,744 $ 223,512 $ 185,248 -------- -------- -------- Production volumes from continuing operations Natural gas (MMcf) 47,776 45,847 47,441 Oil (MBbl) 3,139 2,019 2,140 Natural gas liquids (MBbl) 1,792 1,477 1,411 -------- -------- -------- Average sales price including effects of hedging Natural gas (per Mcf) $ 3.16 $ 3.09 $ 2.49 Oil (per barrel) $ 24.03 $ 23.78 $ 18.33 Natural gas liquids (per barrel) $ 12.75 $ 17.61 $ 16.06 -------- -------- -------- Average sales price excluding effects of hedging Natural gas (per Mcf) $ 2.96 $ 4.86 $ 3.06 Oil (per barrel) $ 24.75 $ 27.46 $ 26.45 Natural gas liquids (per barrel) $ 12.75 $ 17.61 $ 16.06 -------- -------- --------
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, which was adopted as of January 1, 2002. 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. In 2001, prior to the adoption of SFAS No. 144, Energen Resources recorded in operating revenues a net pre-tax gain from the sale of properties and adjustments to the fair value of properties held for sale of $0.8 million. Pre-tax gains from the sale of properties of $1.1 million were recorded in operating revenues in 2000. Operations and maintenance (O&M) expense increased $10.3 million and $9.9 million in 2002 and 2001, respectively. Lease operating expense in 2002 rose $7.6 million primarily due to the acquisition of oil and gas properties. In 2001, lease operating expense increased by $9.2 million largely due to significantly higher operational costs driven by market conditions resulting from increased commodity costs. In the current year, administrative expense increased $3.5 million primarily due to labor related costs and additional cost related to the property acquisition. Administrative expense increased $1.4 million in 2001. Exploration expense decreased $0.6 million in 2002 and $0.7 million in 2001, primarily due to reduced exploratory efforts. DD&A expense increased $17.6 million in 2002 largely due to increased production volumes and increased DD&A rates. In 2001, DD&A expense decreased $2.4 million primarily due to lower production volumes and additional pre-tax DD&A expense of $3.5 million recorded in 2000 to adjust the carrying amount of certain properties to their 17 fair value based on expected future discounted cash flows (see Note 12). The average depletion rate was $0.90 per Mcfe in 2002 as compared to $0.79 per Mcfe in the prior year. Energen Resources' expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes for 2002 of $18.9 million. Severance taxes in 2001 were $23.9 million as a result of increased commodity prices. In 2000, severance taxes were $17.3 million. OIL AND GAS OPERATIONS - TRANSITION PERIOD: Revenues from oil and gas continuing operations declined 9.8 percent to $49.5 million for the three months ended December 31, 2001, largely as a result of lower natural gas liquids prices. In the transition quarter, realized gas prices increased 8.4 percent to $2.97 per Mcf, while realized oil prices rose 7.8 percent to $24.19 per barrel. Natural gas liquids prices decreased 51.4 percent to an average price of $10.07 per barrel. Natural gas production in the transition quarter increased slightly to 11.9 Bcf, while oil volumes decreased slightly to 512 MBbl. Natural gas liquids production increased 13.9 percent to 450 MBbl. Natural gas comprised nearly 70 percent of Energen Resources' production in the transition quarter.
DECEMBER 31, December 31, Three months ended (in thousands, except sales price data) 2001 2000 ------------ ------------ Revenues from continuing operations Natural gas production $ 35,324 $32,316 Oil production 12,375 11,586 Natural gas liquids production 4,533 8,180 Operating fees 913 2,225 Other (3,659) 555 -------- ------- Total revenues from continuing operations $ 49,486 $54,862 -------- ------- Production volumes from continuing operations Natural gas (MMcf) 11,886 11,796 Oil (MBbl) 512 516 Natural gas liquids (MBbl) 450 395 -------- ------- Average sales price including effects of hedging Natural gas (per Mcf) $ 2.97 $ 2.74 Oil (per barrel) $ 24.19 $ 22.45 Natural gas liquids (per barrel) $ 10.07 $ 20.70 -------- ------- Average sales price excluding effects of hedging Natural gas (per Mcf) $ 2.35 $ 5.15 Oil (per barrel) $ 19.79 $ 30.65 Natural gas liquids (per barrel) $ 10.07 $ 20.70 -------- -------
Prior to the adoption of SFAS No. 144, Energen Resources recorded in operating revenues a pre-tax loss of $3.4 million for the current transition quarter from the sale of properties and adjustments to the fair value of properties held-for-sale as compared to a pre-tax gain of $0.8 million in the prior year quarter on the sale of various properties. O&M expense increased $8.6 million for the transition quarter ended December 31, 2001, largely due to the one-time non-cash writedown of $8.7 million pre-tax associated with Energen Resources' hedge position with Enron. Lease operating expenses increased by $0.4 million for the transition quarter while exploration expense remained relatively stable. Energen Resources' DD&A expense for the period rose $4.5 million primarily driven by the impact of market declines in commodity prices. The average depletion rate for the transition quarter was $0.91 as compared to $0.67 for the same period in the previous year. 18 Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $3.3 million lower in the transition quarter primarily as a result of the significantly decreased commodity market prices. 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 Company'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 real-time temperature adjustment mechanism that allows Alagasco to adjust customer bills monthly to reflect changes in usage due to departures from normal temperatures. The temperature adjustment applies to residential, small commercial and small industrial customers. Alagasco's natural gas and transportation sales revenues totaled $424.4 million, $553.9 million and $366.2 million in 2002, 2001 and 2000, respectively. Lower commodity gas costs and weather that was 13.1 percent warmer than in the prior year contributed to the decrease in sales revenue in the current year. Sales revenue in fiscal 2001 rose due to significantly higher commodity gas costs as well as weather that was 29.9 percent colder than in fiscal year 2000. In the current year, residential sales volumes decreased 15.1 percent primarily due to the impact of warmer weather on throughput. Small commercial and industrial volumes, also sensitive to weather, decreased 15.8 percent. Transportation volumes rose 10.5 percent, due to the previous period's significantly higher natural gas prices and a general economic weakness. During 2001, significantly colder weather in Alagasco's service territory caused a 19.2 percent increase in residential sales volumes and a 16.2 percent increase in small commercial and industrial sales volumes. Transportation volumes decreased 23.5 percent, primarily due to the prior-year closing of a steel manufacturing plant and reduced consumption resulting from an economic downturn during the year. In 2002, significantly lower commodity gas costs along with decreased purchased volumes due to warmer weather resulted in a 41.9 percent decrease in cost of gas. Higher commodity cost of gas, including record high prices in fiscal year 2001, along with increased purchased volumes resulting from colder weather generated a 111.5 percent increase in cost of gas for fiscal year 2001. O&M expense at the utility increased 3.1 percent in 2002 primarily due to higher insurance and labor-related costs partially offset by reduced bad debt expense and marketing costs. In fiscal 2001, O&M expense increased 1.5 percent primarily as a result of increased bad debt expense and insurance costs largely offset by reduced marketing and labor-related costs. The increase in O&M expense per customer was above the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utility's rate-setting mechanism, for the rate year ended September 30, 2002; as a result, three quarters of the difference, or $0.3 million pre-tax, was returned to the customers through RSE (see Note 2). In 2001 and 2000, the increase in O&M expense on a per-customer basis fell within the CCM. Consistent with growth in the utility's depreciable base, depreciation expense rose 8.9 percent in 2002 and 7.8 percent in 2001. 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. 19
DECEMBER 31, September 30, September 30, Years ended (in thousands) 2002 2001 2000 ------------ ------------- ------------- Natural gas transportation and sales revenues $ 424,431 $ 553,862 $ 366,161 Cost of natural gas (191,479) (329,572) (155,841) Revenue taxes (21,591) (28,766) (19,749) --------- --------- --------- Natural gas transportation and sales margin $ 211,361 $ 195,524 $ 190,571 --------- --------- --------- Natural gas sales volumes (MMcf) Residential 26,358 31,064 26,069 Commercial and industrial-small 11,838 14,054 12,092 --------- --------- --------- Total natural gas sales volumes 38,196 45,118 38,161 Natural gas transportation volumes (MMcf) 59,644 53,989 70,534 --------- --------- --------- Total deliveries (MMcf) 97,840 99,107 108,695 --------- --------- ---------
NATURAL GAS DISTRIBUTION - TRANSITION PERIOD: Natural gas distribution revenues decreased $22.4 million for the transition quarter ended December 31, 2001, largely due to a decrease in the commodity cost of gas as well as to a decrease in weather-related sales volumes and gas usage volumes. For the quarter, weather that was 30.1 percent warmer than the same period last year contributed to a 29.1 percent decrease in residential sales volumes and a 34.3 percent decrease in small commercial and industrial customer sales volumes. Transportation volumes decreased 6.3 percent primarily due to reduced consumption resulting from a general economic weakness in the transition period. Lower commodity gas prices along with decreased gas purchase volumes contributed to a 32.5 percent decrease in cost of gas for the quarter. O&M expense increased 3.2 percent in the transition quarter primarily due to increased bad debt expense partially offset by reduced labor-related and marketing costs. A 7.9 percent increase in depreciation expense in the three-months ended December 31, 2001 primarily was due to normal growth of the utility's distribution system. Taxes other than income taxes primarily reflected 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.
DECEMBER 31, December 31, Three months ended (in thousands) 2001 2000 ------------ ------------ Natural gas transportation and sales revenues $ 96,678 $ 119,126 Cost of natural gas (45,651) (67,679) Revenue taxes (4,969) (6,281) -------- --------- Natural gas transportation and sales margin $ 46,058 $ 45,166 -------- --------- Natural gas sales volumes (MMcf) Residential 5,128 7,230 Commercial and industrial-small 2,193 3,337 -------- --------- Total natural gas sales volumes 7,321 10,567 Natural gas transportation volumes (MMcf) 12,973 13,851 -------- --------- Total deliveries (MMcf) 20,294 24,418 -------- ---------
NON-OPERATING ITEMS CONSOLIDATED: Interest expense in 2002 increased $1.6 million and was influenced by increased short-term debt at Energen, primarily related to Energen Resources' acquisition of Permian Basin properties in April 2002, as well as Alagasco's issuance of $40 million of 6.25% Notes and $35 million of 6.75% Notes in August 2001 (the Notes). Fiscal 2001 interest expense increased $4.3 million primarily due to $150 million of medium term notes (MTNs) issued by Energen in December 2000 and, in part, from the issuance of the Notes. The average daily outstanding balance under short-term credit facilities was $85.6 million in 2002. The average daily outstanding balance under short-term credit facilities was $80.7 million in fiscal year 2001 as compared to $146.8 million in fiscal year 2000. The Company's effective tax rates in 2002, 2001 and 2000 were lower than statutory federal tax rates primarily due to the recognition of nonconventional fuels tax credits and the amortization of investment tax credits. Nonconventional fuels tax credits were generated annually on qualified production through December 31, 2002. 20 Income tax expense increased in 2002 and 2001 primarily due to higher pre-tax income. The Company recognized $14.2 million, $13.6 million and $14.4 million in nonconventional fuels tax credits in 2002, 2001 and 2000, respectively. The nonconventional fuels tax credits are no longer generated effective December 31, 2002, due to changes in the tax law. As of December 31, 2002, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $64.8 million. TRANSITION PERIOD: Interest expense for the Company increased $0.4 million for the transition quarter. Influencing the increase in interest expense for the transition quarter was the issuance of MTNs issued by Energen in December 2000 and the issuance of the Notes by Alagasco in August 2001. The proceeds from the Notes were used for repayment of borrowings under Energen's short-term credit facilities incurred as a result of the growth at Energen Resources and for general corporate purposes at Alagasco. The Company's effective tax rate was lower than the statutory federal tax rate primarily due to the recognition of nonconventional fuels tax credits and the amortization of investment tax credits. Income tax expense decreased in quarter comparisons primarily as a result of lower consolidated pre-tax income slightly offset by higher nonconventional fuels tax credits of $1.2 million. The increase in credit recognition reflected the annualized effective rate applied on an interim basis in the three months ended December 31, 2000, as compared to the transition period which was presented as a stand alone tax period in the current quarter. The effective tax rate utilized in computing income tax expense reflects financial recognition of $3.5 million of nonconventional fuels tax credits as produced during the transitional quarter. FINANCIAL POSITION AND LIQUIDITY The Company's net cash from operating activities totaled $213.5 million, $156.5 million and $105 million in 2002, 2001 and 2000, respectively. In 2002, operating cash flow benefited from significantly higher production volumes related to Energen Resources' property acquisition and decreased storage inventory balances at Alagasco. Operating cash flow in 2001 benefited from significantly higher realized commodity prices at Energen Resources. Working capital needs at Alagasco in 2001 were affected by increased gas costs and colder-than-normal weather 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 2002, the Company made net investments of $268.2 million. 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 total acquisition approximated $184 million and added 227 Bcfe of reserves. Energen Resources drilled 232 gross development wells incurring approximately $77 million. Energen Resources sold or traded certain properties during the current year, resulting in cash proceeds of $17 million. Utility expenditures in 2002 totaled $65.8 million and primarily represented system distribution expansion and support facilities, including, information technology application projects. Cash used in investing activities totaled $174.4 million in 2001. During fiscal 2001, Energen Resources invested $34.3 million for property acquisitions, $103.6 million for development of proved properties and $1.2 million for exploration. Energen Resources drilled 140 gross development wells spending approximately $70 million. Energen Resources sold or traded certain properties during fiscal 2001, resulting in cash proceeds of $17.3 million. Utility expenditures for fiscal 2001 totaled $56.1 million, including approximately $3 million for a municipal acquisition. Cash used in investing activities totaled $131.7 million in 2000. Energen Resources invested $2.4 million for property acquisitions, $66.7 million for development and $1.2 million for exploration during fiscal 2000. Energen Resources drilled 141 gross development wells incurring approximately $38 million. Utility expenditures in 2000 totaled $67.1 million. During 2002, the Company added approximately 162 Bcfe of reserves. These reserve additions are primarily the result of unit downspacing, which increases the number of available drilling locations, for certain wells in the Black Warrior and San Juan basins. Energen Resources' added approximately 50 Bcfe and 76 Bcfe of reserves in fiscal year 2001 and 2000, respectively. 21 Net cash provided by financing activities totaled $53 million in 2002. In the current year, 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 retirement of the Series 1993 Notes for $7.8 million. Net cash provided by financing activities totaled $19.4 million in 2001. In August 2001 Alagasco issued 6.25% Notes for $40 million, redeemable September 1, 2016, and 6.75% Notes for $35 million, redeemable September 1, 2031, and in December 2000, Energen issued $150 million of long-term debt redeemable December 15, 2010. The $223.8 million in net proceeds were used to repay short-term borrowings incurred to finance Energen Resources' growth activities and to repay additional borrowings by the utility as a result of higher capital expenditures related to replacement of liquifaction equipment and for general corporate purposes. The proceeds also were used to reduce long-term debt by $36.3 million, including the retirement of the 8% Debentures for $18.3 million. Net cash used in financing activities totaled $114.9 million in 2000 resulting primarily from fluctuations in the amount and timing of short-term debt at year-end. The Company borrowed $140.9 million at September 30, 1999 to invest in short-term federal obligations for tax planning purposes that were sold in early October 2000 with the proceeds used to repay the related debt. 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 and the employee savings plans. TRANSITION PERIOD: Cash flows from operations for the transition quarter were $21.4 million compared to $20.7 million in the three months ended December 31, 2000. The decreased net income during the period was offset by changes in working capital items, which are highly influenced by throughput, changes in weather, and timing of payments. The Company had a net investment of $35.7 million through the three months ended December 31, 2001, primarily in additions of property, plant and equipment. Energen Resources invested $25.1 million in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $12.9 million in the quarter and primarily represented system distribution expansion and support facilities. The Company had cash proceeds of $2.3 million resulting from the sale of certain properties during the transition period. The Company's financing activities provided $15.5 million for the transition quarter in net cash flows. Increased borrowings under Energen's short-term credit facilities were used to finance Energen Resources' acquisition strategy and general corporate needs at Alagasco. CAPITAL EXPENDITURES OIL AND GAS OPERATIONS: Energen Resources spent $546.6 million for capital projects during the year ended December 31, 2002, the three months ended December 31, 2001 and the years ended September 30, 2001 and 2000, $12.1 million of which was charged to income as exploration expense primarily due to the writedown of a portion of an unproved leasehold. Property acquisition expenditures totaled $221.2 million, development activities totaled $317.5 million, and exploratory expenditures totaled $2.7 million.
