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, 2003
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___
COMMISSION IRS EMPLOYER FILE STATE OF IDENTIFICATION NUMBER REGISTRANT INCORPORATION NUMBER -------------------------------------------------------------------------------- 1-7810 ENERGEN CORPORATION ALABAMA 63-0757759 2-38960 ALABAMA GAS CORPORATION ALABAMA 63-0022000 |
605 RICHARD ARRINGTON JR. BOULEVARD NORTH
BIRMINGHAM, ALABAMA 35203-2707
TELEPHONE NUMBER 205/326-2700
HTTP://WWW.ENERGEN.COM
Securities Registered Pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS EXCHANGE ON WHICH REGISTERED ------------------- ---------------------------- Energen Corporation Common Stock, $0.01 par value New York Stock Exchange Energen Corporation Preferred Stock Purchase Rights New York Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the Act: NONE
Indicate by a check mark whether registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. YES |X| NO |_|
Indicate by a check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |_|
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). YES |X| NO |_|
Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30 2003:
Energen Corporation $1,160,436,680 |
Indicate number of shares outstanding of each of the registrant's classes of
common stock as of March 4, 2004:
Energen Corporation 36,346,358 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 29, 2004 (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 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 stratigraphic 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 detected by smell. OPERATIONAL ENHANCEMENT Any action undertaken to improve production efficiency of oil and gas wells and/or reduce well costs. OPERATOR The company responsible for exploration, development and production activities for a specific project. PAY-ADD An operation within a currently producing wellbore that attempts to access and complete an additional pay zone(s) while maintaining production from the existing completed zone(s). PAY ZONE The formation from which oil and gas is produced. PROVED DEVELOPED RESERVES The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. |
PROVED RESERVES Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. PROVED UNDEVELOPED The portion of proved reserves which can be RESERVES (PUD) expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. PUT OPTION A contract that gives the purchaser the right, but not the obligation, to sell the underlying commodity at a certain price on or before an agreed date. RECOMPLETION An operation within an existing wellbore whereby a completion in one pay zone is abandoned in order to attempt a completion in a different pay zone. RESERVES-TO- PRODUCTION Ratio expressing years of supply determined by 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 2003 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 Equity 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.................................... 29 Item 8. Financial Statements and Supplementary Data................................................... 30 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.......................................................................... 77 Item 9A. Controls and Procedures....................................................................... 77 PART III Item 10. Directors and Executive Officers of the Registrants........................................... 78 Item 11. Executive Compensation........................................................................ 78 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters................................................................... 78 Item 13. Certain Relationships and Related Transactions................................................ 78 Item 14. Principal Accountant Fees and Services........................................................ 78 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.............................. 79 Signatures .............................................................................................. 83 |
(This page intentionally left blank.)
This Form 10-K is filed on behalf of Energen Corporation
(Energen or the Company)
and Alabama Gas Corporation (Alagasco).
FORWARD-LOOKING STATEMENT AND RISK FACTORS: Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the 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, the Company's oil and gas subsidiary, is unable to fully invest its planned acquisition, development and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors.
Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate risk, fluctuations in future oil and gas prices could materially affect the Company's financial position and results of operation and cash flows; furthermore, such risk mitigation activities may cause the Company's financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk-mitigation assumes that counterparties maintain satisfactory credit quality.
PART I
ITEM 1. BUSINESS
GENERAL
Energen Corporation, based in Birmingham, Alabama, is a diversified energy holding company engaged primarily in the acquisition, development, exploration and production of oil, natural gas and natural gas liquids in the continental United States and in the purchase, distribution, and sale of natural gas, principally in central and north Alabama. Its two 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 this report. The Company makes available free of charge through its Web site the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. These reports are provided as soon as reasonably practicable after such reports are electronically filed with or furnished to the Securities and Exchange Commission. The Company's Web site also includes its Code of Ethics, Corporate Governance Guidelines, Audit Committee Charter, Officers' Review Committee Charter, Governance and Nominations Committee Charter and Finance Committee Charter.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The information required by this item is provided in Note 21, Industry Segment Information, in the Notes to Financial Statements.
NARRATIVE DESCRIPTION OF BUSINESS
- 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, 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 2003, Energen Resources' inventory of proved oil and gas reserves totaled 1,364.9 billion cubic feet equivalent (Bcfe). Substantially all of the company's approximately 1.4 trillion cubic feet equivalent of reserves are located in the San Juan Basin in New Mexico, the Permian Basin in west Texas, the Black Warrior Basin in Alabama, and the north Louisiana/east Texas region. Approximately 81 percent of Energen Resources' year-end reserves are proved developed reserves. Energen Resources reserves are long-lived, with a year-end reserves-to-production ratio of 16. Natural gas represents approximately 65 percent of Energen Resources' proved reserves, with oil representing approximately 23 percent and natural gas liquids comprising the balance.
GROWTH STRATEGY: Energen has operated for more than eight years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $755 million in property acquisitions, $555 million in related development, and $90 million in exploration and related development. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2008, is currently expected to approximate $1.4 billion, the majority of which represents unidentified acquisitions and related development.
Energen Resources' approach to the oil and gas business calls for the company to pursue onshore North American property acquisitions which offer proved undeveloped (PUD) and/or behind-pipe reserves as well as operational enhancement potential. Energen Resources prefers operated natural gas properties with long-lived reserves and multiple pay-zone opportunities; however, Energen Resources does not preclude possible acquisitions of properties with varying characteristics that otherwise meet its investment requirements.
Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties' PUD and behind-pipe reserve potential as well as engaging in other 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 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 2000, the Company's development efforts have added approximately 357 Bcfe of proved reserves from the drilling of approximately 749 gross development wells and 406 well recompletions and pay-adds. In 2003, Energen Resources' successful development wells and other activities added approximately 135 Bcfe of proved reserves. The company drilled 347 gross development wells, performed some 145 well recompletions and pay-adds, and conducted other operational enhancements. Energen Resources' production from continuing operations totaled 85.4 Bcfe in 2003 and is estimated to total 85 Bcfe in 2004, including 81.6 Bcfe of estimated production from proved reserves owned at December 31, 2003.
RISK MANAGEMENT: Energen Resources attempts to lower the risks associated with its oil and natural gas business. A key component of the company's efforts to manage risk is its acquisition versus exploration orientation and its preference for long-lived reserves. In pursuing an acquisition, Energen Resources primarily uses the then-current oil and gas futures prices in its evaluation models, the prevailing swap curve and, for the longer-term, its own pricing assumptions. 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 estimated annual production in any given year depending on its pricing outlook.
Statement of Financial Accounting Standards (SFAS) No. 133 (as amended), "Accounting for Derivative Instruments and Hedging Activities," requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the 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 operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized as operating revenues in earnings in the period of change under mark-to-market accounting.
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. To the extent that Energen Resources has operating agreements with various joint venture partners, environmental costs would be shared proportionately.
RISK FACTORS: For a discussion of risks inherent in the Company's businesses, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
- 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 185 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.4 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2003, Alagasco served an average of 427,413 residential customers and 35,463 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 9,810 miles of main and more than 11,494 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, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and year-to-date performance, whether Alagasco's return on average equity at the end of the rate year will be within the allowed range. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco's operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments.
The temperature adjustment rider to Alagasco's rate tariff, approved by the APSC in 1990, was designed to mitigate the earnings impact of variances from normal temperatures. Alagasco calculates a temperature adjustment to customers' monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco's earnings. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers' bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. Adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider that permits the pass-through to customers of changes in the cost of gas supply.
The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, when one or a
combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco's return on equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is achieved.
GAS SUPPLY: Alagasco's distribution system is connected to two major interstate natural gas pipeline systems - Southern Natural Gas Company (Southern) and Transcontinental Gas Pipe Line Company (Transco). It is also connected to several intrastate natural gas pipeline systems and to Alagasco's two liquified natural gas (LNG) facilities.
Alagasco purchases natural gas from various natural gas producers and marketers. Certain volumes are purchased under firm contractual commitments with other volumes purchased on a spot market basis. The purchased volumes are delivered to Alagasco's system using a variety of firm transportation, interruptible transportation and storage capacity arrangements designed to meet the system's varying levels of demand. Alagasco's LNG facilities can provide the system with up to 200,000 additional thousand cubic feet per day (Mcfd) of natural gas to meet peak day demand.
As of December 31, 2003, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:
-------------------------------------------------------------------------- DECEMBER 31, 2003 -------------------------------------------------------------------------- (Mcfd) ----------------- Southern firm transportation 164,332 Southern storage and no notice transportation 251,679 Transco firm transportation 100,000 Various intrastate transportation 23,900 -------------------------------------------------------------------------- |
COMPETITION AND RATE FLEXIBILITY: The price of natural gas is a significant competitive factor in Alagasco's service territory, particularly among large commercial and industrial transportation customers. Propane, coal and fuel oil are readily available, and many industrial customers have the capability to switch to alternate fuels and/or alternate sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of flexible rate strategies to help it compete for the large customer gas load in the deregulated marketplace. Rate flexibility remains critical as the utility faces competition for this load. To date, the utility has been effective in utilizing its flexible rate strategies to minimize bypass and price-based switching to alternate fuels and alternate sources of gas.
In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs. Alagasco's core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential and small commercial and industrial customers. In 2003, approximately 300 of Alagasco's transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled approximately $7.5 million.
The Competitive Fuel Clause (CFC) and Transportation Tariff also have been important to Alagasco's ability to compete effectively for customer load in its service territory. The CFC allows Alagasco to adjust large customer rates on a case-by-case basis to compete with alternate fuels and alternate sources of gas. The GSA rider to Alagasco's tariff allows the Company to recover the reduction in charges allowed under the CFC because the retention of any customer, particularly large commercial and industrial transportation customers, benefits all customers by recovering a portion of the system's fixed costs. The Transportation Tariff allows Alagasco to transport gas for customers, rather than buy and resell it to them, and is based on Alagasco's sales profit margin so that operating margins are unaffected. During 2003 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 2003, 50 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 2003, Alagasco's average number of customers increased slightly. For 2004, 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.
RISK FACTORS: For a discussion of risks inherent in the Company's businesses, see Management's Discussion and Analysis of Financial Condition and Results of Operations as set forth in Item 7 of Part II of this Form 10-K.
EMPLOYEES
The Company has 1,500 employees; Alagasco employs 1,232 and Energen Resources employs 268. The Company believes that its relations with employees are good.
ITEM 2. PROPERTIES
The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. Energen Resources maintains leased offices in 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 and reserves is summarized in the table below and included in Note 20, Oil and Gas Operations (unaudited), included in the Form 10-K in the Notes to Financial Statements.