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------- ------------- ------------- Capital and exploration expenditures for: Property acquisitions $184,177 $ 319 $ 34,316 $ 2,436 Development 122,494 24,757 103,574 66,717 Exploration 104 228 1,190 1,150 Other 1,880 464 1,477 1,343 -------- ------- -------- ------- Total 308,655 25,768 140,557 71,646 Less exploration expenditures charged to income 3,179 716 3,671 4,556 -------- ------- -------- ------- Net capital expenditures $305,476 $25,052 $136,886 $67,090 ======== ======= ======== =======
22 NATURAL GAS DISTRIBUTION: During the year ended December 31, 2002, the three months ended December 31, 2001 and the years ended September 30, 2001 and 2000, Alagasco invested $201.9 million for capital projects: $124 million for normal expansion, replacements and support of its distribution system, $74.9 million for support facilities, including the replacement of liquifaction equipment and the development and implementation of information systems, and $3 million to purchase a municipal gas system.
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Capital and expenditures for: Renewals, replacements, system expansion and other $43,029 $ 8,839 $36,340 $35,774 Support facilities 22,786 4,034 16,733 31,299 Municipal gas system acquisition -- -- 3,017 -- ------- ------- ------- ------- Total $65,815 $12,873 $56,090 $67,073 ======= ======= ======= =======
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, 2002, Energen's EPS grew at an average compound rate of 11.5 percent a year. Over the next five years, Energen is targeting an average EPS growth rate over each rolling five-year period of 7 percent to 8 percent a year. To finance Energen Resources' investment program, the Company expects to utilize its short-term credit facilities to supplement internally generated cash flow, with long-term debt and equity providing permanent financing. Energen currently has available short-term credit facilities of $267 million to help finance its growth plans and operating needs. As an acquisition company, 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. In February 2003, Moody's Investors Service confirmed Energen's debt rating as Baa1 and Alagasco's debt rating as A1. Standard and Poor's last update in June 2002, confirmed Energen's and Alagasco's rating as A- with a stable outlook. While the Company expects to have ongoing access to it's short-term credit facilities and the broader long-term markets, continued accessibility could be affected by future economic and business conditions. Energen's management plans to utilize increases in cash flows to help finance Energen Resources' acquisition strategy. In 2003, Energen Resources plans to invest approximately $158 million, including $47 million in property acquisitions and related development and $111 million in other development and exploratory activities. Included in this $111 million is approximately $65 million for the development of previously identified proved undeveloped reserves and exploratory exposure of approximately $3 million. Capital investment at Energen Resources in 2004 is expected to approximate $123 million for property acquisitions and related development and $68 million for other development and exploration. Of this $68 million, development of previously identified proved undeveloped reserves is estimated to be $35 million and exploratory exposure is estimated to be $3 million. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2007 is estimated to be approximately $835 million, with $590 million for property acquisitions and related development, $222 million for other development and $23 million for exploratory and other activities. During the five year period, Energen Resources anticipates spending approximately $120 million on development of previously identified proved undeveloped reserves and incurring approximately $15 million in exploratory exposure. During this period, the Company expects to issue approximately $75 million in long-term debt and an estimated $25 million in equity to replace short-term obligations and to provide permanent financing for its acquisition strategy. The Company will also provide up to $14 million a year from the issuance of common stock through the dividend reinvestment and direct stock purchase plan, and through employee savings plans. 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 23 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 strategy. These acquisitions may alter the aforementioned financing requirements. Additionally, Energen Resources may enter into negotiations to sell, trade or otherwise dispose of properties which may reduce or eliminate the amount of additional financing described above. During 2003, Alagasco plans to invest approximately $57 million in utility capital expenditures for normal distribution and support systems. Alagasco maintains an investment in storage gas that is expected to average approximately $42 million in 2003. Alagasco plans to invest approximately $55 million in utility capital expenditures during 2004. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. Over the Company's five-year planning period ending September 30, 2007, Alagasco anticipates capital investments of approximately $265 million. 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, 2002.
PAYMENTS DUE BY PERIOD ------------------------------------------------------------------------ LESS THAN AFTER 5 (in thousands) TOTAL 1 YEAR 1 - 3 YEARS 4 - 5 YEARS YEARS -------- --------- ----------- ----------- --------- Short-term cash obligations $113,000 $113,000 $ -- $ -- $ -- Long-term cash obligations (1) 537,533 23,000 40,000 22,000 452,533 Gas procurement contracts (2) 265,380 50,107 100,017 82,354 32,902 Operating leases 45,883 3,609 8,467 4,505 29,302 -------- -------- -------- -------- -------- Total contractual cash obligations $961,796 $189,716 $148,484 $108,859 $514,737 ======== ======== ======== ======== ========
(1) Long-term cash obligations include $1.6 million of unamortized debt discounts as of December 31, 2002. (2) Certain of the Company's long-term contracts for the supply, storage and delivery of natural gas include fixed charges that amount to approximately $265.4 million through October 2010. 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 55.4 billion cubic feet through October 2004. Alagasco entered into an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $20 million as further described in Note 8. OUTLOOK OIL AND GAS OPERATIONS: Energen Resources plans to continue to implement its acquisition and development program with capital spending in fiscal years 2003 and 2004 as outlined above. Production in 2003 is expected to be approximately 85 Bcfe, including 82.4 Bcfe of estimated production from proved reserves owned at December 31, 2002. In 2004, production is estimated to reach approximately 87 Bcfe, including approximately 77 Bcfe produced from proved reserves currently owned. Nonconventional fuels tax credits were generated annually on qualified production through December 31, 2002. To mitigate the effects of the tax credit benefit, Energen Resources has replaced a portion of the tax credits with revenue-generating property acquisitions and related development affecting corporate earnings in 2003 and has increased the number of available drilling locations through unit downspacing in the Black Warrior Basin. 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 24 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 periodically enters into cash flow derivative commodity instruments to hedge its exposure to oil, natural gas and natural gas liquids price fluctuations. In addition, Alagasco enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments 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's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counterparty credit. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. Energen Resources may hedge up to 80 percent of its estimated annual production under this policy. As acquisitions are made, Energen Resources may use futures, swaps and/or fixed-price contracts to hedge commodity prices for up to 36 months in order to protect targeted returns. As of December 31, 2002, 78 percent of Energen Resources' estimated 2003 gas production, excluding anticipated acquisition volumes, was hedged or under contract. These hedges included 30.9 Bcf of its estimated gas production at an average NYMEX price of $4.13 per Mcf, 4.4 Bcf of basin-specific hedges at an average contract price of $3.86 and 4.8 Bcf of gas production hedged with a basin-specific collar price of $3.72 to $4.70 per Mcf. The Company also had hedges in place for 2,478 MBbl or 68 percent of its estimated 2003 oil production, excluding anticipated acquisition volumes, at an average NYMEX price of $26.26 per barrel and 38 MMGal or 53 percent of its estimated 2003 natural gas liquids production at an average price of $0.42 per gallon. In addition, the Company had hedged the basis difference on 11.7 Bcf of its estimated 2003 gas production and 2,174 MBbl of its oil production. Subsequent to December 31, 2002, Energen Resources entered into additional hedges for 2003, resulting in a total of 2,628 MBbl of its estimated 2003 oil production hedged at an average NYMEX price of $26.36. The Company also entered into additional basis hedges resulting in a total of 15.7 Bcf of basis hedges on its estimated 2003 gas production and 2,271 MBbl of basis hedges on its estimated 2003 oil production. At December 31, 2002, Energen Resources had entered into swaps for 6.5 Bcf of its estimated 2004 gas production at an average NYMEX price of $4.02 per Mcf and 2.4 Bcf of its estimated 2004 gas production hedged with a NYMEX collar price of $4.05 to $4.44 per Mcf. Subsequent to December 31, 2002, Energen Resources entered into additional hedges for 2004, resulting in a total of 8.9 Bcf of its estimated 2004 gas production hedged at an average NYMEX price of $4.13 per Mcf, 120 MBbl of its estimated 2004 oil production hedged at an average NYMEX price of $26.15 and 13.9 Bcf of basin-specific hedges at an average contract price of $3.83 per Mcf. In addition, the Company hedged 30 MMGal of its estimated 2004 natural gas liquids production at an average price of $0.41 per gallon. For 2005, Energen Resources had entered into swaps for 1.2 Bcf of its gas production at an average NYMEX price of $3.75 per Mcf. 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, 2002, the Company estimated that a 10 percent increase in the commodities prices would have resulted in a $27.2 million change in the fair value of open derivative contracts while a 10 percent decrease in the commodities prices would have resulted in a $26.6 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. At December 31, 2001 and September 30, 2001, the Company estimated that a 10 percent change in the commodities prices would have resulted in a $2.1 million and a $6.9 million change, respectively, in the fair value of open derivative contracts. Due to the short duration of the 25 contracts, the time value of money was not considered. 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, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. As discussed in Note 2,the utility's CCM is based in part on the number of residential 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 equity lower than the allowed range of return due to the operation of the CCM. 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. Even though the utility enjoys a market saturation rate higher than the national average, customer growth in the service territory is limited. On December 4, 2000, the APSC authorized Alagasco to engage in energy risk management activities to manage the utility's cost of gas supply. As required by SFAS No. 133, Alagasco recognizes all derivatives at their fair values 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 it's APSC-approved tariff. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," Alagasco had recorded a regulatory liability of $16.8 million representing the fair value of derivatives as of December 31, 2002. FORWARD-LOOKING STATEMENT AND RISK: 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 Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. The Company undertakes no 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, future business decisions, 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 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 risk, fluctuations in future oil and gas prices could materially affect the Company's financial position and results of operation; 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. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB) 26 In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company adopted this statement as of January 1, 2002 (See Note 10). The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" in June 2002. This statement requires that a liability for costs associated with exit or disposal activities be recognized at fair value in the period the liability is incurred. This Statement does not apply to costs associated with the retirement of long-lived assets covered by SFAS No. 143. The Company has adopted this statement for disposal or exit activities initiated after December 31, 2002. The FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure" in December 2002. This statement is effective for 2003 and amends SFAS No. 123, "Accounting for Stock-Based Compensation" by providing alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 requires additional disclosures related to the effect of stock-based compensation on reported results. The Company has adopted the disclosure provisions of SFAS No. 148 and is currently reviewing its treatment of stock-based compensation as well as the impact of this pronouncement. The FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosures Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," (FIN 45) in November 2002. FIN 45 clarifies the requirements of SFAS No. 5, "Accounting for Contingencies," related to a guarantors accounting for, and disclosures of, the issuance of certain types of guarantees. Management has completed a review of potential contingencies and noted the following guarantee disclosure: Alagasco has an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $20 million. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables (see Note 8). The Company is required to adopt the provisions for initial recognition and measurement for all guarantees issued or modified after December 31, 2002 on a prospective basis. The Company is currently reviewing the impact related to the initial recognition and measurement guarantees of this Interpretation. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46) which clarifies the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements." This Interpretation provides guidance on the identification and consolidation of variable interest entities (VIEs), whereby control is achieved through means other than through voting rights. Management has completed an analysis of FIN 46 and has determined that the Company does not have VIEs. 27 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by this item in 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. 28 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 Accountants................................................................................. 31 Consolidated Statements of Income for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000.................................................................................................... 32 Consolidated Balance Sheets as of December 31, 2002 and 2001, and September 30, 2001............................................................................................... 33 Consolidated Statements of Shareholders' Equity for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000...................................................................................... 35 Consolidated Statements of Cash Flows for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000...................................................................................... 36 Notes to Financial Statements.................................................................................... 42 ALABAMA GAS CORPORATION Report of Independent Accountants................................................................................ 31 Statements of Income for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000......................................... 37 Balance Sheets as of December 31, 2002 and 2001, and September 30, 2001 ......................................... 38 Statements of Shareholder's Equity for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000.................................................................................................... 40 Statements of Cash Flows for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000......................................................................................................... 41 Notes to Financial Statements.................................................................................... 42 2. Financial Statement Schedules ENERGEN CORPORATION Schedule II - Valuation and Qualifying Accounts.................................................................. 73 ALABAMA GAS CORPORATION Schedule II - Valuation and Qualifying Accounts.................................................................. 73
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. 29 REPORT OF MANAGEMENT The accompanying consolidated financial statements and related notes of Energen Corporation and subsidiaries and the financial statements and related notes of Alabama Gas Corporation (collectively, "the financial statements") were prepared by management, which has the primary responsibility for the integrity of the financial information therein. These financial statements were prepared in conformity with accounting principles generally accepted in the United States of America appropriate in the circumstances and include amounts which are based necessarily on management's best estimates and judgments. Financial information presented elsewhere in this report is consistent with the information in the financial statements. Management maintains a comprehensive system of internal accounting controls and relies on the system to discharge its responsibility for the integrity of the financial statements. This system provides reasonable assurance that corporate assets are safeguarded and that transactions are recorded in such a manner as to permit the preparation of materially reliable financial information. Reasonable assurance recognizes that the cost of a system of internal accounting controls should not exceed the related benefits. This system of internal accounting controls is augmented by written policies and procedures, internal auditing, and the careful selection and training of qualified personnel. As of December 31, 2002, management was aware of no material weaknesses in Energen or Alabama Gas Corporation's systems of internal accounting controls. The financial statements have been audited by the Company's independent accountants, whose opinions are expressed elsewhere in this Form 10-K. Their audits were conducted in accordance with generally accepted auditing standards; and, in connection therewith, they obtained an understanding of the Company's systems of internal accounting controls and conducted such tests and related procedures as they deemed necessary to arrive at an opinion on the fairness of presentation of the financial statements. The functioning of the accounting system and related internal accounting controls is under the general oversight of the Audit Committee of the Board of Directors, which is comprised of four outside Directors. The Audit Committee meets regularly with the independent accountants and representatives of management to discuss matters regarding internal accounting controls, auditing and financial reporting. Geoffrey C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer 30 REPORT OF INDEPENDENT ACCOUNTANTS TO THE SHAREHOLDERS OF ENERGEN CORPORATION: In our opinion, the consolidated financial statements of Energen Corporation listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and subsidiaries at December 31, 2002 and 2001 and September 30, 2001, and the results of their operations and their cash flows for the year ended December 31, 2002, the three months ended December 31, 2001 and the years ended September 30, 2001 and 2000, 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 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. As discussed in Notes 10 and 12, 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" and SFAS No. 144, "Accounting for the Impairment of Long-Lived Assets," respectively. PricewaterhouseCoopers LLP Birmingham, Alabama February 21, 2003 REPORT OF INDEPENDENT ACCOUNTANTS 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, 2002 and 2001 and September 30, 2001, and the results of its operations and its cash flows for the year ended December 31, 2002, the three months ended December 31, 2001 and the years ended September 30, 2001 and 2000, 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 February 21, 2003 31 CONSOLIDATED STATEMENTS OF INCOME ENERGEN CORPORATION
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands, except share data) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- OPERATING REVENUES Oil and gas operations $ 252,744 $ 49,486 $ 223,512 $ 185,248 Natural gas distribution 424,431 96,678 553,862 366,161 ----------- ----------- ----------- ----------- Total operating revenues 677,175 146,164 777,374 551,409 ----------- ----------- ----------- ----------- OPERATING EXPENSES Cost of gas 189,810 45,291 327,531 154,201 Operations and maintenance 195,954 54,630 182,295 170,708 Depreciation, depletion and amortization 105,087 24,502 84,779 84,934 Taxes, other than income taxes 50,238 10,881 61,734 46,555 ----------- ----------- ----------- ----------- Total operating expenses 541,089 135,304 656,339 456,398 ----------- ----------- ----------- ----------- OPERATING INCOME 136,086 10,860 121,035 95,011 ----------- ----------- ----------- ----------- OTHER INCOME (EXPENSE) Interest expense (43,713) (10,634) (42,070) (37,769) Accretion expense (1,819) -- -- -- Other income 15,644 4,354 16,825 17,315 Other expense (15,103) (4,385) (14,892) (15,540) ----------- ----------- ----------- ----------- Total other expense (44,991) (10,665) (40,137) (35,994) ----------- ----------- ----------- ----------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 91,095 195 80,898 59,017 Income tax expense (benefit) 20,509 (3,384) 14,811 6,482 ----------- ----------- ----------- ----------- INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 70,586 3,579 66,087 52,535 ----------- ----------- ----------- ----------- DISCONTINUED OPERATIONS, NET OF TAXES Income (loss) from discontinued operations (267) 79 1,809 483 Gain on disposal 540 -- -- -- ----------- ----------- ----------- ----------- INCOME FROM DISCONTINUED OPERATIONS 273 79 1,809 483 ----------- ----------- ----------- ----------- CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAXES (2,220) -- -- -- ----------- ----------- ----------- ----------- NET INCOME $ 68,639 $ 3,658 $ 67,896 $ 53,018 =========== =========== =========== =========== DILUTED EARNINGS PER AVERAGE COMMON SHARE Continuing operations $ 2.09 $ 0.12 $ 2.13 $ 1.73 Discontinued operations 0.01 -- 0.05 0.02 Cumulative effect of change in accounting principle (0.07) -- -- -- ----------- ----------- ----------- ----------- Net Income $ 2.03 $ 0.12 $ 2.18 $ 1.75 =========== =========== =========== =========== BASIC EARNINGS PER AVERAGE COMMON SHARE Continuing operations $ 2.10 $ 0.12 $ 2.15 $ 1.74 Discontinued operations 0.01 -- 0.06 0.02 Cumulative effect of change in accounting principle (0.07) -- -- -- ----------- ----------- ----------- ----------- Net Income $ 2.04 $ 0.12 $ 2.21 $ 1.76 =========== =========== =========== =========== DILUTED AVERAGE COMMON SHARES OUTSTANDING 33,838,299 31,277,406 31,083,784 30,359,417 =========== =========== =========== =========== BASIC AVERAGE COMMON SHARES OUTSTANDING 33,604,601 31,052,152 30,725,919 30,108,149 =========== =========== =========== ===========
The accompanying Notes to Financial Statements are an integral part of these statements. 32 CONSOLIDATED BALANCE SHEETS ENERGEN CORPORATION
DECEMBER 31, December 31, September 30, (in thousands) 2002 2001 2001 ------------ ------------ ------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 4,804 $ 6,482 $ 5,333 Accounts receivable, net of allowance for doubtful accounts of $8,874 at December 31, 2002, of $11,783 at December 31, 2001, and of $10,031 at September 30, 2001 100,946 77,106 74,078 Inventories, at average cost Storage gas inventory 23,668 50,978 56,761 Materials and supplies 8,335 8,894 10,225 Liquified natural gas in storage 3,671 3,146 3,271 Deferred gas costs 21,040 17,776 3,275 Regulatory asset -- -- 95 Deferred income taxes 33,941 29,636 12,425 Prepayments and other 20,367 6,948 27,081 ---------- ---------- ---------- Total current assets 216,772 200,966 192,544 ---------- ---------- ---------- PROPERTY, PLANT AND EQUIPMENT Oil and gas properties, successful efforts method 1,103,472 844,962 822,956 Less accumulated depreciation, depletion and amortization 269,616 228,867 209,451 ---------- ---------- ---------- Oil and gas properties, net 833,856 616,095 613,505 ---------- ---------- ---------- Utility plant 825,421 769,259 758,374 Less accumulated depreciation 408,165 384,430 378,218 ---------- ---------- ---------- Utility plant, net 417,256 384,829 380,156 ---------- ---------- ---------- Other property, net 5,691 4,755 4,673 ---------- ---------- ---------- Total property, plant and equipment, net 1,256,803 1,005,679 998,334 ---------- ---------- ---------- OTHER ASSETS Deferred income taxes 16,333 8,406 12,039 Regulatory asset 14,744 -- -- Deferred charges and other 26,239 25,305 20,962 ---------- ---------- ---------- Total other assets 57,316 33,711 33,001 ---------- ---------- ---------- TOTAL ASSETS $1,530,891 $1,240,356 $1,223,879 ========== ========== ==========
The accompanying Notes to Financial Statements are an integral part of these statements. 33 CONSOLIDATED BALANCE SHEETS ENERGEN CORPORATION
DECEMBER 31, December 31, September 30, (in thousands, except share data) 2002 2001 2001 ------------ ------------ ------------- CAPITAL AND LIABILITIES CURRENT LIABILITIES Long-term debt due within one year $ 23,000 $ 16,072 $ 16,072 Notes payable to banks 113,000 24,000 7,000 Accounts payable 103,964 58,783 65,412 Accrued taxes 27,936 32,183 30,014 Customers' deposits 17,404 16,399 15,195 Amounts due customers 8,458 6,434 -- Accrued wages and benefits 23,652 22,711 25,821 Regulatory liability 23,814 8,462 3,792 Other 34,710 29,564 32,217 ---------- ---------- ---------- Total current liabilities 375,938 214,608 195,523 ---------- ---------- ---------- DEFERRED CREDITS AND OTHER LIABILITIES Asset retirement obligation 27,235 -- -- Minimum pension liability 25,825 -- -- Regulatory liability 1,468 137 242 Other 4,661 7,273 3,237 ---------- ---------- ---------- Total deferred credits and other liabilities 59,189 7,410 3,479 ---------- ---------- ---------- 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, 34,745,477 shares outstanding at December 31, 2002, 31,248,547 shares outstanding at December 31, 2001, and 31,124,761 shares outstanding at September 30, 2001 347 312 311 Premium on capital stock 320,060 235,976 233,471 Capital surplus 2,802 2,802 2,802 Retained earnings 275,266 230,554 232,354 Accumulated other comprehensive income (loss), net of tax Unrealized gain (loss) on hedges (10,471) 7,168 15,531 Minimum pension liability (4,340) -- -- Deferred compensation on restricted stock (770) (1,513) (1,186) Deferred compensation plan 10,348 7,222 5,259 Treasury stock, at cost; 358,228 shares and 341,465 shares at December 31, 2002 and 2001, respectively, and 325,355 shares at September 30, 2001 (10,432) (8,316) (7,775) ---------- ---------- ---------- Total common shareholders' equity 582,810 474,205 480,767 Long-term debt 512,954 544,133 544,110 ---------- ---------- ---------- Total capitalization 1,095,764 1,018,338 1,024,877 ---------- ---------- ---------- TOTAL CAPITAL AND LIABILITIES $1,530,891 $1,240,356 $1,223,879 ========== ========== ==========
The accompanying Notes to Financial Statements are an integral part of these statements. 34 CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY ENERGEN CORPORATION
(in thousands, except share amounts) Common Stock -------------------------- Number of Par Premium on Capital Retained Shares Value Capital Stock Surplus Earnings ---------- ---------- ------------- ---------- ---------- BALANCE SEPTEMBER 30, 1999 29,903,964 $ 299 $ 205,831 $ 2,802 $ 152,572 Net income 53,018 Purchase of treasury shares Shares issued for: Dividend reinvestment plan 57,920 1 1,438 Employee benefit plans 388,918 4 6,313 Deferred compensation obligation Cash dividends - $0.665 per share (20,029) ---------- ---------- ---------- ---------- ---------- BALANCE SEPTEMBER 30, 2000 30,350,802 304 213,582 2,802 185,561 Net income 67,896 Other comprehensive income (loss): Transition adjustment on cash flow hedging activities, net of tax of ($35,430) Current period change in fair value of derivative instruments, net of tax of $11,740 Reclassification adjustment, net of tax of $33,619 Comprehensive income Purchase of treasury shares Shares issued for: Dividend reinvestment plan 75,480 1 2,366 Employee benefit plans 698,479 6 17,523 Deferred compensation obligation Issuance of restricted stock Amortization of restricted stock Cash dividends - $0.685 per share (21,103) ---------- ---------- ---------- ---------- ---------- BALANCE SEPTEMBER 30, 2001 31,124,761 311 233,471 2,802 232,354 Net income 3,658 Other comprehensive loss: Current period change in fair value of derivative instruments, net of tax of ($187) Reclassification adjustment, net of tax of ($3,821) Minimum pension liability, net of tax of ($1,127) Comprehensive loss Purchase of treasury shares Shares issued for: Dividend reinvestment plan 5,519 -- 72 Employee benefit plans 118,267 1 2,433 Deferred compensation obligation Issuance of restricted stock Amortization of restricted stock Cash dividends - $0.175 per share (5,458) ---------- ---------- ---------- ---------- ---------- BALANCE DECEMBER 31, 2001 31,248,547 312 235,976 2,802 230,554 Net income 68,639 Other comprehensive loss: Current period change in fair value of derivative instruments, net of tax of ($9,893) Reclassification adjustment, net of tax of ($2,724) Minimum pension liability, net of tax of ($1,211) Comprehensive loss Purchase of treasury shares Shares issued for: Stock issuance for acquisition 3,043,479 30 72,861 Dividend reinvestment plan 77,725 1 2,020 Employee benefit plans 375,726 4 9,203 Deferred compensation obligation Amortization of restricted stock Cash dividends - $0.71 per share (23,927) ---------- ---------- ---------- ---------- ---------- BALANCE DECEMBER 31, 2002 34,745,477 $ 347 $ 320,060 $ 2,802 $ 275,266 ========== ========== ========== ========== ========== (in thousands, except share amounts) Accumulated Other Deferred Deferred Comprehensive Compensation Compensation Treasury Shareholders' Income (Loss) Restricted Stock Plan Stock Equity ------------- ---------------- ------------ ---------- ------------- BALANCE SEPTEMBER 30, 1999 $ -- $ -- $ 2,054 $ (2,054) $ 361,504 Net income 53,018 Purchase of treasury shares (4,934) (4,934) Shares issued for: Dividend reinvestment plan 1,395 2,834 Employee benefit plans 2,150 8,467 Deferred compensation obligation 2,911 (2,911) -- Cash dividends - $0.665 per share (20,029) ---------- ---------- ---------- ---------- ---------- BALANCE SEPTEMBER 30, 2000 -- -- 4,965 (6,354) 400,860 Net income 67,896 Other comprehensive income (loss): Transition adjustment on cash flow hedging activities, net of tax of ($35,430) (55,416) (55,416) Current period change in fair Value of derivative instruments, net of tax of $11,740 18,363 18,363 Reclassification adjustment, net of tax of $33,619 52,584 52,584 ---------- Comprehensive income 83,427 ---------- Purchase of treasury shares (2,516) (2,516) Shares issued for: Dividend reinvestment plan 331 2,698 Employee benefit plans 1,058 18,587 Deferred compensation obligation 294 (294) -- Issuance of restricted stock (1,662) (1,662) Amortization of restricted stock 476 476 Cash dividends - $0.685 per share (21,103) ---------- ---------- ---------- ---------- ---------- BALANCE SEPTEMBER 30, 2001 15,531 (1,186) 5,259 (7,775) 480,767 Net income 3,658 Other comprehensive loss: Current period change in fair value of derivative instruments, net of tax of ($187) (292) (292) Reclassification adjustment, net of tax of ($3,821) (5,977) (5,977) Minimum pension liability, net of tax of ($1,127) (2,094) (2,094) ---------- Comprehensive loss (4,705) ---------- Purchase of treasury shares (1,245) (1,245) Shares issued for: Dividend reinvestment plan 689 761 Employee benefit plans 1,978 4,412 Deferred compensation obligation 1,963 (1,963) -- Issuance of restricted stock (515) (515) Amortization of restricted stock 188 188 Cash dividends - $0.175 per share (5,458) ---------- ---------- ---------- ---------- ---------- BALANCE DECEMBER 31, 2001 7,168 (1,513) 7,222 (8,316) 474,205 Net income 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 loss 46,660 ---------- Purchase of treasury shares (133) (133) Shares issued for: Stock issuance for acquisition 72,891 Dividend reinvestment plan 401 2,422 Employee benefit plans 742 9,949 Deferred compensation obligation 3,126 (3,126) -- Amortization of restricted stock 743 743 Cash dividends - $0.71 per share (23,927) ---------- ---------- ---------- ---------- ---------- BALANCE DECEMBER 31, 2002 $ (14,811) $ (770) $ 10,348 $ (10,432) $ 582,810 ========== ========== ========== ========== ==========
The accompanying Notes to Financial Statements are an integral part of these statements. 35 CONSOLIDATED STATEMENTS OF CASH FLOWS ENERGEN CORPORATION
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------- ------------- ------------- OPERATING ACTIVITIES Net income $ 68,639 $ 3,658 $ 67,896 $ 53,018 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion and amortization 110,767 25,184 86,975 87,073 Deferred income taxes, net 10,915 (8,495) 5,349 (5,400) Deferred investment tax credits, net (448) (112) (448) (448) Change in derivative fair value (9,205) (174) (879) -- (Gain) loss on sale of assets (3,738) 3,161 (4,716) (1,107) Loss on properties held for sale -- -- 3,821 -- Cumulative effect of change in accounting principle, net of taxes (2,220) -- -- -- Net change in: Accounts receivable (23,840) (3,028) 19,284 (18,857) Inventories 27,344 7,239 (22,018) (11,912) Accounts payable 28,600 2,442 16,544 4,569 Deferred gas costs (3,264) (14,501) 281 (1,251) Amounts due customers 626 11,637 (11,655) (3,662) Other current assets and liabilities 1,712 (4,813) 1,424 8,370 Other, net 7,619 (837) (5,362) (5,350) --------- -------- --------- --------- Net cash provided by operating activities 213,507 21,361 156,496 105,043 --------- -------- --------- --------- INVESTING ACTIVITIES Additions to property, plant and equipment (166,075) (37,752) (190,695) (133,061) Acquisition, net of cash acquired (117,043) -- -- -- Proceeds from sale of assets 17,094 2,323 17,326 2,647 Other, net (2,198) (252) (1,038) (1,329) --------- -------- --------- --------- Net cash used in investing activities (268,222) (35,681) (174,407) (131,743) --------- -------- --------- --------- FINANCING ACTIVITIES Payment of dividends on common stock (23,927) (5,458) (21,103) (20,029) Issuance of common stock 12,371 5,172 21,285 11,301 Purchase of treasury stock (133) (1,245) (2,516) (4,934) Reduction of long-term debt (21,204) -- (36,267) (1,205) Proceeds from issuance of long-term debt -- -- 223,799 -- Debt issuance costs -- -- (4,777) -- Net change in short-term debt issued to purchase U.S. Treasury securities -- -- -- (140,917) Net change in short-term debt 85,930 17,000 (161,000) 40,917 --------- -------- --------- --------- Net cash provided by (used in) financing activities 53,037 15,469 19,421 (114,867) --------- -------- --------- --------- Net change in cash and cash equivalents (1,678) 1,149 1,510 (141,567) Cash and cash equivalents at beginning of period 6,482 5,333 3,823 145,390 --------- -------- --------- --------- Cash and cash equivalents at end of period $ 4,804 $ 6,482 $ 5,333 $ 3,823 ========= ======== ========= =========
The accompanying Notes to Financial Statements are an integral part of these statements. 36 STATEMENTS OF INCOME ALABAMA GAS CORPORATION