-------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 2003 DECEMBER 31, 2003 -------------------------------------------------------------------------------- Production Volumes Proved Reserves (MMcfe) (MMcfe) --------------------------------------- San Juan Basin 28,406 666,349 Permian Basin 31,263 365,394 Black Warrior Basin 15,549 252,416 North Louisiana/East Texas 10,087 75,004 Other 852 5,782 -------------------------------------------------------------------------------- Total 86,157 1,364,945 -------------------------------------------------------------------------------- |
The properties of Alagasco consist primarily of its gas distribution system, which includes more than 9,810 miles of main, more than 11,494 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, seven division offices, four payment centers, four district offices, nine service centers, and other related property and equipment, some of which are leased by Alagasco. For a further description of Alagasco's properties, see the discussion under Item 1-Business.
ITEM 3. LEGAL PROCEEDINGS
Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specific relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards may bear little or no relation to culpability or actual damages thus making it difficult to predict litigation results.
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 2003.
EXECUTIVE OFFICERS OF THE REGISTRANTS
ENERGEN CORPORATION
Name Age Position (1) ---- --- ------------ Wm. Michael Warren, Jr. 56 Chairman of the Board President and Chief Executive Officer (2) Geoffrey C. Ketcham 53 Executive Vice President, Chief Financial Officer and Treasurer (3) James T. McManus 45 President and Chief Operating Officer of Energen Resources (4) Dudley C. Reynolds 51 President and Chief Operating Officer of Alagasco (5) Grace B. Carr 48 Vice President and Controller (6) J. David Woodruff, Jr. 47 General Counsel and Secretary and Vice President-Corporate Development (7) |
NOTES: (1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of the Board of Directors.
(2) Mr. Warren has been employed by the Company in various capacities since 1983. In January 1992 he was elected President and Chief Operating Officer of Energen and all of its subsidiaries, in October 1995 he was elected Chief Executive Officer of Alagasco and Energen Resources, in February 1997 he was elected Chief Executive Officer of Energen and effective January 1, 1998, he was elected Chairman of the Board of Energen and each of its subsidiaries. Mr. Warren serves as a Director of Energen and each of its subsidiaries. He is also a Director of Protective Life Corporation.
(3) Mr. Ketcham has been employed by the Company in various financial and strategic planning capacities since 1981. He has served as Executive Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries since April 1991.
(4) Mr. McManus has been employed by the Company in various capacities since 1986. He was elected Executive Vice President and Chief Operating Officer of Energen Resources in October 1995 and President of Energen Resources in April 1997.
(5) Mr. Reynolds has been employed by the Company in various capacities since 1980. He was elected General Counsel and Secretary of Energen and each of its subsidiaries in April 1991. He was elected President and Chief Operating Officer of Alagasco effective January 1, 2003.
(6) Ms. Carr was employed by the Company in various capacities from January 1985 to April 1989. She was not employed from May 1989 through December 1997. She was elected Controller of Energen in January 1998 and elected Vice President and Controller of Energen in October 2001.
(7) Mr. Woodruff has been employed by the Company in various capacities since 1986. He was elected Vice President-Legal and Assistant Secretary of Energen and each of its subsidiaries in April 1991 and Vice President-Corporate Development of Energen in October 1995. He was elected General Counsel and Secretary of Energen and each of its subsidiaries effective January 1, 2003.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE -------------------------------------------------------------------------------- Quarter ended (in dollars) HIGH LOW CLOSE DIVIDENDS PAID -------------------------------------------------------------------------------- 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 -------------------------------------------------------------------------------- March 31, 2003 32.06 28.08 32.06 .180 June 30, 2003 34.29 31.60 33.30 .180 September 30, 2003 37.09 31.35 36.18 .185 December 31, 2003 42.00 36.14 41.03 .185 -------------------------------------------------------------------------------- |
Energen's common stock is listed on the New York Stock Exchange under the symbol EGN. On February 9, 2004, there were approximately 7,750 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 to Weighted Number of Securities Remaining be Issued Upon Exercise Average Available for Future Issuance Plan Category of Outstanding Options Exercise Price Under Equity Compensation Plans -------------------------------------------------------------------------------------------------------------- Equity compensation plans approved by security holders 588,420 $22.28 1,744,823 Equity compensation plans not approved by security holders -- -- -- -------------------------------------------------------------------------------------------------------------- Total 588,420 $22.28 1,744,823 -------------------------------------------------------------------------------------------------------------- |
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 Year Ended Ended Year Ended Year Ended Year Ended Year Ended (dollars in thousands, except DECEMBER 31, December 31, December 31, September 30, September 30, September 30, September 30, per share amounts) 2003 2002 2001* 2001 2000 1999 1998 ----------------------------------------------------------------------------------------------------------------------------------- INCOME STATEMENT Operating revenues $ 842,221 $ 668,551 $ 143,632 $ 762,816 $ 542,012 $ 487,654 $ 492,847 Income from continuing operations before cumulative effect of change in accounting principle $ 110,265 $ 70,396 $ 3,730 $ 62,417 $ 51,488 $ 41,729 $ 32,535 Net income $ 110,654 $ 68,639 $ 3,658 $ 67,896 $ 53,018 $ 41,410 $ 36,249 Diluted earnings per average common share from continuing operations before cumulative effect of change in accounting principle $ 3.09 $ 2.08 $ 0.12 $ 2.01 $ 1.70 $ 1.39 $ 1.11 Diluted earnings per average common share $ 3.10 $ 2.03 $ 0.12 $ 2.18 $ 1.75 $ 1.38 $ 1.23 ----------------------------------------------------------------------------------------------------------------------------------- BALANCE SHEET Capitalization at year-end: Common shareholders' equity $ 699,032 $ 582,810 $ 474,205 $ 480,767 $ 400,860 $ 361,504 $ 329,249 Long-term debt 552,842 512,954 544,133 544,110 353,932 371,824 372,782 ----------------------------------------------------------------------------------------------------------------------------------- Total capitalization $1,251,874 $1,095,764 $1,018,338 $1,024,877 $ 754,792 $ 733,328 $ 702,031 ----------------------------------------------------------------------------------------------------------------------------------- Total assets $1,781,432 $1,643,012 $1,342,346 $1,313,885 $1,286,341 $1,261,469 $1,064,142 ----------------------------------------------------------------------------------------------------------------------------------- Property, plant and equipment, net $1,433,451 $1,351,554 $1,093,201 $1,084,052 $ 986,604 $ 933,333 $ 822,741 ----------------------------------------------------------------------------------------------------------------------------------- COMMON STOCK DATA Annual dividend rate at period-end $ 0.74 $ 0.72 $ 0.70 $ 0.70 $ 0.68 $ 0.66 $ 0.64 Cash dividends paid per common share $ 0.73 $ 0.71 $ 0.175 $ 0.685 $ 0.665 $ 0.645 $ 0.625 Book value per common share $ 19.30 $ 16.77 $ 15.18 $ 15.45 $ 13.21 $ 12.09 $ 11.23 Market-to-book ratio at period-end (%) 213 174 162 145 225 167 169 Yield at period-end (%) 1.8 2.5 2.8 3.1 2.3 3.3 3.4 Return on average common equity (%) 17.1 12.4 13.0 15.8 13.7 11.7 11.1 Price-to-earnings (diluted) ratio at period-end 13.2 14.3 -- 10.3 17.0 14.7 15.4 Shares outstanding at period-end (000) 36,224 34,745 31,249 31,125 30,351 29,904 29,327 Price Range: High $ 42.00 $ 29.99 $ 25.20 $ 40.25 $ 30.38 $ 20.38 $ 22.50 Low $ 28.08 $ 21.65 $ 21.50 $ 21.50 $ 14.69 $ 13.13 $ 15.13 Close $ 41.03 $ 29.10 $ 24.65 $ 22.50 $ 29.75 $ 20.25 $ 19.00 ----------------------------------------------------------------------------------------------------------------------------------- |
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
SELECTED BUSINESS SEGMENT DATA
Energen Corporation
----------------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended Year Ended Year Ended Year Ended DECEMBER 31, December 31, December 31, September 30, September 30, September 30, September 30, (dollars in thousands) 2003 2002 2001* 2001 2000 1999 1998 ----------------------------------------------------------------------------------------------------------------------------------- OIL AND GAS OPERATIONS Operating revenues from continuing operations Natural gas $ 235,649 $ 145,935 $ 34,290 $ 132,554 $ 113,168 $ 113,219 $ 89,866 Oil 87,200 72,758 11,128 43,880 36,143 33,779 19,508 Natural gas liquids 25,890 21,857 4,282 24,540 21,443 6,683 6,482 Other 4,383 3,570 (2,746) 7,980 5,097 8,419 7,051 ----------------------------------------------------------------------------------------------------------------------------------- Total $ 353,122 $ 244,120 $ 46,954 $ 208,954 $ 175,851 $ 162,100 $ 122,907 ----------------------------------------------------------------------------------------------------------------------------------- Production volumes from continuing operations Natural gas (MMcf) 55,433 46,060 11,454 44,071 45,557 51,105 40,631 Oil (MBbl) 3,412 3,016 464 1,873 1,983 2,823 1,298 Natural gas liquids (MBbl) 1,587 1,712 428 1,397 1,334 700 760 ----------------------------------------------------------------------------------------------------------------------------------- Production volumes from continuing operations (MMcfe) 85,422 74,424 16,801 63,690 65,459 72,243 52,979 ----------------------------------------------------------------------------------------------------------------------------------- Total production volumes (MMcfe) 86,157 77,973 18,022 68,478 70,482 77,159 57,353 ----------------------------------------------------------------------------------------------------------------------------------- Proved reserves Natural gas (MMcf) 886,307 803,748 714,395 627,051 777,456 740,001 542,039 Oil (MBbl) 52,528 49,833 19,128 20,878 24,518 24,719 19,845 Natural gas liquids (MBbl) 27,245 26,697 25,944 24,931 26,007 21,937 17,292 ----------------------------------------------------------------------------------------------------------------------------------- Total (MMcfe) 1,364,945 1,262,928 984,827 901,905 1,080,605 1,019,937 764,861 ----------------------------------------------------------------------------------------------------------------------------------- Other data from continuing operations Lease operating expense (LOE) LOE and other $ 67,920 $ 57,141 $ 11,474 $ 49,273 $ 49,866 $ 53,441 $ 37,918 Production taxes 27,731 18,254 3,387 22,833 16,536 10,677 8,688 ----------------------------------------------------------------------------------------------------------------------------------- Total $ 95,651 $ 75,395 $ 14,861 $ 72,106 $ 66,402 $ 64,118 $ 46,606 ----------------------------------------------------------------------------------------------------------------------------------- Depreciation and amortization $ 79,687 $ 68,009 $ 15,317 $ 50,907 $ 53,499 $ 57,402 $ 52,194 Capital expenditures $ 163,338 $ 305,476 $ 25,052 $ 136,886 $ 67,090 $ 198,577 $ 120,991 Operating income $ 155,481 $ 78,105 $ 3,496 $ 66,416 $ 45,853 $ 31,541 $ 16,643 ----------------------------------------------------------------------------------------------------------------------------------- NATURAL GAS DISTRIBUTION ----------------------------------------------------------------------------------------------------------------------------------- Operating revenues Residential $ 320,938 $ 277,088 $ 63,724 $ 367,109 $ 233,839 $ 209,263 $ 241,964 Commercial and industrial-small 126,638 104,247 22,445 147,636 88,521 77,254 89,361 Transportation 38,250 38,395 9,765 33,972 35,312 34,541 35,246 Other 3,273 4,701 744 5,145 8,489 4,496 3,369 ----------------------------------------------------------------------------------------------------------------------------------- Total $ 489,099 $ 424,431 $ 96,678 $ 553,862 $ 366,161 $ 325,554 $ 369,940 ----------------------------------------------------------------------------------------------------------------------------------- Gas delivery volumes (MMcf) Residential 27,248 26,358 5,128 31,064 26,069 24,751 31,079 Commercial and industrial-small 12,564 11,838 2,193 14,054 12,092 11,662 13,705 Transportation 55,623 59,644 12,973 53,989 70,534 66,356 70,563 ----------------------------------------------------------------------------------------------------------------------------------- Total 95,435 97,840 20,294 99,107 108,695 102,769 115,347 ----------------------------------------------------------------------------------------------------------------------------------- Average number of customers Residential 427,413 425,630 422,461 428,663 429,368 425,937 423,602 Commercial, industrial and transportation 35,463 35,601 35,161 35,882 35,526 35,111 34,782 ----------------------------------------------------------------------------------------------------------------------------------- Total 462,876 461,231 457,622 464,545 464,894 461,048 458,384 ----------------------------------------------------------------------------------------------------------------------------------- Other data Depreciation and amortization $ 37,171 $ 33,682 $ 8,151 $ 30,933 $ 28,708 $ 26,730 $ 25,153 Capital expenditures $ 57,906 $ 65,815 $ 12,873 $ 56,090 $ 67,073 $ 46,029 $ 54,168 Operating income $ 66,848 $ 59,370 $ 8,034 $ 50,288 $ 49,063 $ 46,565 $ 41,663 ----------------------------------------------------------------------------------------------------------------------------------- |
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CRITICAL ACCOUNTING POLICIES
The Company's consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Management has identified the following critical accounting policies in the application of existing accounting standards or in the implementation of new standards that involve significant judgments and estimates by the Company:
OIL AND GAS OPERATIONS
ACCOUNTING FOR NATURAL GAS AND OIL PRODUCING ACTIVITIES
AND RELATED RESERVES: The Company utilizes the successful efforts method of
accounting for its natural gas and oil producing activities. Under this
accounting method, acquisition and development costs of proved properties are
capitalized and amortized on a units-of-production basis over the remaining life
of total proved and proved developed reserves.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have reviewed the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2003. The independent reservoir engineers have issued reports covering approximately 97 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate. The Company's production of undeveloped reserves requires the installation or completion of related infrastructure facilities such as pipelines and the drilling of development wells.
Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property's book value if an impairment is warranted. The table below reflects the estimated increase (decrease) in 2004 depreciation and depletion expense associated with changes in oil and gas reserve quantities from the reported amounts at December 31, 2003.
------------------------------------------------------------------------------------------------- Percentage Change in Oil & Gas Reserves From Reported Reserves as of December 31, 2003 (dollars in thousands) +10% +5% -5% -10% ------------------------------------------------------------------------------------------------- Estimated change in depreciation expense for the year ended December 31, 2004, net of tax $(3,900) $(2,000) $ 2,400 $ 5,000 ------------------------------------------------------------------------------------------------- |
ASSET IMPAIRMENTS: Oil and gas developed and undeveloped properties periodically are assessed for possible impairment, generally on a field-by-field basis, using the estimated undiscounted future cash flows of each field. Impairment losses are recognized when the estimated undiscounted future cash flows are less than the current net book values of the properties in a field. The Company monitors its oil and gas properties as well as the market and business environments in which it operates and makes assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, substantial commodity price declines, unanticipated increased operating costs, and lower-than-expected production performance. If a material event occurs, Energen Resources makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, the Company will record an impairment loss for the difference 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 impact on the Company's need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact the Company's original and ongoing assessments of potential impairment.
DERIVATIVES: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended) requires all derivatives to be recognized on the balance sheet and measured at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. SFAS No. 133 is subject to interpretations in its application. The potential exists for additional issues to be brought under review, and, if subsequent interpretations of SFAS No. 133 are different than current interpretations, it is possible that the Company's policy, as stated above, may be modified.
NATURAL GAS DISTRIBUTION
REGULATED OPERATIONS: Alagasco applies Statement of Financial Accounting
Standard (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," to its regulated operations. This standard requires a cost to be
capitalized as a regulatory asset that otherwise would be charged to expense if
it is probable that the cost is recoverable in the future through regulated
rates. Likewise, if current recovery is provided for a cost that will be
incurred in the future, SFAS No. 71 requires the cost to be recognized as a
regulatory liability. The Company anticipates SFAS No. 71 will continue as the
applicable accounting standard for its regulated operations. Alagasco's rate
setting methodology, Rate Stabilization and Equalization, has been in effect
since 1983.
CONSOLIDATED
EMPLOYEE PENSION PLANS: Determining the Company's obligations to employees under
its defined benefit pension plans requires the use of estimates. The calculation
of the liability related to the Company's defined benefit pension plans 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. The discount rate used for actuarial purposes covering a
majority of employees was 6 percent for the year ended December 31, 2003. A
hypothetical 25 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. The return on
assets used for actuarial purposes was 9 percent for the year ended December 31,
2003. A hypothetical 25 basis point change in the return on assets would impact
total pension expense by approximately $245,000. The discount rate and return on
plan assets used in the actuarial assumptions for 2004 is 6 percent and 8.75
percent, respectively.
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 is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes.
RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Energen Corporation's net income for the year ended December 31, 2003 totaled
$110.7 million, or $3.10 per diluted share compared to year ended December 31,
2002 net income of $68.6 million, or $2.03 per diluted share. This 52.7 percent
increase in earnings per diluted share (EPS) largely reflected the result of
significantly higher prices for natural gas, oil and natural gas liquids as well
as the impact of a 14.8 percent increase in production volumes of Energen's oil
and gas subsidiary, Energen Resources Corporation. Prior-year results included a
$5.7 million after-tax, or $0.17 per diluted share, non-cash benefit from the
Company's previous hedge position with Enron North America Corp. (Enron) and
$14.2 million, or $0.42 per diluted share, of nonconventional fuels tax credits.
Discontinued operations in 2003 reflected a gain of $0.4 million as compared
with a gain of $0.5 million in 2002. Net income in 2002 also included a charge
of $2.2 million after-tax or $0.07 per diluted share, reflecting the cumulative
effect on prior years of the adoption of SFAS No. 143, "Accounting for Asset
Retirement Obligations." For the year ended December 31, 2003, Energen Resources
earned $78.9 million, as compared with $41.2 million in the previous year.
Alabama Gas Corporation (Alagasco), Energen's utility subsidiary, generated a
19.8 percent increase in net income, earning $33 million in the current year as
compared with net income in the prior period of $27.6 million. For the 12 months
ended September 30, 2001, Energen reported earnings of $67.9 million, or $2.18
per diluted share.
2003 VS 2002: Energen Resources' net income rose 91.5 percent to $78.9 million in 2003. Energen Resources' income from continuing operations before the cumulative effect of a change in accounting principle totaled $78.5 million in 2003 as compared with $43 million in 2002, primarily due to higher commodity prices along with the impact of increased gas and oil production volumes due to a full year's production from the April 2002 acquisition of oil properties in the Permian Basin, a new gas project in the Permian Basin, acquisitions in the San Juan Basin and the successful coalbed methane down-spacing program. These increases were partially offset by higher lease operating expense and increased depreciation, depletion and amortization (DD&A) expense. Prior year results included the non-cash benefit associated with the Company's previous hedge position with Enron and the recognition of $14.2 million in non-conventional fuels tax credits. The ability to generate new credits ended December 31, 2002.
Alagasco earned net income of $33 million in 2003 as compared with net income of $27.6 million in 2002. This increase in earnings reflected the utility's ability to earn on a higher level of equity representing investment in utility plant. It also reflected the impact of timing differences between quarters as it relates to revenue recovery under the utility's rate-setting mechanism. Alagasco's return on average equity (ROE) was 13.5 percent in 2003 compared with 12.3 percent in 2002.
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 2002 included a charge of $2.2 million after-tax ($0.07 per diluted share) related to the adoption of SFAS No. 143, as discussed above. Energen Resources' income from continuing operations before the cumulative effect of a change in accounting principle in 2002 totaled $43 million as compared with $37.1 million in 2001. Positively influencing income from continuing operations was a 16.9 percent increase in production volumes related to the acquisition of oil properties in the Permian Basin in April 2002 and the non-cash benefit of $5.7 million after-tax ($0.17 per diluted share) associated with its previous hedge position with Enron. The primary negative influences on income from continuing operations were increased DD&A and lease operating expenses.
Alagasco's earnings increased to $27.6 million in 2002 from $26 million in 2001 as a result of the utility earning on a higher level of equity. Alagasco achieved a ROE of 12.3 percent in both 2002 and 2001.
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 income from continuing operations of $1.2 million in the December 31,
2001 transition quarter as compared with $8.3 million in the same quarter in the
previous year largely due to a 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 and a $1.7 million writedown on property held for sale. 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 2003, 2002 and 2001 totaled $219.8 million, $135.8 million and $115 million, respectively. This significant growth in operating income has been influenced by strong financial performance from Energen Resources under Energen's diversified growth strategy, implemented in fiscal 1996. Alagasco also contributed to this growth in operating income consistent with increases in the levels of equity upon which it has been able to earn a return.
OIL AND GAS OPERATIONS: Revenues from oil and gas operations rose significantly in the current year largely as a result of increased natural gas, oil and natural gas liquids prices; a full year's production from the 2002 acquisition of oil properties in the Permian Basin; a new project in the Permian Basin that produced gas which had previously been reinjected into the reservoir; acquisitions in the San Juan Basin; and a successful coalbed methane down-spacing program. During 2003, production from continuing operations rose 14.8 percent to 85.4 billion cubic feet equivalent (Bcfe). Natural gas production increased 20.3 percent to 55.4 billion cubic feet (Bcf) and oil volumes rose 13.1 percent to 3,412 thousand barrels (MBbl). Production of natural gas liquids declined 7.3 percent to 1,587 MBbl. Including the prior-period non-cash benefit from the former Enron hedges, realized gas prices increased 34.1 percent to $4.25 per thousand cubic feet (Mcf), realized oil prices rose 5.9 percent to $25.56 per barrel and natural gas liquids prices increased 27.8 percent to an average price of $16.32 per barrel during 2003.