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------- ------------- ------------- OPERATING REVENUES $ 424,431 $ 96,678 $ 553,862 $ 366,161 --------- -------- --------- --------- OPERATING EXPENSES Cost of gas 191,479 45,651 329,572 155,841 Operations and maintenance 109,115 27,687 105,812 104,206 Depreciation 33,682 8,151 30,933 28,708 Income taxes Current 8,764 10,348 16,995 16,711 Deferred, net 9,509 (8,689) (3,099) (1,939) Deferred investment tax credits, net (448) (112) (448) (448) Taxes, other than income taxes 30,785 7,155 37,257 28,343 --------- -------- --------- --------- Total operating expenses 382,886 90,191 517,022 331,422 --------- -------- --------- --------- OPERATING INCOME 41,545 6,487 36,840 34,739 --------- -------- --------- --------- OTHER INCOME (EXPENSE) Allowance for funds used during construction 1,336 122 2,098 1,172 Other income 5,520 1,596 5,978 7,520 Other expense (6,280) (1,838) (6,585) (7,239) --------- -------- --------- --------- Total other income (expense) 576 (120) 1,491 1,453 --------- -------- --------- --------- INTEREST CHARGES Interest on long-term debt 13,153 3,327 8,803 8,542 Other interest charges 1,404 353 3,513 1,328 --------- -------- --------- --------- Total interest charges 14,557 3,680 12,316 9,870 --------- -------- --------- --------- NET INCOME $ 27,564 $ 2,687 $ 26,015 $ 26,322 ========= ======== ========= =========
The accompanying Notes to Financial Statements are an integral part of these statements. 37 BALANCE SHEETS ALABAMA GAS CORPORATION
December 31, December 31, September 30, (in thousands) 2002 2001 2001 ------------ ------------ ------------- ASSETS PROPERTY, PLANT AND EQUIPMENT Utility plant $ 825,421 $ 769,259 $ 758,374 Less accumulated depreciation 408,165 384,430 378,218 --------- --------- --------- Utility plant, net 417,256 384,829 380,156 --------- --------- --------- Other property, net 842 308 333 --------- --------- --------- CURRENT ASSETS Cash 2,818 3,372 1,555 Accounts receivable Gas 70,220 59,504 47,024 Merchandise 1,748 1,506 1,417 Other 656 626 1,448 Affiliated companies -- -- 937 Allowance for doubtful accounts (8,200) (11,100) (9,500) Inventories, at average cost Storage gas inventory 23,668 50,978 56,761 Materials and supplies 5,049 5,363 5,423 Liquified natural gas in storage 3,671 3,146 3,271 Deferred gas costs 21,040 17,776 3,275 Regulatory asset -- -- 95 Deferred income taxes 20,093 22,820 14,477 Prepayments and other 18,314 1,378 2,521 --------- --------- --------- Total current assets 159,077 155,369 128,704 --------- --------- --------- OTHER ASSETS Regulatory asset 14,744 -- -- Deferred charges and other 11,290 8,715 8,546 --------- --------- --------- Total other assets 26,034 8,715 8,546 --------- --------- --------- TOTAL ASSETS $ 603,209 $ 549,221 $ 517,739 ========= ========= =========
The accompanying Notes to Financial Statements are an integral part of these statements. 38 BALANCE SHEETS ALABAMA GAS CORPORATION
DECEMBER 31, December 31, September 30, (in thousands, except share data) 2002 2001 2001 ------------ ------------ ------------- 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, 2002 and 2001, and September 30, 2001, respectively 20 20 20 Premium on capital stock 31,682 31,682 31,682 Capital surplus 2,802 2,802 2,802 Retained earnings 182,852 172,147 174,885 -------- -------- -------- Total common shareholder's equity 217,356 206,651 209,389 Long-term debt 169,533 185,000 185,000 -------- -------- -------- Total capitalization 386,889 391,651 394,389 -------- -------- -------- CURRENT LIABILITIES Long-term debt due within one year 15,000 5,000 5,000 Notes payable to banks 13,000 19,000 1,000 Accounts payable Trade 55,720 34,023 32,078 Affiliated companies 1,432 3,054 -- Accrued taxes 24,044 29,505 26,963 Customers' deposits 17,404 16,399 15,195 Amounts due customers 8,458 6,434 -- Accrued wages and benefits 5,710 10,509 11,616 Regulatory liability 23,814 8,462 3,792 Other 8,947 7,289 9,416 -------- -------- -------- Total current liabilities 173,529 139,675 105,060 -------- -------- -------- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 20,747 15,531 15,825 Minimum pension liability 18,661 -- -- Accumulated deferred investment tax credits 756 1,204 1,317 Regulatory liability 1,468 137 242 Customer advances for construction and other 1,159 1,023 906 -------- -------- -------- Total deferred credits and other liabilities 42,791 17,895 18,290 -------- -------- -------- COMMITMENTS AND CONTINGENCIES -------- -------- -------- TOTAL CAPITAL AND LIABILITIES $603,209 $549,221 $517,739 ======== ======== ========
The accompanying Notes to Financial Statements are an integral part of these statements. 39 STATEMENTS OF SHAREHOLDER'S EQUITY ALABAMA GAS CORPORATION
(in thousands, except share amounts) COMMON STOCK ------------------------ TOTAL NUMBER OF PAR PREMIUM ON CAPITAL RETAINED SHAREHOLDER'S SHARES VALUE CAPITAL STOCK SURPLUS EARNINGS EQUITY --------- --------- ------------- --------- --------- ------------- BALANCE SEPTEMBER 30, 1999 1,972,052 $ 20 $ 31,682 $ 2,802 $ 143,502 $ 178,006 Net income 26,322 26,322 Cash dividends (5,057) (5,057) --------- --------- --------- --------- --------- --------- BALANCE SEPTEMBER 30, 2000 1,972,052 20 31,682 2,802 164,767 199,271 Net income 26,015 26,015 Cash dividends (15,897) (15,897) --------- --------- --------- --------- --------- --------- BALANCE SEPTEMBER 30, 2001 1,972,052 20 31,682 2,802 174,885 209,389 Net income 2,687 2,687 Cash dividends (5,425) (5,425) --------- --------- --------- --------- --------- --------- 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 ========= ========= ========= ========= ========= =========
The accompanying Notes to Financial Statements are an integral part of these statements. 40 STATEMENTS OF CASH FLOWS ALABAMA GAS CORPORATION
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- OPERATING ACTIVITIES Net income $ 27,564 $ 2,687 $ 26,015 $ 26,322 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation and amortization 33,682 8,151 30,933 28,708 Deferred income taxes, net 9,509 (8,689) (3,099) (1,939) Deferred investment tax credits (448) (112) (448) (448) Net change in: Accounts receivable (13,887) (10,147) 5,775 (9,290) Inventories 27,099 5,968 (20,351) (12,040) Deferred gas costs (3,264) (14,501) 281 (1,251) Accounts payable 21,697 1,945 (7,298) 2,391 Amounts due customers 626 11,637 (11,655) (3,662) Other current assets and liabilities (6,666) 1,191 7,692 1,617 Other, net (1,447) (201) (2,231) (1,663) --------- -------- --------- --------- Net cash provided (used) by operating activities 94,465 (2,071) 25,614 28,745 --------- -------- --------- --------- INVESTING ACTIVITIES Additions to property, plant and equipment (64,257) (12,820) (53,749) (65,684) Net advances from (to) parent company (1,622) 3,990 (2,093) 21,811 Other, net (814) 143 (327) 18 --------- -------- --------- --------- Net cash used in investing activities (66,693) (8,687) (56,169) (43,855) --------- -------- --------- --------- FINANCING ACTIVITIES Payment of dividends on common stock (16,859) (5,425) (15,897) (5,057) Reduction of long-term debt (5,467) -- -- -- Proceeds from issuance of long-term debt -- -- 75,000 -- Debt issuance costs -- -- (3,709) -- Net change in short-term debt (6,000) 18,000 (24,150) 20,500 --------- -------- --------- --------- Net cash provided (used) by financing activities (28,326) 12,575 31,244 15,443 --------- -------- --------- --------- Net change in cash and cash equivalents (554) 1,817 689 333 Cash and cash equivalents at beginning of period 3,372 1,555 866 533 --------- -------- --------- --------- Cash and cash equivalents at end of period $ 2,818 $ 3,372 $ 1,555 $ 866 ========= ======== ========= =========
The accompanying Notes to Financial Statements are an integral part of these statements. 41 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. 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. Alagasco has continued 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. 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 and gas 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. 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. All development costs are capitalized. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the unit-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated over the estimated useful life of the related asset. The costs and related accumulated depletion of properties sold or retired are removed from the accounts and the resulting gains or losses are included in discontinued operations. OPERATING REVENUE: Energen Resources utilizes the sales method of accounting to recognize oil and gas production revenue. Under the sales method, revenue is recognized for the Company's total takes of oil and gas production that are sold to and payable by its customers. 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, 2002. DERIVATIVE COMMODITY INSTRUMENTS: Energen Resources periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments 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 Company's credit ratings must be maintained at investment grade status to have available counterparty credit. 42 The Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (subsequently amended by SFAS Nos. 137 and 138), "Accounting for Derivative Instruments and Hedging Activities," 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 when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in earnings in the period of change. As of December 31, 2002, all of the Company's derivatives qualified for cash flow hedge accounting. 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 subject to the Company's risk management policy as approved by the Board of Directors. The policy's objective is to preserve revenues from forecasted sales and 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. 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, together with the cost of removal less salvage, is charged to the accumulated reserve for depreciation. 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 year ended December 31, 2002, for the three months ended December 31, 2001 and for the years ended September 30, 2001 and 2000. INVENTORIES: Inventories, which consist primarily of gas stored underground, are stated at average cost. OPERATING REVENUE AND GAS COSTS: In accordance with industry practice, Alagasco records natural gas distribution revenues on a monthly- and cycle-billing basis. The commodity cost of purchased gas applicable to gas delivered to customers but not yet billed under the cycle-billing method is deferred as a current asset. 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. 43 DERIVATIVE COMMODITY INSTRUMENTS: 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, as required by SFAS No. 71. TAXES ON REVENUES: Collections and payments of excise taxes are reported on a gross basis. The amounts included in taxes other than income taxes on the consolidated statements of income are as follows:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Taxes on revenues $21,591 $4,969 $28,766 $19,749 ------- ------ ------- ------- Total $21,591 $4,969 $28,766 $19,749 ======= ====== ======= =======
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 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. CASH EQUIVALENTS The Company includes highly liquid marketable securities and debt instruments purchased with a maturity of three months or less in cash equivalents. F. 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). G. STOCK-BASED COMPENSATION The Company currently reports stock-based employee compensation through the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation." Accordingly, no compensation expense has been recognized for its stock options. Had compensation cost for these options been determined in accordance with SFAS No. 123, the Company's net income and diluted earnings per share would have been as follows: 44
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Net income As reported $ 68,639 $ 3,658 $ 67,896 $ 53,018 Stock based compensation expense included in reported net income, net of tax 2,879 911 2,894 4,545 Stock based compensation expense determined under fair value based method, net of tax (3,472) (822) (3,142) (3,539) ---------- --------- ---------- ---------- Pro forma $ 68,046 $ 3,747 $ 67,648 $ 54,024 ---------- --------- ---------- ---------- Diluted earnings per average common share As reported $ 2.03 $ 0.12 $ 2.18 $ 1.75 Pro forma $ 2.01 $ 0.12 $ 2.18 $ 1.78 ---------- --------- ---------- ---------- Basic earnings per average common share As reported $ 2.04 $ 0.12 $ 2.21 $ 1.76 Pro forma $ 2.02 $ 0.12 $ 2.20 $ 1.79 ========== ========= ========== ==========
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 34.67 percent, 36.35 percent and 34.64 percent for the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000, respectively; a risk-free interest rate of 3.36 percent, 4.14 percent, and 5.76 percent for the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000, respectively; and a dividend yield of 3.12 percent, 2.55 percent and 3.53 percent on options without dividend equivalents for the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000, respectively. Options with dividend equivalents assume no dividend yield for all periods presented. The weighted-average grant-date fair value of options granted for the three-months ended December 31, 2001, was $9.74 for options granted with dividend equivalents and $6.52 for options granted without dividend equivalents; $12.66 for options granted with dividend equivalents and $9.27 for options granted without dividend equivalents during the year-ended September 30, 2001; and $5.91 for options granted without dividend equivalents in the year-ended September 30, 2000. There were no options granted in the year ended December 31, 2002. H. 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. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserves and the related present value of estimated future net revenues therefrom (see Note 19). 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. 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 Commission, following a generic rate of return hearing, adjusts the equity returns of all major energy utilities operating under a similar methodology. Under RSE as extended, 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. 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 45 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, 2002; as a result, the utility returned to customers $0.3 million pre-tax through rate adjustments under the provisions of RSE. A $12.4 million, $16.3 million and $9.1 million annual increase in revenues became effective December 1, 2002, 2001 and 2000, respectively, under RSE as extended. 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 to residential, small commercial and small industrial customers. 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 fiscal 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 September 30, 2001, Alagasco charged $1.2 million against the ESR related to extraordinary bad debt expense and revenue losses from certain large industrial customers. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR of no more than $40,000 monthly until the maximum funding level is achieved. The ESR balances of $3 million at December 31, 2002, and $2.7 million at December 31, 2001 and September 30, 2001, respectively, are included in the consolidated financial statements. At December 31, 2002, Alagasco had a $18.7 million accrued obligation related to its salaried and union pension plans. In accordance with SFAS No. 71, Alagasco has established a regulatory asset of $14.7 million for the portion of the accrued obligation to be recovered through rates in future periods. 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, 2002, December 31, 2001 and September 30, 2001, the net acquisition adjustments were $13.8 million, $12.1 million and $12.4 million, respectively. 3. LONG-TERM DEBT AND NOTES PAYABLE - ------------------------------------------------------------------------------- Long-term debt consisted of the following:
DECEMBER 31, December 31, September 30, (in thousands) 2002 2001 2001 ------------ ------------ ------------- Energen Corporation: Medium-term Notes, interest ranging from 6.81% to 8.09%, for notes redeemable September 15, 2003, to February 15, 2028 $353,000 $363,000 $363,000 Series 1993 Notes -- 8,881 8,881 Alabama Gas Corporation: Medium-term Notes, interest ranging from 6.25% to 7.97%, for notes redeemable September 15, 2003, to September 23, 2026 110,000 115,000 115,000 6.25% Notes, redeemable September 1, 2016 39,758 40,000 40,000 6.75% Notes, redeemable September 1, 2031 34,775 35,000 35,000 -------- -------- -------- Total 537,533 561,881 561,881 Less amounts due within one year 23,000 16,072 16,072 Less unamortized debt discount 1,579 1,676 1,699 -------- -------- -------- Total $512,954 $544,133 $544,110 ======== ======== ========
46 The aggregate maturities of Energen's long-term debt for the next five years are as follows:
Years ending December 31, (in thousands) - -------------------------------------------------------------------------- 2003 2004 2005 2006 2007 - ------- ------- ------- ------- ------ $23,000 $10,000 $10,000 $20,000 $7,000
The aggregate maturities of Alagasco's long-term debt for the next five years are as follows:
Years ending December 31, (in thousands) - ---------------------------------------------------------------------- 2003 2004 2005 2006 2007 - ------- --- ------- ------- ------ $15,000 $-- $10,000 $10,000 $7,000
At December 31, 2002, 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 agreed that it will not 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, 2002. All of the Company's debt is unsecured. Energen and Alagasco had short-term credit lines and other credit facilities of $267 million available as of December 31, 2002, for working capital needs; Alagasco has been authorized to borrow up to $70 million of the available credit lines by the APSC. The following is a summary of information relating to notes payable to banks:
DECEMBER 31, December 31, September 30, (in thousands) 2002 2001 2001 ------------ ------------ ------------- Energen outstanding $100,000 $ 5,000 $ 6,000 Alagasco outstanding 13,000 19,000 1,000 -------- -------- -------- Notes payable to banks 113,000 24,000 7,000 Available for borrowings 154,000 196,000 213,000 -------- -------- -------- Total $267,000 $220,000 $220,000 -------- -------- -------- Maximum amount outstanding at any month-end $113,000 $ 24,000 $177,000 Average daily amount outstanding $ 85,644 $ 16,717 $ 80,681 Weighted average interest rates based on: Average daily amount outstanding 2.28% 2.53% 6.05% Amount outstanding at year-end 1.88% 2.18% 2.97% -------- -------- -------- Alagasco maximum amount outstanding at any month-end $ 21,000 $ 19,000 $ 62,000 Alagasco average daily amount outstanding $ 3,304 $ 11,761 $ 40,066 Alagasco weighted average interest rates based on: Average daily amount outstanding 2.18% 2.47% 5.31% Amount outstanding at year-end 1.78% 2.16% 2.97% -------- -------- --------
Energen's total interest expense was $43,713,000 for the year ended December 31, 2002, $10,634,000 for the three months ended December 31, 2001 and $42,070,000 and $37,769,000 for the years ended September 31, 2001 and 2000, respectively. Total interest expense at Alagasco was $14,557,000 for the year ended December 31, 2002, $3,680,000 for the three months ended December 31, 2001 and $12,316,000 and $9,870,000 for the years ended September 30, 2001 and 2000, respectively, at Alagasco. 47 4. INCOME TAXES - ------------------------------------------------------------------------------- The components of Energen's income taxes consisted of the following:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Taxes estimated to be payable currently: Federal $ 7,370 $ 3,686 $ 8,601 $ 10,412 State 546 1,537 1,309 1,918 ------- ------- ------- -------- Total current 7,916 5,223 9,910 12,330 ------- ------- ------- -------- Taxes deferred: Federal 9,065 (7,211) 3,073 (6,027) State 3,528 (1,396) 1,828 179 ------- ------- ------- -------- Total deferred 12,593 (8,607) 4,901 (5,848) ------- ------- ------- -------- Total income tax expense (benefit) from continuing operations $20,509 $(3,384) $14,811 $ 6,482 ======= ======= ======= ========
In addition, Energen recorded income tax expense, related to income from discontinued operations, of $2,300,000 in current income tax expense and ($2,126,000) in deferred income tax expense for the year ended December 31, 2002, $59,000 in current income tax expense for the three months ended December 31, 2001, and $1,165,000 and $307,000 in current income tax expense for the years ended September 30, 2001 and 2000, respectively. The components of Alagasco's income taxes consisted of the following:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Taxes estimated to be payable currently: Federal $ 7,763 $ 9,167 $ 15,456 $ 15,225 State 1,001 1,181 1,539 1,486 ------- -------- -------- -------- Total current 8,764 10,348 16,995 16,711 ------- -------- -------- -------- Taxes deferred: Federal 7,974 (7,807) (3,193) (2,215) State 1,087 (994) (354) (172) ------- -------- -------- -------- Total deferred 9,061 (8,801) (3,547) (2,387) ------- -------- -------- -------- Total income tax expense from continuing operations $17,825 $ 1,547 $ 13,448 $ 14,324 ======= ======== ======== ========
Temporary differences and carryforwards which gave rise to a significant portion of Energen's and Alagasco's deferred tax assets and liabilities for 2002 and 2001 were as follows: 48
Energen Corporation (in thousands) DECEMBER 31, 2002 December 31, 2001 September 30, 2001 ---------------------- ---------------------- ---------------------- CURRENT NONCURRENT Current Noncurrent Current Noncurrent ------- ---------- ------- ---------- ------- ---------- Deferred tax assets: Minimum tax credit $ -- $64,756 $ -- $57,441 $ -- $56,043 Pension and other costs 5,326 7,056 7,165 -- 6,574 -- Unbilled revenue and other costs 9,082 -- 9,037 -- 1,942 -- Enhanced stability reserve 1,120 -- 1,022 -- 1,016 -- Allowance for doubtful accounts 3,316 -- 4,236 -- 3,631 -- Insurance and accruals 2,736 -- 2,402 -- 2,384 -- Other comprehensive income 5,980 3,053 -- -- -- -- Other, net 6,644 2,153 9,894 1,338 5,979 1,420 ------- ------- ------- ------- ------- ------- Total deferred tax assets 34,204 77,018 33,756 58,779 21,526 57,463 ------- ------- ------- ------- ------- ------- Deferred tax liabilities: Depreciation and basis differences -- 53,622 -- 49,217 -- 44,165 Minimum pension liability -- 7,056 -- -- -- -- Other comprehensive income -- -- 3,644 1,151 8,676 1,254 Other, net 263 7 476 5 425 5 ------- ------- ------- ------- ------- ------- Total deferred tax liabilities 263 60,685 4,120 50,373 9,101 45,424 ------- ------- ------- ------- ------- ------- Net deferred tax assets (liabilities) $33,941 $16,333 $29,636 $ 8,406 $12,425 $12,039 ======= ======= ======= ======= ======= =======
Alabama Gas Corporation (in thousands) DECEMBER 31, 2002 December 31, 2001 September 30, 2001 ---------------------- ---------------------- ---------------------- CURRENT NONCURRENT Current Noncurrent Current Noncurrent ------- ---------- ------- ---------- ------- ---------- Deferred tax assets: Enhanced stability reserve $ 1,120 $ -- $ 1,022 $ -- $ 1,016 $ -- Unbilled revenue and other costs 9,082 -- 9,037 -- 1,942 -- Insurance and accruals 3,418 -- 3,182 -- 2,817 -- Inventories 1,133 -- 1,022 -- 1,061 -- Allowance for doubtful accounts 3,100 -- 4,197 -- 3,592 -- Pension and other costs -- 7,056 2,675 -- 2,239 -- Other, net 2,721 791 1,931 444 2,058 526 ------- -------- ------- -------- ------- -------- Total deferred tax assets 20,574 7,847 23,066 444 14,725 526 ------- -------- ------- -------- ------- -------- Deferred tax liabilities: Depreciation and basis differences -- 21,538 -- 15,975 -- 16,351 Minimum pension liability -- 7,056 -- -- -- -- Other, net 481 -- 246 -- 248 -- ------- -------- ------- -------- ------- -------- Total deferred tax liabilities 481 28,594 246 15,975 248 16,351 ------- -------- ------- -------- ------- -------- Net deferred tax assets (liabilities) $20,093 $(20,747) $22,820 $(15,531) $14,477 $(15,825) ======= ======== ======= ======== ======= ========
The Company files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2002, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $64.8 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: 49
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Income tax expense from continuing operations at statutory federal income tax rate $ 31,883 $ 68 $ 28,314 $ 20,656 Increase (decrease) resulting from: Nonconventional fuels tax credits (14,165) (3,481) (13,588) (14,405) Enhanced oil recovery tax credits -- -- (25) (457) Deferred investment tax credits (448) (112) (448) (448) State income taxes, net of federal income tax benefit 2,465 28 1,754 1,421 Other, net 774 113 (1,196) (285) -------- ------- -------- -------- Total income tax expense (benefit) from continuing operations $ 20,509 $(3,384) $ 14,811 $ 6,482 -------- ------- -------- -------- Effective income tax rate (%) 22.51 -- 18.31 10.98 ======== ======= ======== ========
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:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Income tax expense from continuing operations at statutory federal income tax rate $ 15,886 $ 1,482 $ 13,812 $ 14,226 Increase (decrease) resulting from: Deferred investment tax credits (448) (112) (448) (448) State income taxes, net of federal income tax benefit 1,236 116 799 874 Other, net 1,151 61 (715) (328) -------- ------- -------- -------- Total income tax expense from continuing operations $ 17,825 $ 1,547 $ 13,448 $ 14,324 -------- ------- -------- -------- Effective income tax rate (%) 39.27 36.54 34.08 35.24 ======== ======= ======== ========
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. The Company's policy is to use the projected unit credit actuarial method for funding and financial reporting purposes. The status of the plans was as follows:
(in thousands) PLAN A -------------------------------------------------------------- SEPTEMBER 30, September 30, June 30, June 30, 2002 2001 2001 2000 ------------- ------------- -------- -------- Projected benefit obligation: Balance at beginning of period $ 92,101 $ 90,613 $ 71,694 $ 73,841 Service cost 3,074 899 2,219 1,988 Interest cost 6,173 1,643 5,458 5,573 Actuarial loss (gain) 6,093 (46) 16,478 (2,642) Benefits paid (6,042) (1,008) (5,236) (7,066) --------- -------- -------- -------- Balance at end of period 101,399 92,101 90,613 71,694 --------- -------- -------- --------
50 Plan assets: Fair value of plan assets at beginning of period 67,967 74,486 87,169 83,844 Actual return on plan assets (5,331) (5,510) (7,447) 10,391 Employer contributions 11,000 -- -- -- Benefits paid (6,042) (1,009) (5,236) (7,066) --------- -------- -------- -------- Fair value of plan assets at end of period 67,594 67,967 74,486 87,169 --------- -------- -------- -------- Amounts recognized in the consolidated balance sheets: Funded status of plan (33,805) (24,134) (16,127) 15,475 Unrecognized actuarial loss (gain) 30,565 12,996 6,001 (22,926) Unrecognized prior service cost 2,027 2,262 2,321 2,555 Unrecognized net transition obligation (asset) -- (196) (261) (1,069) --------- -------- -------- -------- Accrued pension asset (liability) $ (1,213) $ (9,072) $ (8,066) $ (5,965) ========= ======== ======== ========
(in thousands) PLAN B -------------------------------------------------------------- SEPTEMBER 30, September 30, June 30, June 30, 2002 2001 2001 2000 ------------- ------------- -------- -------- Projected benefit obligation: Balance at beginning of period $ 17,945 $ 17,949 $ 17,002 $ 18,227 Service cost 396 80 255 265 Interest cost 1,422 320 1,267 1,361 Plan amendment 1,781 -- -- -- Actuarial loss (gain) 1,912 58 1,345 (487) Benefits paid (1,468) (462) (1,920) (2,364) -------- -------- -------- -------- Balance at end of period 21,988 17,945 17,949 17,002 -------- -------- -------- -------- Plan assets: Fair value of plan assets at beginning of period 18,420 20,666 23,561 24,043 Actual return on plan assets (1,264) (1,784) (975) 1,882 Benefits paid (1,468) (462) (1,920) (2,364) -------- -------- -------- -------- Fair value of plan assets at end of period 15,688 18,420 20,666 23,561 -------- -------- -------- -------- Amounts recognized in the consolidated balance sheets: Funded status of plan (6,300) 475 2,717 6,559 Unrecognized actuarial loss (gain) 4,315 (481) (2,729) (6,458) Unrecognized prior service cost 2,295 869 928 1,163 Unrecognized net transition obligation (asset) -- 43 57 114 -------- -------- -------- -------- Accrued pension asset (liability) $ 310 $ 906 $ 973 $ 1,378 ======== ======== ======== ========
The components of net pension expense were:
(in thousands) PLAN A ------------------------------------------------------------ Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Components of net periodic benefit cost: Service cost $ 3,074 $ 899 $ 2,219 $ 1,988 Interest cost 6,173 1,643 5,458 5,573 Expected long-term return on assets (6,145) (1,537) (5,778) (5,566) Prior service cost amortization 235 59 235 235 Actuarial loss (gain) -- 2 422 -- Transition amortization (196) (65) (808) (808) ------- ------- ------- ------- Net periodic expense $ 3,141 $ 1,001 $ 1,748 $ 1,422 ======= ======= ======= =======
51
(in thousands) PLAN B ------------------------------------------------------------ Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Components of net periodic benefit cost: Service cost $ 396 $ 80 $ 255 $ 265 Interest cost 1,422 320 1,267 1,361 Expected long-term return on assets (1,619) (406) (1,466) (1,577) Prior service cost amortization 354 59 235 235 Actuarial loss (gain) -- -- (28) -- Transition amortization 43 14 57 57 ------- ----- ------- ------- Net periodic expense $ 596 $ 67 $ 320 $ 341 ======= ===== ======= =======
Net pension expense for Alagasco was $3,224,000 for the year ended December 31, 2002, $918,000 for the three-months ended December 31, 2001 and $1,812,000 and $1,466,000 for the years ended September 30, 2001 and 2000, respectively.
PLAN A --------------------------------------------------------- DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Weighted average rate assumptions in pension actuarial calculations: Discount rate 6.75% 7.50% 7.50% 8.00% Expected long-term return on plan assets 9.00% 9.00% 9.00% 8.25% Rate of compensation increase 4.50% 4.50% 4.50% 5.50%
PLAN B --------------------------------------------------------- DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Weighted average rate assumptions in pension actuarial calculations: Discount rate 6.75% 7.50% 7.50% 8.00% Expected long-term return on plan assets 9.00% 9.00% 9.00% 8.25%
Under SFAS No. 87, "Employers' Accounting for Pensions," Energen recorded a minimum pension liability for the accumulated benefit obligation in excess of plan assets at December 31, 2002, of $21.7 million. Alagasco established a regulatory asset of $14.7 million for the portion of this accrued 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 $4.3 million and the balance of $1.7 million was recorded as a component of accumulated other comprehensive income, net of tax. Subsequent to December 31, 2002, Energen contributed an additional $9 million to pension Plan A assets. The Company has supplemental retirement plans with certain key executives providing payments on retirement, termination, death or disability. Expense (income) under these agreements for the year ended December 31, 2002, the three months ended December 31, 2001 and the years ended September 30, 2001 and 2000 was $314,000, $(125,000), $381,000 and $372,000, respectively. At September 30, 2002 and 2001 and at June 30, 2001, the accumulated post-retirement benefit obligation related to these agreements was $10,093,000, $9,198,000 and $5,465,000, respectively, and the projected benefit obligation was $15,209,000, $14,082,000, and $10,750,000, respectively. An accrued post-retirement benefit liability of $5,860,000, $5,589,000 and $2,408,000 was recorded at December 31, 2002 and 2001 and September 30, 2001, respectively. The Company recorded a minimum pension liability for supplemental retirement plans of $4.2 million at December 31, 2002. A corresponding amount was recognized as an intangible asset for the unrecognized prior service cost of $81,000 and the balance was recorded as a component of accumulated other comprehensive income, net of tax, of $2.6 million. In addition to providing pension benefits, the Company provides certain post-retirement health care and life 52 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. The status of the post-retirement benefit programs was as follows:
(in thousands) SALARIED EMPLOYEES ------------------------------------------------------------- SEPTEMBER 30, September 30, June 30, June 30, 2002 2001 2001 2000 ------------- ------------- -------- -------- Projected post-retirement benefit obligation: Balance at beginning of period $ 35,888 $ 36,518 $ 29,811 $ 29,144 Service cost 831 261 1,095 1,092 Interest cost 2,120 649 2,327 2,203 Actuarial loss (gain) (6,264) (1,274) 4,964 (1,146) Benefits paid (1,567) (266) (1,679) (1,482) -------- -------- -------- -------- Balance at end of period 31,008 35,888 36,518 29,811 -------- -------- -------- -------- Plan assets: Fair value of plan assets at beginning of period 30,921 36,142 41,004 35,494 Actual return on plan assets (7,073) (5,184) (4,520) 4,186 Company contribution 1,846 229 1,337 2,806 Benefits paid (1,567) (266) (1,679) (1,482) -------- -------- -------- -------- Fair value of plan assets at end of period 24,127 30,921 36,142 41,004 -------- -------- -------- -------- Amounts recognized in the consolidated balance sheets: Funded status of plan (6,881) (4,967) (376) 11,193 Unrecognized actuarial loss (gain) (1,259) (4,035) (8,667) (19,435) Unrecognized net transition obligation (asset) 7,809 8,491 8,672 9,395 Company contribution 265 410 369 -- -------- -------- -------- -------- Accrued pension asset (liability) $ (66) $ (101) $ (2) $ 1,153 ======== ======== ======== ========
(in thousands) UNION EMPLOYEES ------------------------------------------------------------- SEPTEMBER 30, September 30, June 30, June 30, 2002 2001 2001 2000 ------------- ------------- -------- -------- Projected post-retirement benefit obligation: Balance at beginning of period $ 40,077 $ 40,986 $ 39,291 $ 37,423 Service cost 807 218 733 1,876 Interest cost 2,800 727 3,095 2,852 Plan amendment 248 -- -- -- Actuarial loss (gain) (11,282) (1,450) 124 (1,635) Benefits paid (2,041) (404) (2,257) (1,225) -------- -------- -------- -------- Balance at end of period 30,609 40,077 40,986 39,291 -------- -------- -------- -------- Plan assets: Fair value of plan assets at beginning of period 27,954 31,917 35,410 26,702 Actual return on plan assets (4,159) (4,628) (5,749) 3,928 Company contribution 2,141 1,069 4,513 6,005 Benefits paid (2,041) (404) (2,257) (1,225) -------- -------- -------- -------- Fair value of plan assets at end of period 23,895 27,954 31,917 35,410 -------- -------- -------- -------- Amounts recognized in the consolidated balance sheets: Funded status of plan (6,714) (12,123) (9,069) (3,881) Unrecognized actuarial loss (gain) (7,869) (3,314) (7,269) (11,274) Unrecognized prior service costs 237 -- -- -- Unrecognized net transition obligation (asset) 13,811 15,096 15,417 16,702 Company contribution 392 494 1,069 -- -------- -------- -------- -------- Accrued pension asset (liability) $ (143) $ 153 $ 148 $ 1,547 ======== ======== ======== ========
53 Net periodic post-retirement benefit expense included the following:
(in thousands) SALARIED EMPLOYEES --------------------------------------------------------------- Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Components of net periodic benefit cost: Service cost $ 831 $ 261 $ 1,095 $ 1,092 Interest cost 2,120 649 2,327 2,203 Expected long-term return on assets (1,678) (490) (1,994) (1,721) Actuarial loss (gain) (434) (111) (1,098) (1,029) Transition amortization 682 181 723 723 ------- ----- ------- ------- Net periodic expense $ 1,521 $ 490 $ 1,053 $ 1,268 ======= ===== ======= =======
(in thousands) UNION EMPLOYEES --------------------------------------------------------------- Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Components of net periodic benefit cost: Service cost $ 807 $ 218 $ 733 $ 1,876 Interest cost 2,800 727 3,095 2,852 Expected long-term return on assets (2,472) (720) (1,723) (1,292) Actuarial loss (gain) (93) (57) (336) (271) Prior service cost 12 -- -- -- Transition amortization 1,285 321 1,285 1,285 ------- ----- ------- ------- Net periodic expense $ 2,339 $ 489 $ 3,054 $ 4,450 ======= ===== ======= =======
Net periodic post-retirement benefit expense for Alagasco was $3,493,000 for the year ended December 31, 2002, $905,000 for the three months ended December 31, 2001 and $3,959,000 and $5,449,000 for the years ended September 30, 2001 and 2000, respectively.