In 2002, revenues from oil and gas operations increased primarily as a result of increased production volumes related to the Permian Basin acquisition. During 2002, production from continuing operations increased 16.9 percent to 74.4 Bcfe. Natural gas production increased 4.5 percent to 46.1 Bcf, oil volumes rose 61 percent to 3,016 MBbl and natural gas liquids production increased 22.5 percent to 1,712 MBbl. Including the non-cash benefit from the former Enron hedges, realized gas prices rose 5.3 percent to $3.17 per Mcf, while realized oil prices increased 3 percent to $24.13 per barrel. Natural gas liquids prices fell 27.3 percent to an average price of $12.77 per barrel.
Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses. Revenues from operating fees were $6.1 million, $4.8 million and $7.6 million in 2003, 2002 and 2001, respectively.
-------------------------------------------------------------------------------------------------- DECEMBER 31, December 31, September 30, Years ended (in thousands, except sales price data) 2003 2002 2001 -------------------------------------------------------------------------------------------------- Operating revenues from continuing operations Natural gas $ 235,649 $ 145,935 $ 132,554 Oil 87,200 72,758 43,880 Natural gas liquids 25,890 21,857 24,540 Operating fees 6,077 4,847 7,618 Other (1,694) (1,277) 362 -------------------------------------------------------------------------------------------------- Total operating revenues from continuing operations $ 353,122 $ 244,120 $ 208,954 -------------------------------------------------------------------------------------------------- Production volumes from continuing operations Natural gas (MMcf) 55,433 46,060 44,071 Oil (MBbl) 3,412 3,016 1,873 Natural gas liquids (MBbl) 1,587 1,712 1,397 -------------------------------------------------------------------------------------------------- Average sales price including effects of hedging Natural gas (per Mcf) $ 4.25 $ 3.17 $ 3.01 Oil (per barrel) $ 25.56 $ 24.13 $ 23.43 Natural gas liquids (per barrel) $ 16.32 $ 12.77 $ 17.57 -------------------------------------------------------------------------------------------------- Average sales price excluding effects of hedging Natural gas (per Mcf) $ 4.97 $ 2.96 $ 4.85 Oil (per barrel) $ 29.19 $ 24.82 $ 27.42 Natural gas liquids (per barrel) $ 18.40 $ 12.77 $ 17.57 -------------------------------------------------------------------------------------------------- |
Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144,"Accounting for Impairment or Disposal of Long-Lived Assets," which was adopted as of January 1, 2002. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million. Energen Resources recorded in 2002 a pre-tax gain of $0.9 million in total income from discontinued operations from the sale of properties and adjustments to the fair value of properties being held-for-sale. 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.
Operations and maintenance (O&M) expense increased $10.8 million and $10.6 million in 2003 and 2002, respectively. Lease operating expense (excluding production taxes) in 2003 rose $10.8 million primarily due to the acquisition of oil and gas properties; higher operational costs driven by market conditions related to increased commodity costs as well as an increased number of wells in the San Juan and Permian Basins; and increased drilling activity in the coalbed methane down-spacing program. In 2002, lease operating expense (excluding production taxes) increased by $7.9 million primarily due to the acquisition of oil and gas properties. Administrative expense increased $2.8 million and $3.3 million in 2003 and 2002, respectively, primarily due to labor related costs and additional costs related to the property acquisition. Exploration expense decreased $2.5 million in 2003 largely due to a $3.2 million pre-tax writedown of unproved leasehold costs recorded during 2002 offset by increased exploratory efforts. In 2002, exploration expense decreased $0.6 million primarily due to decreased exploratory efforts.
DD&A expense increased $11.7 million in 2003 and $17.1 million in 2002 largely due to increased production volumes. The average depletion rate was $0.92 per Mcfe in 2003, $0.89 per Mcfe in 2002 and $0.78 per Mcfe in 2001.
Energen Resources' expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes for 2003 of $27.7 million as a result of increased commodity prices as well as increased production. Severance taxes in 2002 and 2001 were $18.3 million and $22.8 million, respectively.
OIL AND GAS OPERATIONS - TRANSITION PERIOD: Revenues from oil and gas continuing operations declined 8.6 percent to $47 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 12 percent to $2.99 per Mcf, while realized oil prices rose 10 percent to $24.01 per barrel. Natural gas liquids prices decreased 51.6 percent to an average price of $10.01 per barrel.
Natural gas production in the transition quarter increased slightly to 11.5 Bcf, while oil volumes decreased slightly to 464 MBbl. Natural gas liquids production increased 14.1 percent to 428 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 $ 34,290 $ 30,357 Oil production 11,128 10,502 Natural gas liquids production 4,282 7,758 Operating fees 913 2,225 Other (3,659) 555 ------------------------------------------------------------------------------------------ Total revenues from continuing operations $ 46,954 $ 51,397 ------------------------------------------------------------------------------------------ Production volumes from continuing operations Natural gas (MMcf) 11,454 11,364 Oil (MBbl) 464 481 Natural gas liquids (MBbl) 428 375 ------------------------------------------------------------------------------------------ Average sales price including effects of hedging Natural gas (per Mcf) $ 2.99 $ 2.67 Oil (per barrel) $ 24.01 $ 21.84 Natural gas liquids (per barrel) $ 10.01 $ 20.70 ------------------------------------------------------------------------------------------ Average sales price excluding effects of hedging Natural gas (per Mcf) $ 2.34 $ 5.16 Oil (per barrel) $ 19.52 $ 30.50 Natural gas liquids (per barrel) $ 10.01 $ 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 December 31, 2001 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 $7.8 million in the transition quarter ended December 31, 2001, largely due to the non-cash writedown of $8.7 million pre-tax associated with Energen Resources' hedge position with Enron. Lease operating expense decreased by $0.3 million in the transition quarter while exploration expense declined $0.3 million. Energen Resources' DD&A expense for the period rose $4.1 million primarily driven by the impact of market declines in commodity prices. The average depletion rate for the transition quarter was $0.89 as compared to $0.66 for the same period in the previous year.
Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $3.2 million lower in the transition quarter largely 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 utility's rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the company and a hearing, the Commission votes to either modify or discontinue its operation.
Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco's rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues, but operating margins essentially remain unaffected due to a temperature adjustment mechanism that requires Alagasco to adjust customer bills monthly to reflect changes in usage due to departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.
Alagasco's natural gas and transportation sales revenues totaled $489.1 million, $424.4 million and $553.9 million in 2003, 2002 and 2001, respectively. Sales revenue in 2003 rose largely due to a significant increase in the commodity cost of gas. 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 2002.
During 2003, weather was comparable to the previous year. Residential sales volumes increased 3.4 percent and small commercial and industrial volumes increased 6.1 percent largely due to increased gas usage per customer. Transportation volumes declined 6.7 percent primarily due to higher gas prices which resulted in alternate fuel use partially offset by certain nonrecurring gas deliveries. In 2002, 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.
Higher commodity gas cost generated a 23.3 percent increase in cost of gas for 2003. 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.
O&M expense at the utility increased 4.6 percent in 2003 primarily due to increased labor-related costs. In 2002, O&M expense increased 3.1 percent primarily due to higher insurance and labor-related costs partially offset by reduced bad debt expense and marketing costs. The increase in O&M expense per customer for the rate years ended September 30, 2003 and 2002 were slightly above the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utility's rate-setting mechanism; as a result, three quarters of the difference, or $0.1 million and $0.3 million pre-tax respectively, was returned to the customers through RSE (see Note 2). In 2001, the increase in O&M expense on a per-customer basis fell within the CCM.
Depreciation expense rose 10.4 percent in 2003 consistent with the growth in the utility's depreciable base and with the replacement of support systems with higher depreciation rates than the average rates applicable to the distribution system. Depreciation expense rose 8.9 percent in 2002 due to normal growth of the utility's distribution system. Alagasco's expense for taxes other than income primarily reflects various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.
------------------------------------------------------------------------------------------- DECEMBER 31, December 31, September 30, Years ended (in thousands) 2003 2002 2001 Natural gas transportation and sales revenues $ 489,099 $ 424,431 $ 553,862 Cost of natural gas (236,037) (191,479) (329,572) Operations and maintenance (114,078) (109,115) (105,812) Depreciation (37,171) (33,682) (30,933) Income taxes (19,675) (17,825) (13,448) Taxes, other than income taxes (34,965) (30,785) (37,257) ------------------------------------------------------------------------------------------- Operating income $ 47,173 $ 41,545 $ 36,840 ------------------------------------------------------------------------------------------- Natural gas sales volumes (MMcf) Residential 27,248 26,358 31,064 Commercial and industrial-small 12,564 11,838 14,054 ------------------------------------------------------------------------------------------- Total natural gas sales volumes 39,812 38,196 45,118 Natural gas transportation volumes (MMcf) 55,623 59,644 53,989 ------------------------------------------------------------------------------------------- Total deliveries (MMcf) 95,435 97,840 99,107 ------------------------------------------------------------------------------------------- |
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 transition quarter, weather that was 30.1 percent warmer than the same period in the prior 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) Operations and maintenance (27,687) (26,837) Depreciation (8,151) (7,554) Income taxes (1,547) (2,094) Taxes, other than income taxes (7,155) (8,464) -------------------------------------------------------------------------------- Operating income $ 6,487 $ 6,498 -------------------------------------------------------------------------------- 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 2003 decreased $1.5 million largely due to a $32.1 million equity issuance completed in July 2003 which reduced short-term debt. Current maturities of long-term debt, lower short-term interest rates and $50 million of long-term debt issued by Energen in October 2003 also influenced interest expense in the period comparisons. In 2002, interest expense 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). The average daily outstanding balance under short-term credit facilities was $81.1 million in 2003. The average daily outstanding balance under short-term credit facilities was $85.6 million in 2002 as compared to $80.7 million in 2001.
Income tax expense increased in 2003 primarily due to higher pre-tax income and a higher effective tax rate. Income tax expense increased in 2002 and 2001 primarily due to higher pre-tax income. The Company's effective tax rates in 2002 and 2001 were lower than statutory federal tax rates primarily due to the recognition of nonconventional fuels tax credits. The Company recognized $14.2 million and $13.6 million of nonconventional fuels tax credits in 2002 and 2001, respectively. The Company's ability to generate nonconventional fuels tax credits on qualified production ended December 31, 2002, with the expiration of the credit. As of December 31, 2003, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $59.3 million.
TRANSITION PERIOD: Interest expense for the Company increased $0.4 million in 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. 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. The effective tax rate utilized in computing income tax expense reflected financial recognition of $3.5 million of nonconventional fuels tax credits as produced during the transition quarter.
FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $243.1 million, $213.5 million and $156.5 million in 2003, 2002 and 2001, respectively. Operating cash flow in 2003 benefited from significantly higher realized
commodity prices at Energen Resources; working capital needs at Alagasco in 2003 were affected by increased gas costs resulting in higher storage inventory balances. In 2002, operating cash flow benefited from significantly higher production volumes related to Energen Resources' property acquisition and decreased storage inventory balances at Alagasco. 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 2003, the Company made net investments of $190.4 million. Energen Resources invested $40.5 million in property acquisitions, $121.9 million for development costs including approximately $89 million to drill 347 gross development wells and $0.4 million for exploration. Energen Resources sold or traded certain properties during the current year, resulting in cash proceeds of $29.1 million. Utility expenditures in 2003 totaled $57.9 million and primarily represented system distribution expansion and support facilities, including information technology application projects. 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 for approximately $77 million. Energen Resources sold or traded certain properties during 2002, resulting in cash proceeds of $17.1 million. Utility expenditures in 2002 totaled $65.8 million. Cash used in investing activities totaled $174.4 million in 2001. Energen Resources invested $34.3 million for property acquisitions, $103.6 million for development of proved properties and $1.2 million for exploration during 2001. Energen Resources drilled 140 gross development wells for approximately $70 million. Energen Resources sold or traded certain properties during 2001, resulting in cash proceeds of $17.3 million. Utility expenditures for 2001 totaled $56.1 million, including approximately $3 million for a municipal acquisition.
During 2003, the Company added approximately 101 Bcfe of reserves from acquisitions and 135 Bcfe of reserves from discoveries and other additions primarily the result of unit downspacing that increased the number of available drilling locations for certain wells in the Black Warrior, San Juan and Permian basins. Energen Resources added approximately 389 Bcfe and 69 Bcfe of reserves in 2002 and 2001, respectively.
Net cash used in financing activities totaled $55.4 million in 2003. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. The sale of shares began May 9, 2003, and concluded on July 16, 2003, generating net proceeds of $32.1 million. In October 2003, Energen issued $50 million of long-term debt due October 1, 2013. The 5% coupon notes were priced at 99.557 percent to yield 5.057 percent. Long-term debt was reduced by $23 million for current maturities in 2003. In 2002, net cash provided by financing activities totaled $53 million. The Company utilized $85.9 million in short-term credit facilities to finance Energen Resources' acquisition strategy. Long-term debt was reduced by $21.2 million, including the 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. 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. For each of the years, net cash used in financing activities also reflected dividends paid to common stockholders and the issuance of common stock through the dividend reinvestment and direct stock purchase plan as well as the employee savings plans.
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 a total of $639.3 million for capital projects during the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001. Property acquisition expenditures totaled $259.3 million, development activities totaled $372.7 million, and exploratory expenditures totaled $1.9 million.
------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------- Capital and exploration expenditures for: Property acquisitions $ 40,486 $184,177 $ 319 $ 34,316 Development 121,889 122,494 24,757 103,574 Exploration 397 104 228 1,190 Other 1,548 1,880 464 1,477 ------------------------------------------------------------------------------------------------------- Total 164,320 308,655 25,768 140,557 ------------------------------------------------------------------------------------------------------- Less exploration expenditures charged to income 982 3,179 716 3,671 ------------------------------------------------------------------------------------------------------- Net capital expenditures $163,338 $305,476 $ 25,052 $136,886 ------------------------------------------------------------------------------------------------------- |
NATURAL GAS DISTRIBUTION: During the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001, Alagasco invested $192.7 million for capital projects: $128.1 million for normal expansion, replacements and support of its distribution system, $61.6 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 Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------- Capital and expenditures for: Renewals, replacements, system expansion and other $ 39,883 $ 43,029 $ 8,839 $ 36,340 Support facilities 18,023 22,786 4,034 16,733 Municipal gas system acquisition -- -- -- 3,017 ------------------------------------------------------------------------------------------------------- Total $ 57,906 $ 65,815 $ 12,873 $ 56,090 ------------------------------------------------------------------------------------------------------- |
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,
2003, Energen's EPS grew at an average compound rate of 21.9 percent a year. Over the next five years, Energen is targeting an average EPS growth rate over each rolling five-year period of approximately 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. The Company may periodically issue long-term debt and equity to replace short-term obligations to provide 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. Standard and Poor's last update in October 2003 confirmed Energen's and Alagasco's rating as A- with a stable outlook. In February 2003, Moody's Investors Service confirmed Energen's debt rating as Baa1 and Alagasco's debt rating as A1. While the Company expects to have ongoing access to its 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 expected increases in cash flows to help finance Energen Resources' acquisition strategy. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. In October 2003, the Company issued $50 million of long-term debt. These proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.
In 2004, Energen Resources plans to invest approximately $310 million, including $200 million in property acquisitions, $2 million in related acquisition development and $108 million in other development and exploratory activities. Included in this $108 million is approximately $77 million for the development of previously identified proved undeveloped reserves and approximately $4 million of exploratory exposure. Capital investment at Energen Resources in 2005 is expected to approximate $200 million for property acquisitions, $20 million for related acquisition development and $52 million for other development and exploration. Of this $52 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, 2008 is estimated to be approximately $1.4 billion, with $1.2 billion for property acquisitions and related development, $200 million for other development and $25 million for exploratory and other activities. During the five year period, Energen Resources anticipates spending approximately $137 million on development of previously identified proved undeveloped reserves and incurring approximately $16 million in exploratory exposure. Energen Resources' continued ability to invest in property acquisitions will be influenced significantly by industry trends, as the producing property acquisition market historically has been cyclical. Notwithstanding the estimated expenditures mentioned above, as an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time may pursue acquisitions that meet Energen's acquisition criteria which could result in capital expenditures different than those outlined above. These acquisitions or negotiations to sell, trade or otherwise dispose of properties may alter the aforementioned financing requirements.
During 2004, Alagasco plans to invest approximately $60 million in utility capital expenditures for normal distribution and support systems. Alagasco maintains an investment in storage gas that is expected to average approximately $35 million in 2004 but may vary depending upon the price of natural gas. Alagasco plans to invest approximately $53 million in utility capital expenditures during 2005. 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 December 31, 2008, Alagasco anticipates capital investments of approximately $275 million. During this period, the Company may issue approximately $50 million in long-term debt.
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, 2003.
---------------------------------------------------------------------------------------------------------- PAYMENTS DUE BY PERIOD ------------------------------------------------------------------ LESS THAN AFTER (in thousands) TOTAL 1 YEAR 1 - 3 YEARS 4 - 5 YEARS 5 YEARS ---------------------------------------------------------------------------------------------------------- Short-term cash obligations $ 11,000 $ 11,000 $ -- $ -- $ -- Long-term cash obligations (1) 564,533 10,000 37,000 20,000 497,533 Purchase obligations (2) 242,312 49,227 147,138 37,824 8,123 Capital lease obligations -- -- -- -- -- Operating leases 44,163 3,388 8,151 4,185 28,439 ---------------------------------------------------------------------------------------------------------- Total contractual cash obligations $862,008 $ 73,615 $192,289 $ 62,009 $534,095 ---------------------------------------------------------------------------------------------------------- |
(1) Long-term cash obligations include $1.7 million of unamortized debt discounts as of December 31, 2003.
(2) Certain of the Company's long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $240 million through October 2013. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 55.1 Bcf through December 2006.
Alagasco has an agreement with a financial institution whereby it may sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $15 million as further described in Note 8. The fair value of these guarantees is not significant to the Company and is recorded as a non-current other liability. Effective February 1, 2004, Alagasco is no longer selling its installment receivables.
OUTLOOK
OIL AND GAS OPERATIONS: Energen Resources plans to continue to implement its acquisition and development program with capital spending in 2004 and 2005 as outlined above. Production in 2004 is estimated to be approximately 85 Bcfe, including 81.6 Bcfe of estimated production from proved reserves owned at December 31, 2003. In 2005, production is estimated to reach approximately 97 Bcfe, including approximately 77 Bcfe produced from proved reserves currently owned.
In the event Energen Resources is unable to fully invest its planned acquisition, development and exploratory expenditures, future operating revenues, production and proved reserves could be negatively affected. Energen Resources' major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, national supply and demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas.
Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its exposure to oil, natural gas and natural gas liquids production. In addition, Alagasco periodically 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.
Energen Resources has entered into the following transactions for 2004 and subsequent years:
-------------------------------------------------------------------------------- PRODUCTION TOTAL HEDGED AVERAGE CONTRACT PERIOD VOLUMES PRICE DESCRIPTION -------------------------------------------------------------------------------- NATURAL GAS -------------------------------------------------------------------------------- 2004 15.8 Bcf $4.83 Mcf NYMEX Swaps * 1.7 Bcf $5.60 Mcf NYMEX Swaps 20.6 Bcf $4.17 Mcf Basin Specific Swaps * 4.3 Bcf $5.09 Mcf Basin Specific Swaps 2.4 Bcf $4.05 - $4.44 Mcf NYMEX Collars 2005 1.2 Bcf $3.75 Mcf NYMEX Swaps 6.0 Bcf $3.96 Mcf Basin Specific Swaps * 4.2 Bcf $4.70 Mcf Basin Specific Swaps -------------------------------------------------------------------------------- OIL -------------------------------------------------------------------------------- 2004 1,428 MBbl $27.75 Bbl NYMEX Swaps 360 MBbl $27.85 Bbl West Texas Sour (WTS) Swaps * 428 MBbl $30.29 Bbl NYMEX Swaps * 646 MBbl $27.62 Bbl WTS Swaps 2005 * 300 MBbl $30.50 Bbl NYMEX Swaps -------------------------------------------------------------------------------- OIL BASIS DIFFERENTIAL -------------------------------------------------------------------------------- 2004 300 MBbl ** Basis Swaps * 60 MBbl ** Basis Swaps -------------------------------------------------------------------------------- NATURAL GAS LIQUIDS -------------------------------------------------------------------------------- 2004 37 MMGal $0.41 Gal Liquids Swaps -------------------------------------------------------------------------------- |
* Contract entered into subsequent to December 31, 2003
** Average contract prices not meaningful due to the varying nature of each contract
The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the market value of crude oil, natural gas and natural gas liquids may have on the fair value of its derivative instruments. This analysis measured the impact on the commodity derivative instruments and, thereby, did not consider the underlying exposure related to the commodity. At December 31, 2003, the Company estimated that a 10 percent increase or decrease in the commodities prices would have resulted in a $29.1 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, 2002 and 2001, the Company estimated that a 10 percent increase in the commodities prices would have resulted in a $27.2 million and a $2.1 million change, respectively, 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 and a $2.1 million change, respectively, in the fair value of open derivative contracts. The hypothetical change in fair value was calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes and did not include the variance in basis or the impact of related taxes on actual cash prices.
NATURAL GAS DISTRIBUTION: The extension of RSE in June 2002 provides Alagasco the opportunity to continue earning an allowed ROE between 13.15 percent and 13.65 percent through January 1, 2008. Under the terms of that extension, RSE will continue beyond that date, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue its operation. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. Also as discussed in Note 2, the utility's CCM is based in part on the number of customers and the rate of inflation. Continued low inflation, significantly higher gas prices resulting in increased bad debt expense and/or the lack of customer growth could impact the utility's ability to manage its O&M expense per customer sufficiently for the inflation-based cost control requirements of RSE and may result in an average return on equity lower than the allowed range of return. Over this period, Alagasco has the potential for net income growth as the investment in additional utility plant affects the level of equity required in the business. The utility continues to rely on rate flexibility to effectively prevent bypass of its distribution system.