SALARIED EMPLOYEES ------------------------------------------------------------ DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Weighted average rate assumptions in pension actuarial calculations: Discount rate 6.75% 7.50% 7.50% 8.00% Expected long-term return on plan assets 9.00% 9.00% 9.00% 8.25% Rate of compensation increase 4.50% 4.50% 4.50% 5.50% Health care cost trend rate GRADED RATE 7.50% 7.50% 7.50%
UNION EMPLOYEES ------------------------------------------------------------ DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Weighted average rate assumptions in pension actuarial calculations: Discount rate 6.75% 7.50% 7.50% 8.00% Expected long-term return on plan assets 9.00% 9.00% 9.00% 8.25% Health care cost trend rate GRADED RATE 7.50% 7.50% 7.50%
The weighted average health care cost trend rate at December 31, 2002 for both salaried and union employees is a 10% graduated rate down to 6% per year for employees under age 65 and a 12% graduated rate down to 6% per year for employees at or above age 65. This rate used in determining the accumulated post-retirement benefit obligation has an effect on the amounts reported. For example, with respect to salaried employees, increasing the 54 weighted average health care cost trend rate by 1 percentage point would increase the accumulated post-retirement benefit obligation by $2,708,000 and the net periodic post-retirement benefit cost by $283,000. For union employees, increasing the weighted average health care cost trend rate by 1 percentage point would increase the accumulated post-retirement benefit obligation by $2,152,000 and the net periodic post-retirement benefit cost by $213,000. 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 has a long-term disability plan covering most salaried employees. The Company had expense for the year ended December 31, 2002 of $304,000. The Company had no expense for this plan in the three-months ended December 31, 2001 and in the years ended September 30, 2001 and 2000. 6. COMMON STOCK PLANS - ------------------------------------------------------------------------------- A majority of Company employees are eligible to participate in the Energen Employee Savings Plan (ESP) by investing a portion of their compensation in the ESP, with the Company matching a part of the employee investment by contributing Company common stock (new issue or treasury shares) or funds for the purchase of Company common stock. The ESP also contains employee stock ownership plan provisions. At December 31, 2002, a total of 148,594 common shares were reserved for issuance under the ESP. Expense associated with Company contributions to the ESP was $3,963,000 for the year ended December 31, 2002, $803,000 for the three months ended December 31, 2001, and $3,597,000 and $3,381,000 for the years ended September 30, 2001 and 2000, respectively. In 1992 the Company adopted the Energen Corporation 1992 Long-Range Performance Plan which provides 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 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; accordingly, 700,000 shares have been reserved for issuance. Under the Plan, 76,120 and 102,860 performance units were awarded in the years ended September 30, 2001 and 2000, respectively. According to the provisions of the Plan, no additional performance units can be awarded after September 30, 2001. In October 2001, the Company added provisions for the award of future performance units, comparable to the 1992 Long-Range Performance Plan, under the 1997 Stock Incentive Plan. Under the 1997 Stock Incentive Plan, 111,760 performance units were awarded in the three months ended December 31, 2001. The Company recorded expense of $2,136,250 for the year ended December 31, 2002, $722,500 for the three months ended December 31, 2001, and $2,311,000 and $4,448,000 for the years ended September 30, 2001 and 2000, respectively, under the Plans. On November 27, 1997, the Company adopted the Energen Corporation 1997 Stock Incentive Plan. 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 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 22,775 shares awarded in the three-months ended December 31, 2001 and 57,190 and 12,500 shares awarded in the years ended September 30, 2001 and 2000, respectively. The sale or transfer of the shares is limited during the restricted period. The Company recorded expense of $742,875 for the year ended December 31, 2002, $188,000 for the three-months ended December 31, 2001 and $583,000 and $97,000 for the years ended September 30, 2001 and 2000, respectively, related to the restricted stock. Under the 1988 Stock Option Plan, 540,000 shares of Company common stock reserved for issuance have been granted. Under the 1997 Stock Incentive Plan, an additional 1,500,000 shares of Company common stock were reserved for issuance during 2002 resulting in total shares reserved for issuance of 2,800,000. 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: 55
1997 STOCK INCENTIVE PLAN 1988 STOCK OPTION PLAN ------------------------------ ---------------------------- Weighted Average Weighted Average Shares Exercise Price Shares Exercise Price --------- ---------------- -------- ---------------- Outstanding at September 30, 1999 335,270 $ 18.25 422,076 $12.29 Granted 108,500 18.8125 -- -- Exercised (40,262) 18.25 (157,660) 9.65 --------- -------- -------- ------ Outstanding at September 30, 2000 403,508 18.40 264,416 13.86 Granted 137,200 27.44 -- -- Exercised (152,786) 18.30 (105,302) 13.90 --------- -------- -------- ------ Outstanding at September 30, 2001 387,922 21.64 159,114 13.84 --------- -------- -------- ------ Granted 120,340 22.63 -- -- Exercised -- -- (1,000) 18.25 --------- -------- -------- ------ Outstanding at December 31, 2001 508,262 21.87 158,114 13.81 --------- -------- -------- ------ Granted -- -- -- -- 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 --------- -------- -------- ------ Exercisable at September 30, 2000 158,488 $ 18.25 237,836 $13.37 Exercisable at September 30, 2001 138,068 $ 18.34 159,114 $13.84 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 --------- -------- -------- ------ Remaining reserved for issuance at December 31, 2002 1,911,541 -- -- -- --------- -------- -------- ------
The following table summarizes information about options outstanding as of December 31, 2002:
1997 STOCK INCENTIVE PLAN 1988 STOCK OPTION PLAN - --------------------------------------------------------- ----------------------------------------------------- Weighted Average Weighted Average Range of Exercise Remaining Contractual Range of Remaining Contractual Prices Shares Life Exercise Prices Shares Life - ----------------- ------- --------------------- --------------- ------- -------------------- $18.25-$18.81 230,343 5.80 years $10.06-$11.06 41,000 2.40 years $27.44 136,300 7.83 years $15.00-$18.25 94,514 4.57 years $22.63 118,850 8.83 years -- - -- ------------- ------- ---- ------------- ------- ---- $18.25-$27.44 485,493 7.11 years $10.06-$18.25 135,514 3.91 years ============= ======= ==== ============= ======= ====
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, no shares were awarded during the year ended December 31, 2002, 6,000 shares were awarded during the three-months ended December 31, 2001 and 4,800 and 5,054 shares were awarded during the years ended September 30, 2001 and 2000, respectively, leaving 144,639 shares reserved for issuance as of December 31, 2002. In 1996 the Company amended its Dividend Reinvestment and Common Stock Purchase Plan to include a direct stock purchase feature which allows purchases by non-shareholders. In connection with the amendment, 1,500,000 shares were added to the Plan. As of December 31, 2002, 843,218 common shares were reserved under this Plan. On April 26, 2000, the Company authorized the repurchase of up to 1,000,000 shares of the Company's common stock, in addition to the 500,000 shares authorized on May 25, 1994. For the year ended December 31, 2002 the Company repurchased 5,319 shares, for the three-months ended December 31, 2001 the Company repurchased 55,074 shares, and for the years ended September 30, 2001 and 2000 the Company repurchased 91,600 and 290,000 shares, respectively. As of December 31, 2002, a total of 787,718 shares remain authorized for future repurchase. On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan) designed to protect 56 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, 2002, were convertible into 347,454 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 adjustment 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 trusts' assets remain subject to the claims of our creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the Consolidated Statements of Shareholders' Equity. 7. COMMITMENTS AND CONTINGENCIES - ------------------------------------------------------------------------------- CONTRACTS AND AGREEMENTS: Alagasco has various firm gas supply and firm gas transportation contracts which expire at various dates through the year 2010. These contracts typically contain minimum demand charge obligations on the part of Alagasco. ENVIRONMENTAL MATTERS: The Company is subject to various environmental regulations. Management believes that the Company is in compliance with the currently applicable standards of the environmental agencies to which it is subject and that potential environmental liabilities are minimal. Alagasco is in the chain of title of eight former manufactured gas plant sites, of which it still owns four, and five manufactured gas distribution sites, of which it still owns one. 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 operations or financial condition of Alagasco. Also, to the extent Energen Resources has operating agreements with various joint venture partners, environmental costs would be shared proportionately. To date, the Company's expenditures to comply with environmental or safety regulations have not been material and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs. 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 legal proceedings arising in the normal course of business are in progress currently, and the Company has accrued a provision for estimated costs. 57 LEASE OBLIGATIONS: In January 1999 Alagasco closed on a sale-leaseback of the Company's headquarters building. The proceeds from the sale approximated the investment in the facility. The building is being leased back from the purchaser over a 25-year lease term and the related lease is accounted for as an operating lease. Under the terms of the lease, Energen 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, inclusive of the sale-leaseback, were $8,273,000 for the year ended December 31, 2002, $1,837,000 for the three-months ended December 31, 2001, $7,324,000 and $6,267,000 for the years ended September 30, 2001 and 2000, respectively. Minimum future rental payments required after 2002 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
Years Ending December 31, (in thousands) - ----------------------------------------------------------------------------------------------------- 2003 2004 2005 2006 2007 2008 AND THEREAFTER - ------ ------ ------ ------ ------ ------------------- $3,609 $3,007 $2,770 $2,690 $2,412 $31,395
Alagasco's total payments related to leases included as operating expense, inclusive of the sale-leaseback, were $2,362,000 for the year ended December 31, 2002, $587,000 for the three-months ended December 31, 2001 $2,343,000 and $2,209,000 for the years ended September 30, 2001 and 2000, respectively. Minimum future rental payments required after 2002 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
Years Ending December 31, (in thousands) - ----------------------------------------------------------------------------------------------------- 2003 2004 2005 2006 2007 2008 AND THEREAFTER - ------ ------ ------ ------ ------ ------------------- $2,150 $1,590 $1,512 $1,504 $1,494 $22,251
8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - ------------------------------------------------------------------------------- FINANCIAL INSTRUMENTS: The fair 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 fixed-rate long-term debt, including the current portion, with a carrying value of $537,533,000, would be $570,243,000 at December 31, 2002. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, with a carrying value of $184,533,000, would be $200,410,000 at December 31, 2002. The fair values were based on the market value of debt with similar maturities and current interest rates. Alagasco entered into an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $20 million. Alagasco sold installment receivables of $5,010,000 in the year ended December 31, 2002, $2,120,000 in the three-months ended December 31, 2001 and $5,444,000 and $6,879,000 in the years ended September 30, 2001 and 2000, respectively. At December 31, 2002 the balance of these installment receivables was $10,566,000 and represented 13,812 accounts. At December 31, 2001 and September 30, 2001, the balance of these installment receivables was $12,838,000 and $13,249,000, respectively. Receivables sold under this agreement are 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. PRICE RISK: The Company adopted SFAS No. 133 (subsequently amended by SFAS Nos. 137 and 138) 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 when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in earnings in the period of change. 58 Energen Resources periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments 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 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 Company's 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 write-down 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 as originally forecasted to occur. As a result, Energen's net income in the three-month transition period ended December 31, 2001, reflected a one-time, non-cash expense of $5.5 million, net of tax. Net income in the year ended December 31, 2002, reflected a total non-cash benefit of $5.7 million, net of tax, related to the Enron hedge position. The Company had current losses on the fair value of derivatives of $15.9 million included in accounts payable and $1.9 million of non-current losses included in deferred credits and other liabilities on the consolidated balance sheet at December 31, 2002. At December 31, 2001 and September 30, 2001, the Company had current gains on the fair value of derivatives of $3.6 million and $22.5 million, respectively, included in prepayments and other and $3 million and $3.2 million, respectively, of non-current gains included in deferred charges and other. As of December 31, 2002, $9.4 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to earnings during the next twelve-month period. 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 $0.8 million after-tax loss in 2002 for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, Energen Resources recorded an after-tax gain of $151,000 in 2002 on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of December 31, 2002, all of the Company's swaps and hedges met the definition of a cash flow hedge. Subsequent to December 31, 2002, the Company entered into a hedge contract for 150 MBbl of oil that did not meet the definition of a cash flow hedge. The contract is considered by management to be an economic hedge and is accounted for as a mark-to-market transaction. The Company had $6.7 million included in current and noncurrent deferred income taxes on the consolidated balance sheet related to other comprehensive income as of December 31, 2002. Energen Resources entered into the following contracts and swaps:
AVERAGE CONTRACT PRODUCTION PERIOD TOTAL HEDGED VOLUME PRICE DESCRIPTION - ----------------- ------------------- ----------------- --------------------- NATURAL GAS - --------------------------------------------------------------------------------------------- 2003 30.9 Bcf $4.13 Mcf NYMEX Swaps 4.4 Bcf $3.86 Mcf Basin Specific Swaps 4.8 Bcf $3.72 - $4.70 Mcf Basin Specific Collars 2004 6.5 Bcf $4.02 Mcf NYMEX Swaps * 2.4 Bcf $4.42 Mcf NYMEX Swaps * 13.9 Bcf $3.83 Mcf Basin Specific Swaps 2.4 Bcf $4.05 - $4.44 Mcf NYMEX Collars 2005 1.2 Bcf $3.75 Mcf NYMEX Swaps
59
NATURAL GAS BASIS DIFFERENTIAL - --------------------------------------------------------------------------------------------- 2003 11.7 Bcf ** Basis Swaps * 4.0 Bcf ** Basis Swaps OIL - --------------------------------------------------------------------------------------------- 2003 2,478 MBbl $26.26 Bbl NYMEX Swaps * 150 MBbl $28.00 Bbl NYMEX Puts 2004 * 120 MBbl $26.15 Bbl NYMEX Swaps OIL BASIS DIFFERENTIAL - --------------------------------------------------------------------------------------------- 2003 2,174 MBbl ** Basis Swaps * 97 MBbl ** Basis Swaps NATURAL GAS LIQUIDS - --------------------------------------------------------------------------------------------- 2003 38 MMGal $0.42 Gal Liquids Swaps 2004 * 30 MMGal $0.41 Gal Liquids Swaps
* Contract entered into subsequent to December 31, 2002. ** Basis 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 Resources has hedged exposures to the variability of cash flows is through September 30, 2005. On December 4, 2000, the APSC authorized Alagasco to engage in energy risk-management activities to manage the utility's cost of gas supply. As of December 31, 2002, Alagasco had recorded a $16,750,000 receivable in prepayments and other representing the fair value of derivatives. 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 GSA in accordance with Alagasco's APSC approved tariff. 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 during the month following the month of 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. During 2001 and 2002, the credit rating agencies downgraded the credit ratings of a number of energy marketers and their affiliates, including certain oil and gas purchasers of the Company. The Company is monitoring this situation 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 buy approximately 23%, 12% and 11%, respectively, of Energen Resources' estimated 2003 production. Energen Resources' other purchasers each buy less than 10% of production. Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 465,000 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. 60 9. RECONCILIATION OF EARNINGS PER SHARE - -------------------------------------------------------------------------------
YEAR ENDED Three Months Ended (in thousands, except per share amounts) DECEMBER 31, 2002 December 31, 2001 --------------------------------- --------------------------------- PER SHARE Per Share INCOME SHARES AMOUNT Income Shares Amount ------- ------ --------- ------ ------ --------- Basic EPS $68,639 33,605 $2.04 $3,658 31,052 $0.12 Effect of dilutive securities Long-range performance shares 88 96 Stock options 143 127 Restricted stock 2 2 ------- ------ ----- ------ ------ ----- Diluted EPS $68,639 33,838 $2.03 $3,658 31,277 $0.12 ======= ====== ===== ====== ====== =====
Year Ended Year Ended (in thousands, except per share amounts) September 30, 2001 September 30, 2000 ---------------------------------- --------------------------------- Per Share Per Share Income Shares Amount Income Shares Amount ------- ------ --------- ------- ------ --------- Basic EPS $67,896 30,726 $2.21 $53,018 30,108 $1.76 Effect of dilutive securities Long-range performance shares 165 126 Stock options 187 125 Restricted stock 6 -- ------- ------ ----- ------- ------ ----- Diluted EPS $67,896 31,084 $ 2.18 $53,018 30,359 $1.75 ======= ====== ====== ======= ====== =====
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 antidilutive. 10. ASSET RETIREMENT OBLIGATIONS - ------------------------------------------------------------------------------- The Company has 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 was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset as of January 1, 2002. Upon initial application of the Statement, a cumulative effect of a change in accounting principle was also required in order to recognize a liability for any 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. 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 in resulting gain or loss. Energen Resources recorded a liability 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 ========
For the year ended December 31, 2002, Energen Resources recognized additional costs of $20.1 million, depreciation expense of $1.7 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. 61 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 will be operated in perpetuity and historical abandonment costs resulting from such easement agreements have been de minimis, no asset retirement obligation has been recorded. 11. SUPPLEMENTAL CASH FLOW INFORMATION - ------------------------------------------------------------------------------- Supplemental information concerning Energen's cash flow activities is as follows:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------ Interest paid, net of amount capitalized $43,085 $11,418 $42,905 $37,717 Income taxes paid $ 9,838 $ 4,261 $11,636 $11,885 Noncash investing activities: First Permian, L.L.C. stock issuance $72,891 $ -- $ -- $ -- Capitalized depreciation $ 223 $ 51 $ 243 $ 217 Allowance for funds used during construction $ 1,336 $ 122 $ 2,098 $ 1,172 ------- ------- ------- -------
Under SFAS No. 143, the Company recorded additional 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, all of which are non-cash adjustments concerning Energen's cash flow activities for the year ended December 31, 2002. Supplemental information concerning Alagasco's cash flow activities is as follows:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Interest paid, net of amount capitalized $14,012 $5,666 $12,154 $ 9,787 Income taxes paid $15,519 $9,425 $18,318 $15,833 Noncash investing activities: Capitalized depreciation $ 223 $ 51 $ 243 $ 217 Allowance for funds used during construction $ 1,336 $ 122 $ 2,098 $ 1,172 ------- ------ ------- -------
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." This statement 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 flow of the asset. In addition, SFAS No. 144 requires that gains and losses in the sale of certain oil and gas properties and write-downs 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. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. Accordingly, during the second quarter of 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 year ended December 31, 2002, included a total of $3.7 million largely due to sales of property located in the Permian Basin. As of December 31, 2002, the Company had no properties classified as held-for-sale. 62 In 2001 and 2000, a pre-tax gain of $0.8 million and $1.1 million, respectively, was recorded in operating revenues from continuing operations for certain non-strategic property sales. In the third fiscal quarter of 2000, as a result of a downward reserve revision in a small oil and gas field, Energen Resources recorded a pre-tax write-down of $3.5 million in additional depreciation, depletion and amortization expense, adjusting the carrying amount of the properties to their fair value based on expected future discounted cash flows. The following are the results of operations from discontinued operations:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands, except per share data) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Oil and gas revenues $ 1,744 $1,164 $7,599 $4,186 ------- ------ ------ ------ Pretax income (loss) from discontinued operations $ (438) $ 138 $2,974 $ 790 Income tax expense (benefit) (171) 59 1,165 307 ------- ------ ------ ------ INCOME (LOSS) FROM DISCONTINUED OPERATIONS (267) 79 1,809 483 ------- ------ ------ ------ Impairment charge on held-for-sale property (2,815) -- -- -- (Loss) gain on disposal 3,700 -- -- -- Income tax expense (benefit) 345 -- -- -- ------- ------ ------ ------ GAIN ON DISPOSAL 540 -- -- -- ------- ------ ------ ------ TOTAL INCOME (LOSS) FROM DISCONTINUED OPERATIONS $ 273 $ 79 $1,809 $ 483 ======= ====== ====== ====== DILUTED EARNINGS PER AVERAGE COMMON SHARE Income (Loss) from Discontinued Operations $ (0.01) $ -- $ 0.05 $ 0.02 Gain on Disposal 0.02 -- -- -- ------- ------ ------ ------ Total Income from Discontinued Operations $ 0.01 $ -- $ 0.05 $ 0.02 ======= ====== ====== ====== BASIC EARNINGS PER AVERAGE COMMON SHARE Income (Loss ) from Discontinued Operations $ (0.01) $ -- $ 0.05 $ 0.02 Gain on Disposal 0.02 -- -- -- ------- ------ ------ ------ Total Income from Discontinued Operations $ 0.01 $ -- $ 0.05 $ 0.02 ======= ====== ====== ======
13. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) - ------------------------------------------------------------------------------- The following data summarizes quarterly operating results. The Company's business is seasonal in character and strongly influenced by weather conditions.
Year Ended December 31, 2002 -------------------------------------------------------------------- (in thousands, except per share amounts) First Second Third Fourth ----------- ----------- ----------- ----------- Operating revenues $ 244,383 $ 138,464 $ 116,952 $ 177,376 Operating income $ 61,022 $ 25,721 $ 13,187 $ 36,156 Income from continuing operations before cumulative effect of change in accounting principle $ 39,038 $ 12,611 $ 124 $ 18,813 Net income $ 36,682 $ 12,744 $ 127 $ 19,086 Diluted earnings per average common share Continuing operations $ 1.24 $ 0.37 $ 0.00 $ 0.54 Net income $ 1.17 $ 0.37 $ 0.00 $ 0.55 Basic earnings per average common share Continuing operations $ 1.25 $ 0.37 $ 0.00 $ 0.54 Net income $ 1.18 $ 0.37 $ 0.00 $ 0.55 ----------- ----------- ----------- -----------
63
Year Ended September 30, 2001 -------------------------------------------------------------------- (in thousands, except per share amounts) First Second Third Fourth ----------- ----------- ----------- ----------- Operating revenues $ 173,988 $ 331,440 $ 159,894 $ 112,052 Operating income $ 26,725 $ 67,931 $ 22,740 $ 3,639 Income (loss) from continuing operations before cumulative effect of change in accounting principle $ 13,115 $ 46,503 $ 10,013 $ (3,555) Net income (loss) $ 13,719 $ 46,992 $ 10,373 $ (3,188) Diluted earnings (loss) per average common share Continuing operations $ 0.42 $ 1.50 $ 0.32 $ (0.11) Net income (loss) $ 0.44 $ 1.52 $ 0.33 $ (0.10) Basic earnings (loss) per average common share Continuing operations $ 0.43 $ 1.52 $ 0.32 $ (0.11) Net income (loss) $ 0.45 $ 1.53 $ 0.34 $ (0.10) ----------- ----------- ----------- -----------
The summarized quarterly information above has been revised to reflect the adoption of SFAS No. 143, (see Note 10) and SFAS No. 144, (see Note 12) as of January 1, 2002. The following data summarizes quarterly operating results. Alagasco's business is seasonal in character and strongly influenced by weather conditions.
Year Ended December 31, 2002 -------------------------------------------------------------- (in thousands, except per share amounts) First Second Third Fourth -------- ------- -------- -------- Operating revenues $196,524 $75,709 $ 50,225 $101,973 Operating income (loss) $ 52,811 $ 4,721 $ (8,907) $ 10,745 Net income (loss) $ 30,542 $ 964 $ (7,700) $ 3,758 -------- ------- -------- --------
Year Ended September 30, 2001 -------------------------------------------------------------- (in thousands, except per share amounts) First Second Third Fourth -------- ------- -------- -------- Operating revenues $119,126 $270,286 $103,779 $ 60,671 Operating income (loss) $ 6,498 $ 30,176 $ 3,186 $ (3,020) Net income (loss) $ 4,040 $ 27,333 $ 578 $ (5,936) -------- ------- -------- --------
14. ACQUISITION OF OIL AND GAS PROPERTIES - ------------------------------------------------------------------------------- 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; this estimate reflects an effective date of January 1, 2002, with appropriate purchase price adjustments from that date forward until completion of the transaction, resulting from interim cash flows and related tax items. Summarized below are the consolidated results of operations for the year ended December 31, 2002, the three months ended December 31, 2001 and the year ended September 30, 2001, on an unaudited pro forma basis as if the acquisition had occurred at the beginning of each period presented. The pro form information is based on our consolidated results of operations for the year ended December 31, 2002, the three months ended December 31, 2001 and the year ended September 30, 2001, and on the data provided by the acquired companies, after giving effect to the issuance of 3,043,479 million 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. 64
Three Months YEAR ENDED Ended Year Ended Unaudited DECEMBER 31, December 31, September 30, (in thousands, except per share amounts) 2002 2001 2001 ------------ ------------ ------------- Operating revenues $683,780 $153,938 $802,187 Net income $ 69,772 $ 4,387 $ 66,562 Diluted earnings per average common share $ 2.06 $ 0.14 $ 2.14 Basic earnings per average common share $ 2.08 $ 0.14 $ 2.17 ======== ======== ========
15. REGULATORY ASSETS AND LIABILITES The following table details regulatory asset and liabilities amounts on the consolidated balance sheets:
DECEMBER 31, 2002 December 31, 2001 September 30, 2001 Energen Corporation -------------------------- ------------------------ -------------------- (in thousands) CURRENT NONCURRENT Current Noncurrent Current Noncurrent ------- ---------- ------- ---------- ------- ---------- Regulatory assets: Pension asset $ -- $14,744 $ -- $ -- $ -- $ -- Early retirement costs -- -- -- -- 95 -- ------- ------- ------ ---- ------ ---- Total regulatory assets $ -- $14,744 $ -- $ -- $ 95 $ -- ======= ======= ====== ==== ====== ==== Regulatory liabilities: Enhanced stability reserve $ 2,963 $ -- $2,702 $ -- $2,686 $ -- Gas supply adjustment 20,851 -- 5,760 -- 1,106 -- Deferred income taxes -- 1,468 -- 137 -- 242 ------- ------- ------ ---- ------ ---- Total regulatory liabilities $23,814 $ 1,468 $8,462 $137 $3,792 $242 ======= ======= ====== ==== ====== ====
16. TRANSACTIONS WITH RELATED PARTIES Alagasco purchased natural gas from affiliates amounting to $1,820,000 for the year ended December 31, 2002, $375,000 for the three-months ended December 31, 2001, $5,254,000 and $3,662,000, for the years ended September 30, 2001 and 2000, respectively. These amounts are included in gas purchased for resale. Alagasco had net payables to affiliates of $1,432,000 and $3,054,000 at December 31, 2002 and December 31, 2001, net receivables from affiliates of $937,000 at September 30, 2001 and net payables to affiliates of $1,156,000 at September 30, 2000. 17. OTHER INCOME AND EXPENSE The following table details Energen's other income and expense amounts on the consolidated income statements:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Allowance for funds used during construction $ 1,336 $ 122 $ 2,098 $ 1,172 Merchandise revenues 14,155 4,226 14,535 15,885 Other 153 6 192 258 ------- ------ ------- ------- Total other income $15,644 $4,354 $16,825 $17,315 ======= ====== ======= ======= Cost of goods sold $10,215 $3,181 $10,136 $10,777 Other merchandise expense 4,888 1,204 4,756 4,763 ------- ------ ------- ------- Total other expense $15,103 $4,385 $14,892 $15,540 ======= ====== ======= =======
65 The following table details Alagasco's other income and expense amounts on the income statements:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Merchandise revenues $5,520 $1,596 $5,978 $7,520 ------ ------ ------ ------ Total other income $5,520 $1,596 $5,978 $7,520 ====== ====== ====== ====== Cost of goods sold $2,702 $ 946 $3,051 $3,564 Other merchandise expense 3,578 892 3,534 3,675 ------ ------ ------ ------ Total other expense $6,280 $1,838 $6,585 $7,239 ====== ====== ====== ======
18. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB) In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company adopted this statement as of January 1, 2002 (See Note 10). The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" in June 2002. This statement requires that a liability for costs associated with exit or disposal activities be recognized at fair value in the period the liability is incurred. This Statement does not apply to costs associated with the retirement of long-lived assets covered by SFAS No. 143. The Company has adopted this statement for disposal or exit activities initiated after December 31, 2002. The FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure" in December 2002. This statement is effective for 2003 and amends SFAS No. 123, "Accounting for Stock-Based Compensation" by providing alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 requires additional disclosures related to the effect of stock-based compensation on reported results. The Company has adopted the disclosure provisions of SFAS No. 148 and is currently reviewing its treatment of stock-based compensation as well as the impact of this pronouncement. The FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosures Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," (FIN 45) in November 2002. FIN 45 clarifies the requirements of SFAS No. 5, "Accounting for Contingencies," related to a guarantors accounting for, and disclosures of, the issuance of certain types of guarantees. Management has completed a review of potential contingencies and noted the following guarantee disclosure: Alagasco has an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $20 million. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables (see Note 8). The Company is required to adopt the provisions for initial recognition and measurement for all guarantees issued or modified after December 31, 2002 on a prospective basis. The Company is currently reviewing the impact related to the initial recognition and measurement guarantees of this Interpretation. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46) which clarifies the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements." This Interpretation provides guidance on the identification and consolidation of variable interest entities (VIEs), whereby control is achieved through means other than through voting rights. Management has completed an analysis of FIN 46 and has determined that the Company does not have VIEs. 66 19. OIL AND GAS OPERATIONS (UNAUDITED) The following schedules detail historical financial data of the Company's oil and gas operations. Certain terms appearing in the schedules are prescribed by the Securities and Exchange Commission (SEC) and 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
DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Proved $1,091,536 $841,155 $818,535 $707,236 Unproved 11,936 3,807 4,421 6,530 ---------- -------- -------- -------- Total capitalized costs 1,103,472 844,962 822,956 713,766 Accumulated depreciation, depletion, and amortization 269,616 228,867 209,451 165,447 ---------- -------- -------- -------- Capitalized costs, net $ 833,856 $616,095 $613,505 $548,319 ========== ======== ======== ========
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:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Property acquisition: Proved $173,984 $ 238 $ 33,764 $ 2,086 Unproved 10,193 81 552 350 Exploration 527 339 1,734 1,472 Development 122,494 24,757 103,574 66,717 -------- ------- -------- ------- Total costs incurred $307,198 $25,415 $139,624 $70,625 ======== ======= ======== =======
67 RESULTS OF CONTINUING OPERATIONS: The following table sets forth results of the Company's oil and gas continuing operations:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Gross revenues $254,021 $53,145 $223,150 $184,415 Production (lifting costs) 80,333 16,630 77,796 62,028 Exploration expense* 3,602 827 4,226 4,890 Depreciation, depletion and amortization** 69,990 16,020 52,502 55,114 Income tax expense 23,929 4,035 18,232 8,298 -------- ------- -------- -------- Results of continuing operation from producing activities $ 76,167 $15,633 $ 70,394 $ 54,085 ======== ======= ======== ========
* Includes a $3.2 million pre-tax writedown in the year ended December 31, 2002, a $0.7 million pre-tax writedown in the three-months ended December 31, 2001, and a $2.7 million and $3.8 million pre-tax writedown in the years ended September 30, 2001 and 2000, respectively, of a portion of an unproved leasehold ** Includes a pre-tax writedown of $3.5 million in the year ended September 30, 2000 under SFAS No. 121 (see Note 12) AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE FROM CONTINUING OPERATIONS
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Average sales price including the effects of hedging: Gas (Mcf) $ 3.16 $ 2.97 $ 3.09 $ 2.49 Oil (per barrel) $24.03 $24.19 $23.78 $18.33 Natural gas liquids (per barrel) $12.75 $10.07 $17.61 $16.06 Average sales price excluding the effects of hedging: Gas (Mcf) $ 2.96 $ 2.35 $ 4.86 $ 3.06 Oil (per barrel) $24.75 $19.79 $27.46 $26.45 Natural gas liquids (per barrel) $12.75 $10.07 $17.61 $16.06 Average production (lifting) cost (per Mcfe) $ 1.04 $ 0.94 $ 1.16 $ 0.90 Average production tax (per Mcfe) $ 0.24 $ 0.20 $ 0.36 $ 0.25 Average depreciation rate (per Mcfe)* $ 0.90 $ 0.91 $ 0.79 $ 0.75 ====== ====== ====== ======
* Excludes a pre-tax writedown of $3.5 million in the year ended September 30, 2000 under SFAS No. 121 (see Note 12) DRILLING ACTIVITY: The following table sets forth the total number of net productive and dry exploratory and development wells drilled:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Exploratory: Productive 0.1 0.3 0.1 0.3 Dry 0.1 -- 1.3 -- ----- ---- ---- ---- Total 0.2 0.3 1.4 0.3 ===== ==== ==== ==== Development: Productive 145.9 23.8 90.7 70.6 Dry 4.3 -- -- 1.5 ----- ---- ---- ---- Total 150.2 23.8 90.7 72.1 ===== ==== ==== ====
68 As of December 31, 2002, the Company was participating in the drilling of 6 gross development wells, with the Company's interest equivalent to 3.31 wells. PRODUCTIVE WELLS AND ACREAGE: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2002, and developed and undeveloped acreage as of the latest practicable date prior to year-end:
Gross Net ------- ------- Gas Wells 3,426 1,725 Oil Wells 2,785 1,069 ------- ------- Developed Acreage 772,519 428,080 Undeveloped Acreage 121,871 53,428 ------- -------
There were 42 wells with multiple completions in 2002. All wells and acreage are located onshore in the United States, with the majority of the net undeveloped acreage located in the Permian Basin. 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.