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 fair value as either assets or liabilities on the balance sheet. Gains or losses are passed through to customers using the mechanisms of the GSA in compliance with its APSC-approved tariff. In accordance with SFAS No. 71, Alagasco had recorded a current regulatory asset of $0.3 million, a current regulatory liability of $17 million and a noncurrent regulatory liability of $8.7 million representing the fair value of derivatives as of December 31, 2003.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS: Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. The 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 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, results of operation and cash flows; furthermore, such risk mitigation activities may cause the Company's financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk-mitigation assumes that counterparties maintain satisfactory credit quality.
Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, in that the Company's oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. 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. Energen Resources monitors the credit quality for its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil and gas purchasers account for approximately 15%, 13% and 12%, respectively, of Energen Resources' estimated 2004 production. Energen Resources' other purchasers each buy less than 11% of production.
RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," were issued by the FASB in June 2001 and became effective on July 1, 2001, and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142 establishes new guidelines in accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain intangible assets that have indefinite useful lives are not amortized, but rather are reviewed annually for impairment. The appropriate application of SFAS No. 141 and SFAS No. 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is currently being considered. One interpretation relative to these standards is that oil and gas mineral rights for both undeveloped and developed leaseholds could be classified separately from oil and gas properties as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. In addition, the disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements. The Company anticipates that this interpretation of SFAS No. 141 and SFAS No. 142 would only affect balance sheet classifications of oil and gas leaseholds. Results of operations and cash flows are not anticipated to be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Company will continue to evaluate the impact of the application of these standards as further guidance is provided.
The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), "Accounting for Stock-Based Compensation," prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to four years; therefore, the cost related to stock-based employee compensation included in the determination of net income is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123.
In December 2003, the FASB revised SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits - an amendment of FASB Statements No. 87, 88 and 106." The revised Statement added additional disclosures relating to the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other postretirement plans and is effective for financial statements with fiscal years ending after December 15, 2003, with an exception for the disclosure of estimated future benefit payments effective for fiscal years ending after June 15, 2004. The Company has incorporated within this report the additional required disclosures (See Note 5).
On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Although the company anticipates that the benefits it pays after 2006 will be lower as a result of the new Medicare provisions, the retiree medical obligations and costs reported do not reflect the impact of this legislation. Deferring the recognition of the new Medicare provisions' impact is permitted by FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," due to open issues related to the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this item with respect to market risk is set forth in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations under the heading "Outlook" and in Note 8, Financial Instruments and Risk Management, in the Notes to Financial Statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Page ---- 1. Financial Statements ENERGEN CORPORATION Report of Independent Auditors.............................. 31 Consolidated Statements of Income for the years ended December 31, 2003and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001............ 32 Consolidated Balance Sheets as of December 31, 2003 and 2002........................................................ 33 Consolidated Statements of Shareholders' Equity for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001........................................................ 35 Consolidated Statements of Cash Flows for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001 ... 36 Notes to Financial Statements............................... 42 ALABAMA GAS CORPORATION Report of Independent Auditors.............................. 31 Statements of Income for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001........................... 37 Balance Sheets as of December 31, 2003 and 2002 ............ 38 Statements of Shareholder's Equity for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001... 40 Statements of Cash Flows for the years ended December 31, 2003 and 2002,the three months ended December 31, 2001, and the year ended September30, 2001........................ 41 Notes to Financial Statements............................... 42 2. Financial Statement Schedules ENERGEN CORPORATION Schedule II - Valuation and Qualifying Accounts............. 76 ALABAMA GAS CORPORATION Schedule II - Valuation and Qualifying Accounts............. 76 |
Schedules other than those listed above are omitted because they are not required or not applicable, or the required information is shown in the financial statements or notes thereto.
REPORT OF INDEPENDENT AUDITORS
TO THE BOARD OF DIRECTORS AND 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, 2003 and 2002, and the results of their operations and their cash flows for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the year ended September 30, 2001, 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. As discussed in Note 1 of the Notes to the Financial Statements, effective October 1, 2000, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities."
PricewaterhouseCoopers LLP
Birmingham, Alabama
March 2, 2004
REPORT OF INDEPENDENT AUDITORS
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, 2003 and 2002, and the results of its operations and its cash flows for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the year ended September 30, 2001, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Birmingham, Alabama
March 2, 2004
CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION
------------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands, except share data) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Oil and gas operations $ 353,122 $ 244,120 $ 46,954 $ 208,954 Natural gas distribution 489,099 424,431 96,678 553,862 ------------------------------------------------------------------------------------------------------------------------------- Total operating revenues 842,221 668,551 143,632 762,816 ------------------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas 233,823 189,810 45,291 327,531 Operations and maintenance 208,219 191,656 53,032 177,688 Depreciation, depletion and amortization 116,858 101,691 23,468 81,840 Taxes, other than income taxes 63,543 49,619 10,728 60,731 Accretion expense 1,890 1,819 -- -- ------------------------------------------------------------------------------------------------------------------------------- Total operating expenses 624,333 534,595 132,519 647,790 ------------------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 217,888 133,956 11,113 115,026 ------------------------------------------------------------------------------------------------------------------------------- OTHER INCOME (EXPENSE) Interest expense (42,262) (43,713) (10,634) (42,070) Other income 8,744 15,644 4,354 16,825 Other expense (9,977) (15,103) (4,385) (14,892) ------------------------------------------------------------------------------------------------------------------------------- Total other expense (43,495) (43,172) (10,665) (40,137) ------------------------------------------------------------------------------------------------------------------------------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 174,393 90,784 448 74,889 Income tax expense (benefit) 64,128 20,388 (3,282) 12,472 ------------------------------------------------------------------------------------------------------------------------------- INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 110,265 70,396 3,730 62,417 ------------------------------------------------------------------------------------------------------------------------------- DISCONTINUED OPERATIONS, NET OF TAXES Income (loss) from discontinued operations 973 (80) (72) 5,479 Gain (loss) on disposal (584) 543 -- -- ------------------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) FROM DISCONTINUED OPERATIONS 389 463 (72) 5,479 ------------------------------------------------------------------------------------------------------------------------------- CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAXES -- (2,220) -- -- ------------------------------------------------------------------------------------------------------------------------------- NET INCOME $ 110,654 $ 68,639 $ 3,658 $ 67,896 ------------------------------------------------------------------------------------------------------------------------------- DILUTED EARNINGS PER AVERAGE COMMON SHARE Continuing operations $ 3.09 $ 2.08 $ 0.12 $ 2.01 Discontinued operations 0.01 0.02 -- 0.17 Cumulative effect of change in accounting principle -- (0.07) -- -- ------------------------------------------------------------------------------------------------------------------------------- Net Income $ 3.10 $ 2.03 $ 0.12 $ 2.18 ------------------------------------------------------------------------------------------------------------------------------- BASIC EARNINGS PER AVERAGE COMMON SHARE Continuing operations $ 3.11 $ 2.09 $ 0.12 $ 2.03 Discontinued operations 0.01 0.02 -- 0.18 Cumulative effect of change in accounting principle -- (0.07) -- -- ------------------------------------------------------------------------------------------------------------------------------- Net Income $ 3.12 $ 2.04 $ 0.12 $ 2.21 ------------------------------------------------------------------------------------------------------------------------------- DILUTED AVERAGE COMMON SHARES OUTSTANDING 35,716,876 33,838,299 31,277,406 31,083,784 ------------------------------------------------------------------------------------------------------------------------------- BASIC AVERAGE COMMON SHARES OUTSTANDING 35,434,486 33,604,601 31,052,152 30,725,919 ------------------------------------------------------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
---------------------------------------------------------------------------------------------- DECEMBER 31, December 31, (in thousands) 2003 2002 ---------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 2,127 $ 4,804 Accounts receivable, net of allowance for doubtful accounts of $9,852 at December 31, 2003, and of $8,874 at December 31, 2002 172,915 139,356 Inventories, at average cost Storage gas inventory 40,654 23,668 Materials and supplies 7,677 8,335 Liquified natural gas in storage 3,475 3,671 Deferred income taxes 38,145 33,941 Prepayments and other 25,073 20,367 ---------------------------------------------------------------------------------------------- Total current assets 290,066 234,142 ---------------------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT Oil and gas properties, successful efforts method 1,197,340 1,103,472 Less accumulated depreciation, depletion and amortization 310,368 269,616 ---------------------------------------------------------------------------------------------- Oil and gas properties, net 886,972 833,856 ---------------------------------------------------------------------------------------------- Utility plant 883,225 825,421 Less accumulated depreciation 341,787 313,414 ---------------------------------------------------------------------------------------------- Utility plant, net 541,438 512,007 ---------------------------------------------------------------------------------------------- Other property, net 5,041 5,691 ---------------------------------------------------------------------------------------------- Total property, plant and equipment, net 1,433,451 1,351,554 ---------------------------------------------------------------------------------------------- OTHER ASSETS Deferred income taxes -- 16,333 Regulatory asset 18,082 14,744 Deferred charges and other 39,833 26,239 ---------------------------------------------------------------------------------------------- Total other assets 57,915 57,316 ---------------------------------------------------------------------------------------------- TOTAL ASSETS $1,781,432 $1,643,012 ---------------------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
----------------------------------------------------------------------------------------------- DECEMBER 31, December 31, (in thousands, except share data) 2003 2002 ----------------------------------------------------------------------------------------------- CAPITAL AND LIABILITIES CURRENT LIABILITIES Long-term debt due within one year $ 10,000 $ 23,000 Notes payable to banks 11,000 113,000 Accounts payable 135,319 103,964 Accrued taxes 28,551 27,936 Customers' deposits 17,884 17,404 Amounts due customers 8,571 8,458 Accrued wages and benefits 24,957 23,652 Regulatory liability 54,146 41,184 Other 37,303 34,710 ----------------------------------------------------------------------------------------------- Total current liabilities 327,731 393,308 ----------------------------------------------------------------------------------------------- DEFERRED CREDITS AND OTHER LIABILITIES Asset retirement obligation 26,515 27,235 Minimum pension liability 17,911 25,825 Regulatory liability 113,427 96,219 Deferred income taxes 33,200 -- Other 10,774 4,661 ----------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 201,827 153,940 ----------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES ----------------------------------------------------------------------------------------------- CAPITALIZATION Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized -- -- Common shareholders' equity Common stock, $0.01 par value; 75,000,000 shares authorized, 36,223,531 shares outstanding at December 31, 2003, and 34,745,477 shares outstanding at December 31, 2002 362 347 Premium on capital stock 367,765 320,060 Capital surplus 2,802 2,802 Retained earnings 360,001 275,266 Accumulated other comprehensive income (loss), net of tax Unrealized gain (loss) on hedges (21,714) (10,471) Minimum pension liability (8,881) (4,340) Deferred compensation on restricted stock (1,258) (770) Deferred compensation plan 17,063 10,348 Treasury stock, at cost; 415,869 shares and 358,228 shares at December 31, 2003 and 2002, respectively (17,108) (10,432) ----------------------------------------------------------------------------------------------- Total common shareholders' equity 699,032 582,810 Long-term debt 552,842 512,954 ----------------------------------------------------------------------------------------------- Total capitalization 1,251,874 1,095,764 ----------------------------------------------------------------------------------------------- TOTAL CAPITAL AND LIABILITIES $ 1,781,432 $ 1,643,012 ----------------------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
ENERGEN CORPORATION
(in thousands, except share amounts)
--------------------------------------------------------------------------------------------------------------------------- COMMON STOCK ------------ NUMBER OF PAR PREMIUM ON CAPITAL RETAINED SHARES VALUE CAPITAL STOCK SURPLUS EARNINGS --------------------------------------------------------------------------------------------------------------------------- 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 income 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 Net income 110,654 Other comprehensive income (loss): Current period change in fair value of derivative instruments, net of tax of ($29,019) Reclassification adjustment, net of tax of $21,830 Minimum pension liability, net of tax of ($2,445) Comprehensive income Purchase of treasury shares Shares issued for: Stock offerings 1,000,000 10 32,121 Dividend reinvestment plan 53,990 1 1,865 Employee benefit plans 424,064 4 12,033 Deferred compensation obligation Issuance of restricted stock Amortization of restricted stock Stock based compensation 270 Tax benefit from exercise of stock options 1,416 Cash dividends - $0.73 per share (25,919) --------------------------------------------------------------------------------------------------------------------------- BALANCE DECEMBER 31, 2003 36,223,531 $362 $367,765 $2,802 $ 360,001 --------------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------------- ACCUMULATED OTHER DEFERRED COMPREHENSIVE COMPENSATION DEFERRED INCOME RESTRICTED COMPENSATION TREASURY SHAREHOLDERS' (LOSS) STOCK PLAN STOCK EQUITY --------------------------------------------------------------------------------------------------------------------------- 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 (55,416) tax of ($35,430) (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 income 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 Net income 110,654 Other comprehensive income (loss): Current period change in fair value of derivative instruments, net of tax of ($29,019) (45,388) (45,388) Reclassification adjustment, net of tax of $21,830 34,145 34,145 Minimum pension liability, net of (4,541) (4,541) tax of ($2,445) ------- Comprehensive income 94,870 ------- Purchase of treasury shares (1,046) (1,046) Shares issued for: Stock offerings 32,131 Dividend reinvestment plan 491 2,357 Employee benefit plans 594 12,631 Deferred compensation obligation 6,715 (6,715) -- Issuance of restricted stock (1,564) (1,564) Amortization of restricted stock 1,076 1,076 Stock based compensation 270 Tax benefit from exercise of stock options 1,416 Cash dividends - $0.73 per share (25,919) --------------------------------------------------------------------------------------------------------------------------- BALANCE DECEMBER 31, 2003 $(30,595) $(1,258) $17,063 $(17,108) $ 699,032 --------------------------------------------------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
------------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net income $ 110,654 $ 68,639 $ 3,658 $ 67,896 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion and amortization 117,785 107,952 25,184 86,975 Deferred income taxes, net 54,632 10,915 (8,495) 5,349 Deferred investment tax credits, net (448) (448) (112) (448) Change in derivative fair value 735 (9,205) (174) (879) (Gain) loss on sale of assets (9,987) (3,738) 3,161 (4,716) Loss on properties held for sale 10,404 2,815 -- 3,821 Cumulative effect of change in accounting principle, net of taxes -- 2,220 -- -- Net change in: Accounts receivable (24,811) (27,104) (17,529) 19,565 Inventories (16,132) 27,344 7,239 (22,018) Accounts payable 12,860 28,600 2,442 16,544 Amounts due customers 4,052 626 11,637 (11,655) Other current assets and liabilities (5,533) 1,712 (4,813) 1,424 Other, net (11,084) 3,179 (837) (5,362) ------------------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 243,127 213,507 21,361 156,496 ------------------------------------------------------------------------------------------------------------------------------- INVESTING ACTIVITIES Additions to property, plant and equipment (219,593) (166,075) (37,752) (190,695) Acquisition, net of cash acquired -- (117,043) -- -- Proceeds from sale of assets 29,149 17,094 2,323 17,326 Other, net 30 (2,198) (252) (1,038) ------------------------------------------------------------------------------------------------------------------------------- Net cash (used in) investing activities (190,414) (268,222) (35,681) (174,407) ------------------------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES Payment of dividends on common stock (25,919) (23,927) (5,458) (21,103) Issuance of common stock 47,119 12,371 5,172 21,285 Purchase of treasury stock (1,046) (133) (1,245) (2,516) Reduction of long-term debt (23,000) (21,204) -- (36,267) Proceeds from issuance of long-term debt 49,778 -- -- 223,799 Debt issuance costs (322) -- -- (4,777) Net change in short-term debt (102,000) 85,930 17,000 (161,000) ------------------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities (55,390) 53,037 15,469 19,421 ------------------------------------------------------------------------------------------------------------------------------- Net change in cash and cash equivalents (2,677) (1,678) 1,149 1,510 Cash and cash equivalents at beginning of period 4,804 6,482 5,333 3,823 ------------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 2,127 $ 4,804 $ 6,482 $ 5,333 ------------------------------------------------------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
------------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES $ 489,099 $ 424,431 $ 96,678 $ 553,862 ------------------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas 236,037 191,479 45,651 329,572 Operations and maintenance 114,078 109,115 27,687 105,812 Depreciation 37,171 33,682 8,151 30,933 Income taxes Current 6,577 8,764 10,348 16,995 Deferred, net 13,546 9,509 (8,689) (3,099) Deferred investment tax credits, net (448) (448) (112) (448) Taxes, other than income taxes 34,965 30,785 7,155 37,257 ------------------------------------------------------------------------------------------------------------------------------- Total operating expenses 441,926 382,886 90,191 517,022 ------------------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 47,173 41,545 6,487 36,840 ------------------------------------------------------------------------------------------------------------------------------- OTHER INCOME (EXPENSE) Allowance for funds used during construction 948 1,336 122 2,098 Other income 4,132 5,520 1,596 5,978 Other expense (5,269) (6,280) (1,838) (6,585) ------------------------------------------------------------------------------------------------------------------------------- Total other income (expense) (189) 576 (120) 1,491 ------------------------------------------------------------------------------------------------------------------------------- INTEREST CHARGES Interest on long-term debt 12,815 13,153 3,327 8,803 Other interest charges 1,152 1,404 353 3,513 ------------------------------------------------------------------------------------------------------------------------------- Total interest charges 13,967 14,557 3,680 12,316 ------------------------------------------------------------------------------------------------------------------------------- NET INCOME $ 33,017 $ 27,564 $ 2,687 $ 26,015 ------------------------------------------------------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
BALANCE SHEETS
ALABAMA GAS CORPORATION
-------------------------------------------------------------------------------- DECEMBER 31, December 31, (in thousands) 2003 2002 -------------------------------------------------------------------------------- ASSETS PROPERTY, PLANT AND EQUIPMENT Utility plant $ 883,225 $ 825,421 Less accumulated depreciation 341,787 313,414 -------------------------------------------------------------------------------- Utility plant, net 541,438 512,007 -------------------------------------------------------------------------------- Other property, net 331 842 -------------------------------------------------------------------------------- CURRENT ASSETS Cash 1,440 2,818 Accounts receivable Gas 134,376 108,630 Merchandise 1,210 1,748 Other 1,018 656 Allowance for doubtful accounts (9,100) (8,200) Inventories, at average cost Storage gas inventory 40,654 23,668 Materials and supplies 5,527 5,049 Liquified natural gas in storage 3,475 3,671 Regulatory asset 251 -- Deferred income taxes 17,650 20,093 Prepayments and other 22,056 18,314 -------------------------------------------------------------------------------- Total current assets 218,557 176,447 -------------------------------------------------------------------------------- OTHER ASSETS Regulatory asset 18,082 14,744 Deferred charges and other 19,285 11,290 -------------------------------------------------------------------------------- Total other assets 37,367 26,034 -------------------------------------------------------------------------------- TOTAL ASSETS $ 797,693 $ 715,330 -------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
BALANCE SHEETS
ALABAMA GAS CORPORATION
---------------------------------------------------------------------------------- DECEMBER 31, December 31, (in thousands, except share data) 2003 2002 ---------------------------------------------------------------------------------- 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, 2003 and 2002, respectively 20 20 Premium on capital stock 31,682 31,682 Capital surplus 2,802 2,802 Retained earnings 215,869 182,852 ---------------------------------------------------------------------------------- Total common shareholder's equity 250,373 217,356 Long-term debt 169,533 169,533 ---------------------------------------------------------------------------------- Total capitalization 419,906 386,889 ---------------------------------------------------------------------------------- CURRENT LIABILITIES Long-term debt due within one year -- 15,000 Notes payable to banks 11,000 13,000 Accounts payable Trade 56,020 55,720 Affiliated companies 37,290 1,432 Accrued taxes 22,145 24,044 Customers' deposits 17,884 17,404 Amounts due customers 8,571 8,458 Accrued wages and benefits 6,247 5,710 Regulatory liability 54,146 41,184 Other 9,039 8,947 ---------------------------------------------------------------------------------- Total current liabilities 222,342 190,899 ---------------------------------------------------------------------------------- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 32,178 20,747 Minimum pension liability 6,988 18,661 Regulatory liability 113,427 96,219 Customer advances for construction and other 2,852 1,915 ---------------------------------------------------------------------------------- Total deferred credits and other liabilities 155,445 137,542 ---------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES ---------------------------------------------------------------------------------- TOTAL CAPITAL AND LIABILITIES $797,693 $715,330 ---------------------------------------------------------------------------------- |
STATEMENTS OF SHAREHOLDER'S EQUITY
ALABAMA GAS CORPORATION
---------------------------------------------------------------------------------------------------------------------- COMMON STOCK ------------ TOTAL (in thousands, except NUMBER OF PAR PREMIUM ON CAPITAL RETAINED SHAREHOLDER'S share amounts) SHARES VALUE CAPITAL STOCK SURPLUS EARNINGS EQUITY ---------------------------------------------------------------------------------------------------------------------- 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 Net income 33,017 33,017 ---------------------------------------------------------------------------------------------------------------------- BALANCE DECEMBER 31, 2003 1,972,052 $ 20 $ 31,682 $ 2,802 $ 215,869 $250,373 ---------------------------------------------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
------------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net income $ 33,017 $ 27,564 $ 2,687 $ 26,015 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation and amortization 37,171 33,682 8,151 30,933 Deferred income taxes, net 13,546 9,509 (8,689) (3,099) Deferred investment tax credits (448) (448) (112) (448) Net change in: Accounts receivable (15,923) (17,151) (24,648) 6,056 Inventories (17,268) 27,099 5,968 (20,351) Accounts payable 49 21,697 1,945 (7,298) Amounts due customers 4,052 626 11,637 (11,655) Other current assets and liabilities (4,140) (6,666) 1,191 7,692 Other, net (13,774) (1,447) (201) (2,231) ------------------------------------------------------------------------------------------------------------------------------- Net cash provided (used) by operating activities 36,282 94,465 (2,071) 25,614 ------------------------------------------------------------------------------------------------------------------------------- INVESTING ACTIVITIES Additions to property, plant and equipment (56,255) (64,257) (12,820) (53,749) Net advances from (to) parent company 35,858 (1,622) 3,990 (2,093) Other, net (263) (814) 143 (327) ------------------------------------------------------------------------------------------------------------------------------- Net cash (used in) investing activities (20,660) (66,693) (8,687) (56,169) ------------------------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES Payment of dividends on common stock -- (16,859) (5,425) (15,897) Reduction of long-term debt (15,000) (5,467) -- -- Proceeds from issuance of long-term debt -- -- -- 75,000 Debt issuance costs -- -- -- (3,709) Net change in short-term debt (2,000) (6,000) 18,000 (24,150) ------------------------------------------------------------------------------------------------------------------------------- Net cash provided (used) by financing activities (17,000) (28,326) 12,575 31,244 ------------------------------------------------------------------------------------------------------------------------------- Net change in cash and cash equivalents (1,378) (554) 1,817 689 Cash and cash equivalents at beginning of period 2,818 3,372 1,555 866 ------------------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 1,440 $ 2,818 $ 3,372 $ 1,555 ------------------------------------------------------------------------------------------------------------------------------- |
The accompanying Notes to Financial Statements are an integral part of these statements.