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 ======== ======= =======
Three months ended December 31, 2001 Gas MMcf Oil MBbl NGL MBbl - ------------------------------------ -------- ------- ------- Proved reserves at beginning of period 627,051 20,878 24,931 Revisions of previous estimates 89,055 (1,038) 1,381 Purchases 1 27 2 Discoveries and other additions 10,805 43 154 Production (12,018) (550) (451) Sales (499) (232) (73) -------- ------- ------- Proved reserves at end of period 714,395 19,128 25,944 -------- ------- ------- Proved developed reserves at end of period 646,202 16,293 23,476 ======== ======= =======
Year ended September 30, 2001 Gas MMcf Oil MBbl NGL MBbl - ----------------------------- -------- ------- ------- Proved reserves at beginning of period 777,456 24,518 26,007 Revisions of previous estimates (134,543) (2,407) (2,006) Purchases 9,334 1,100 836 Discoveries and other additions 26,145 1,995 1,672 Production (46,463) (2,187) (1,482) Sales (4,878) (2,141) (96) -------- ------- ------- Proved reserves at end of period 627,051 20,878 24,931 -------- ------- ------- Proved developed reserves at end of period 579,991 17,467 22,867 ======== ======= =======
69
Year ended September 30, 2000 Gas MMcf Oil MBbl NGL MBbl - ----------------------------- -------- ------- ------- Proved reserves at beginning of period 740,001 24,719 21,937 Revisions of previous estimates 37,028 (2,601) 3,250 Purchases 1,819 1,997 308 Discoveries and other additions 47,146 2,890 1,942 Production (48,084) (2,304) (1,429) Sales (454) (183) (1) ------ ------ ---- Proved reserves at end of period 777,456 24,518 26,007 ------ ------ ---- Proved developed reserves at end of period 691,287 18,714 22,906 ======= ====== ======
During 2002, Energen Resources invested approximately $174 million in proved property acquisitions. Energen Resources sold approximately 25 Bcfe of proved reserves, recording net pre-tax gains of $4 million. 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, 2002, December 31, 2001, and September 30, 2001 and 2000, the Company had a deferred hedging loss of $17.2 million, a deferred hedging gain of $15.2 million and $25.7 million and a deferred hedging loss of $89.4 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ----------- ------------- ------------- Future gross revenues $5,455,802 $2,181,148 $1,672,436 $4,824,681 Future production costs 1,754,700 829,968 693,817 1,379,913 Future development costs 183,818 114,317 83,781 110,660 ---------- ---------- ---------- ---------- Future net cash flows before income taxes 3,517,284 1,236,863 894,838 3,334,108 Future income tax expense 1,100,392 265,611 124,803 1,073,051 ---------- ---------- ---------- ---------- Future net cash flows after income taxes 2,416,892 971,252 770,035 2,261,057 Discount at 10% per annum 1,172,635 399,810 272,493 1,155,792 ---------- ---------- ---------- ---------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $1,244,257 $ 571,442 $ 497,542 $1,105,265 ========== ========== ========== ==========
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:
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Balance at beginning of year $ 571,442 $ 497,542 $ 1,105,265 $ 613,854 ----------- --------- ----------- ----------- Revisions to reserves proved in prior years: Net changes in prices, production costs and future development costs 658,956 100,710 (1,015,900) 715,746 Net changes due to revisions in quantity estimates (8,380) 49,579 (81,076) 37,049 Development costs incurred, previously estimated 49,418 8,812 50,768 39,589 Accretion of discount 57,144 11,398 144,266 61,385 Other (8,669) (24,012) 95,165 6,850 ----------- --------- ----------- -----------
70 Total revisions 748,469 146,487 (806,777) 860,619 New field discoveries and extensions, net of future production and development costs 213,625 5,562 33,685 110,727 Sales of oil and gas produced, net of production costs (162,151) (23,699) (220,220) (157,533) Purchases 218,799 20 32,811 17,657 Sales (14,203) (2,271) (26,256) (1,110) Net change in income taxes (331,724) (52,199) 379,034 (338,949) ----------- --------- ----------- ----------- Net change in standardized measure of discounted future net cash flows 672,815 73,900 (607,723) 491,411 ----------- --------- ----------- ----------- Balance at end of year $ 1,244,257 $ 571,442 $ 497,542 $ 1,105,265 =========== ========= =========== ===========
71 20. 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.
Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (in thousands) 2002 2001 2001 2000 ------------ ------------ ------------- ------------- Operating revenues from continuing operations Oil and gas operations $ 252,744 $ 49,486 $ 223,512 $ 185,248 Natural gas distribution 424,431 96,678 553,862 366,161 ----------- ----------- ----------- ----------- Total $ 677,175 $ 146,164 $ 777,374 $ 551,409 =========== =========== =========== =========== Operating income (loss) from continuing operations Oil and gas operations $ 78,416 $ 3,243 $ 72,425 $ 47,568 Natural gas distribution 59,370 8,034 50,288 49,063 Eliminations and corporate expenses (1,700) (417) (1,678) (1,620) ----------- ----------- ----------- ----------- Total $ 136,086 $ 10,860 $ 121,035 $ 95,011 =========== =========== =========== =========== Depreciation, depletion and amortization expense from continuing operations Oil and gas operations $ 71,405 $ 16,351 $ 53,846 $ 56,226 Natural gas distribution 33,682 8,151 30,933 28,708 ----------- ----------- ----------- ----------- Total $ 105,087 $ 24,502 $ 84,779 $ 84,934 =========== =========== =========== =========== Interest expense Oil and gas operations $ 29,635 $ 7,042 $ 30,244 $ 28,441 Natural gas distribution 14,557 3,680 12,316 9,870 Eliminations and other (479) (88) (490) (542) ----------- ----------- ----------- ----------- Total $ 43,713 $ 10,634 $ 42,070 $ 37,769 =========== =========== =========== =========== Income tax expense (benefit) from continuing operations Oil and gas operations $ 3,941 $ (4,843) $ 1,728 $ (7,552) Natural gas distribution 17,825 1,547 13,448 14,324 Other (1,257) (88) (365) (290) ----------- ----------- ----------- ----------- Total $ 20,509 $ (3,384) $ 14,811 $ 6,482 =========== =========== =========== =========== Capital expenditures Oil and gas operations $ 305,476 $ 25,052 $ 136,886 $ 67,090 Natural gas distribution 65,815 12,873 56,090 67,073 Other 5 -- 60 287 ----------- ----------- ----------- ----------- Total $ 371,296 $ 37,925 $ 193,036 $ 134,450 =========== =========== =========== =========== Identifiable assets Oil and gas operations $ 926,839 $ 687,776 $ 716,043 $ 737,814 Natural gas distribution 603,209 549,221 516,802 471,282 Eliminations and other 843 3,359 (8,966) (6,055) ----------- ----------- ----------- ----------- Total $ 1,530,891 $ 1,240,356 $ 1,223,879 $ 1,203,041 =========== =========== =========== =========== Property, plant and equipment, net Oil and gas operations $ 838,526 $ 620,305 $ 617,592 $ 552,287 Natural gas distribution 418,098 385,137 380,489 355,248 Other 179 237 253 294 ----------- ----------- ----------- ----------- Total $ 1,256,803 $ 1,005,679 $ 998,334 $ 907,829 =========== =========== =========== ===========
72 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
ENERGEN CORPORATION Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (IN THOUSANDS) 2002 2001 2001 2000 ------------ ------------- ------------- ------------- ALLOWANCE FOR DOUBTFUL ACCOUNTS BALANCE AT BEGINNING OF YEAR $ 11,783 $ 10,031 $ 6,681 $ 5,598 -------- -------- -------- ------- Additions: Charged to income 5,482 1,819 7,953 4,287 Recoveries and adjustments (495) 139 (901) (276) -------- -------- -------- ------- Net additions 4,987 1,958 7,052 4,011 -------- -------- -------- ------- Less uncollectible accounts written off (7,896) (206) (3,702) (2,928) -------- -------- -------- ------- BALANCE AT END OF YEAR $ 8,874 $ 11,783 $ 10,031 $ 6,681 ======== ======== ======== =======
ALABAMA GAS CORPORATION Three Months YEAR ENDED Ended Year Ended Year Ended DECEMBER 31, December 31, September 30, September 30, (IN THOUSANDS) 2002 2001 2001 2000 ------------ ------------- ------------- ------------- ALLOWANCE FOR DOUBTFUL ACCOUNTS BALANCE AT BEGINNING OF YEAR $ 11,100 $ 9,500 $ 5,800 $ 4,532 -------- -------- ------- ------- Additions: Charged to income 5,410 1,816 7,799 4,275 Recoveries and adjustments (565) (38) (452) (276) -------- -------- ------- ------- Net additions 4,845 1,778 7,347 3,999 -------- -------- ------- ------- Less uncollectible accounts written off (7,745) (178) (3,647) (2,731) -------- -------- ------- ------- BALANCE AT END OF YEAR $ 8,200 $ 11,100 $ 9,500 $ 5,800 ======== ======== ======= =======
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 73 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 23, 2003. The proxy statement will be filed on or about March 20, 2003. ITEM 11. EXECUTIVE COMPENSATION The information regarding executive compensation is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2003. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS The information regarding the security ownership of the beneficial owners of more than five percent of Energen's common stock is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2003. B. SECURITY OWNERSHIP OF MANAGEMENT The information regarding the security ownership of management is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 23, 2003. 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 23, 2003. 74 PART IV ITEM 14. CONTROLS AND PROCEDURES A. Our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures as of a date within 90 days before the filing of this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective. B. Our chief executive officer and chief financial officer have concluded that there were no significant changes in our internal controls or in other factors that could significantly affect those controls subsequent to the date of their most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K 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 B. REPORTS ON FORM 8-K Form 8-K dated March 14, 2002, reporting that Energen Resources signed a Purchase and Sale Agreement with First Permian, L.L.C. Form 8-K dated April 10, 2002, reporting that Energen Resources completed its purchase of oil and gas properties from First Permian, L.L.C. Form 8-K dated June 4, 2002, reporting that Alagasco had filed a request with the Alabama Public Service Commission (APSC) to continue its rate-setting methodology, Rate Stabilization and Equalization (RSE) Form 8-K dated June 11, 2002, reporting that the APSC extended Alagasco's rate-setting methodology, RSE for a six-year period through January 1, 2008 Form 8-K dated July 24, 2002, commenting on the Company's financial relationships with Williams Companies Inc. and Dynegy, Inc. Form 8-K dated August 14, 2002, reporting the certification which accompanied the Form 10-Q for the quarterly period ended June 30, 2002, pursuant to 18 United States Code section 1350, as enacted by section 906 of the Sarbanes-Oxley Act of 2002 75 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 July 22, 1998) which was filed as Exhibit 3(c) to Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810) *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 July 22, 1998) which was filed as Exhibit 3(e) to Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (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(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
76 *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 *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 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(d) Form of Addendum to Executive Retirement Supplement 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, 2000 (File No. 1-7810) *10(e) 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(f) 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(g) 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(h) 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(i) Energen Corporation 1997 Deferred Compensation Plan (as amended effective October 1, 1999) which was filed as Exhibit 10(h) to Energen's Annual Report on Form 10-K for the year ended September 30, 1999 (File No. 1-7810) *10(j) 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(k) 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(l) 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)
77 *10(m) 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(n) 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) 21 Subsidiaries of Energen Corporation 23 Consent of Independent Accountants (Energen Corporation)
*Incorporated by reference 78 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 18, 2003 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 79 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 18, 2003 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 18, 2003 By /s/ Geoffrey C. Ketcham - -------------------------------- -------------------------------------------------- Geoffrey C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer of Energen and Alabama Gas Corporation March 18, 2003 By /s/ Grace B. Carr - -------------------------------- -------------------------------------------------- Grace B. Carr Vice President and Controller of Energen March 18, 2003 By /s/ Paula H. Rushing - -------------------------------- -------------------------------------------------- Paula H. Rushing Vice President-Finance of Alabama Gas Corporation March 18, 2003 By /s/ Julian W. Banton - -------------------------------- -------------------------------------------------- Julian W. Banton Director March 18, 2003 By /s/ J. Mason Davis, Jr. - -------------------------------- -------------------------------------------------- J. Mason Davis, Jr. Director March 18, 2003 By /s/ James S. M. French - -------------------------------- -------------------------------------------------- James S. M. French Director March 18, 2003 By /s/ T. Michael Goodrich - -------------------------------- -------------------------------------------------- T. Michael Goodrich Director March 18, 2003 By /s/ Judy M. Merritt - -------------------------------- -------------------------------------------------- Judy M. Merritt Director
80 CERTIFICATION - ------------- I, Wm. Michael Warren, Jr., certify that: 1. I have reviewed this report on Form 10-K of Energen Corporation and Alabama Gas Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report. 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the "Evaluation Date"); and c) presented in this report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weakness in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. March 18, 2003 By /s/ Wm. Michael Warren, Jr. - ------------------ ----------------------------------------- Wm. Michael Warren, Jr. Chairman, President and Chief Executive Officer of Energen Corporation, Chairman and Chief Executive Officer of Alabama Gas Corporation 81 CERTIFICATION - ------------- I, G. C. Ketcham, certify that: 1. I have reviewed this report on Form 10-K of Energen Corporation and Alabama Gas Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report. 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the "Evaluation Date"); and c) presented in this report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weakness in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. March 18, 2003 By /s/ G. C. Ketcham - ------------------ ------------------------------------ G. C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation 82 EX-21 3 g79764agexv21.txt EX-21 SUBSIDIARIES OF ENERGEN CORPORATION EXHIBIT 21 SUBSIDIARIES OF ENERGEN CORPORATION Alabama Gas Corporation* Energen Resources Corporation* Energen Resources TEAM, Inc.* * Incorporated in the State of Alabama EX-23 4 g79764agexv23.txt EX-23 CONSENT OF INDEPENDENT ACCOUNTANTS EXHIBIT 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-43245 and File No. 333-86056) 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 February 21, 2003 relating to the consolidated financial statements and financial statement schedule of Energen Corporation, which appears in this Form 10-K. PricewaterhouseCoopers LLP Birmingham, Alabama March 18, 2003 83 -----END PRIVACY-ENHANCED MESSAGE-----