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Energen Corporation (Energen or the Company) is a diversified energy holding company engaged primarily in the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations) and in the purchase, distribution, and sale of natural gas principally in central and north Alabama (natural gas distribution). The following is a description of the Company's significant accounting policies and practices.
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 is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes.
A. PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years' financial statements to the current-year presentation.
B. OIL AND GAS OPERATIONS
PROPERTY AND RELATED DEPLETION: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. 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 units-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, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property's over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no material production imbalances at December 31, 2003.
DERIVATIVE COMMODITY INSTRUMENTS: Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments 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.
On October 1, 2000 the Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (as amended), "Accounting for Derivative Instruments and Hedging Activities," which requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change. As of December 31, 2003, 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, 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 December 31, 2005.
C. NATURAL GAS DISTRIBUTION
UTILITY PLANT AND DEPRECIATION: Property, plant and equipment is stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets is charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided on the straight-line method over the estimated useful lives of utility property at rates established by the Alabama Public Service Commission (APSC). Approved depreciation rates averaged approximately 4.5 percent in the years ended December 31, 2003 and 2002, for the three months ended December 31, 2001 and for the year ended September 30, 2001.
INVENTORIES: Inventories, which consist primarily of gas stored underground, are stated at average cost.
OPERATING REVENUE AND GAS COSTS: Alagasco records natural gas distribution revenues in accordance with its tarriff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability.
REGULATORY ACCOUNTING: Alagasco is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." In general, SFAS No. 71 requires utilities to capitalize or defer certain costs or revenues, based upon approvals received from regulatory authorities, to be recovered from or refunded to customers in future periods.
DERIVATIVE COMMODITY INSTRUMENTS: Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco's APSC approved tariff and accordingly are recognized as a regulatory asset or liability 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 Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 -------------------------------------------------------------------------------------------- Taxes on revenues $ 25,218 $ 21,591 $ 4,969 $ 28,766 -------------------------------------------------------------------------------------------- |
D. INCOME TAXES
The Company uses the liability method of accounting for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are allocated to appropriate subsidiaries using the separate return method.
E. 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 adopted the fair value recognition provisions of SFAS No. 123 (as amended), "Accounting for Stock-Based Compensation," prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to six years; therefore, the cost related to stock-based employee compensation included in the determination of net income is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on net income and diluted earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period:
------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------- Net income As reported $110,654 $68,639 $3,658 $67,896 Stock based compensation expense included in reported net income, net of tax 4,553 1,811 573 1,820 Stock based compensation expense determined under fair value based method, net of tax (3,904) (2,413) (539) (2,158) ------------------------------------------------------------------------------------------------------------------------- Pro forma $111,303 $68,037 $3,692 $67,558 ------------------------------------------------------------------------------------------------------------------------- Diluted earnings per average common share As reported $3.10 $2.03 $0.12 $2.18 Pro forma $3.12 $2.01 $0.12 $2.17 ------------------------------------------------------------------------------------------------------------------------- Basic earnings per average common share As reported $3.12 $2.04 $0.12 $2.21 Pro forma $3.14 $2.02 $0.12 $2.20 ------------------------------------------------------------------------------------------------------------------------- |
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 for the year ended December 31, 2003 and the three months ended December 31, 2001, and 36.35 percent for the year ended September 30, 2001; a risk-free interest rate of 2.36 percent, 3.36 percent and 4.14 percent for the year ended December 31, 2003, the three months ended December 31, 2001, and the year ended September 30, 2001, respectively; and a dividend yield of 3.12 percent and 2.55 percent on options without dividend equivalents for the three months ended December 31, 2001, and the year ended September 30, 2001, respectively. Options with dividend equivalents assume no dividend yield for all periods presented. The weighted-average grant-date fair value for options granted with dividend equivalents during the year ended December 31, 2003 was $12.10; $9.74 for options granted with dividend equivalents and $6.52 for options granted without dividend equivalents during the three months ended December 31, 2001; $12.66 for options granted with dividend equivalents and $9.27 for options granted without dividend equivalents during the year-ended September 30, 2001. 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. The major estimates and assumptions identified by management include but are not limited to estimates of physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," will continue as the applicable accounting standard for the Company's regulated operations and estimates used in determining the Company's obligations under its employee pension plans. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.
2. REGULATORY MATTERS
All of Alagasco's utility operations are conducted in the state of Alabama. Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended with modifications in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended Alagasco's rate-setting methodology, RSE, without change, for a six-year period through January 1, 2008. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operations. Alagasco'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. As of September 30, 2003, Alagasco had a $3 million reduction in revenues to bring the return on average equity within the allowed range of return. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco's operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. The increase in O&M expense per customer was slightly above the index range for the rate year ended September 30, 2003 and 2002; as a result, the utility returned to customers $0.1 million pre-tax and $0.3 million pre-tax through rate adjustments under the provisions of RSE. An $11.2 million, $12.7 million and $16.3 million annual increase in revenues became effective December 1, 2003, 2002, and 2001, respectively, under RSE.
Alagasco calculates a temperature adjustment to customers' monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco's earnings. Adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. 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 $3.5 million at December 31, 2003 and $3 million at December 31, 2002, are included in the consolidated financial statements.
At December 31, 2003 and 2002, Alagasco had a $21.7 million and an $18.7 million, respectively, gross additional minimum pension liability related to its salaried and union pension plans. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," Alagasco has established a regulatory asset of $18.1 million and $14.7 million for the accrued obligation to be recovered through rates in future periods at December 31, 2003 and 2002, respectively.
During 2003, Alagasco revised its balance sheet presentation to reflect the margin on service delivered to cycle customers but not yet billed in current assets as accounts receivable with a corresponding regulatory liability and has reclassified deferred gas costs as accounts receivable. As a result, current assets and regulatory liability increased $26.1 million and $17.4 million at December 31, 2003 and 2002, respectively.
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, 2003 and 2002, the net acquisition adjustments were $12.6 million and $13.8 million, respectively.
3. LONG-TERM DEBT AND NOTES PAYABLE
Long-term debt consisted of the following:
--------------------------------------------------------------------------------------------------------- (in thousands) DECEMBER 31, 2003 December 31, 2002 --------------------------------------------------------------------------------------------------------- Energen Corporation: Medium-term Notes, interest ranging from 6.81% to 8.09%, for notes redeemable July 14, 2004, to February 15, 2028 $ 345,000 $ 353,000 5% Notes, redeemable October 1, 2013 50,000 -- Alabama Gas Corporation: Medium-term Notes, interest ranging from 6.35% to 7.97%, for notes redeemable July 15, 2005, to September 23, 2026 95,000 110,000 6.25% Notes, redeemable September 1, 2016 39,758 39,758 6.75% Notes, redeemable September 1, 2031 34,775 34,775 --------------------------------------------------------------------------------------------------------- Total 564,533 537,533 Less amounts due within one year 10,000 23,000 Less unamortized debt discount 1,691 1,579 --------------------------------------------------------------------------------------------------------- Total $ 552,842 $ 512,954 --------------------------------------------------------------------------------------------------------- |
The aggregate maturities of Energen's long-term debt for the next five years are as follows:
-------------------------------------------------------------------------------- Years ending December 31, (in thousands) -------------------------------------------------------------------------------- 2004 2005 2006 2007 2008 -------------------------------------------------------------------------------- $ 10,000 $ 10,000 $ 20,000 $ 7,000 $ 15,000 -------------------------------------------------------------------------------- |
The aggregate maturities of Alagasco's long-term debt for the next five years are as follows:
-------------------------------------------------------------------------------- Years ending December 31, (in thousands) -------------------------------------------------------------------------------- 2004 2005 2006 2007 2008 -------------------------------------------------------------------------------- $ -- $ 10,000 $ 10,000 $ 7,000 $ 5,000 -------------------------------------------------------------------------------- |
At December 31, 2003, 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, 2003. 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, 2003, 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:
----------------------------------------------------------------------------------------------- (in thousands) DECEMBER 31, 2003 December 31, 2002 ----------------------------------------------------------------------------------------------- Energen outstanding $ -- $100,000 Alagasco outstanding 11,000 13,000 ----------------------------------------------------------------------------------------------- Notes payable to banks 11,000 113,000 Available for borrowings 256,000 154,000 ----------------------------------------------------------------------------------------------- Total $267,000 $267,000 ----------------------------------------------------------------------------------------------- Maximum amount outstanding at any month-end $ 83,000 $113,000 |
Average daily amount outstanding $ 81,121 $ 85,644 Weighted average interest rates based on: Average daily amount outstanding 1.71% 2.28% Amount outstanding at year-end 1.42% 1.88% ----------------------------------------------------------------------------------------------- Alagasco maximum amount outstanding at any month-end $ 11,000 $ 21,000 Alagasco average daily amount outstanding $ 9,592 $ 3,304 Alagasco weighted average interest rates based on: Average daily amount outstanding 1.53% 2.18% Amount outstanding at year-end 1.42% 1.78% ----------------------------------------------------------------------------------------------- |
Energen's total interest expense was $42,262,000 and $43,713,000 for the years ended December 31, 2003 and 2002, respectively, $10,634,000 for the three months ended December 31, 2001 and $42,070,000 for the year ended September 31, 2001. Total interest expense at Alagasco was $13,967,000 and $14,557,000 for the years ended December 31, 2003 and 2002, respectively, $3,680,000 for the three months ended December 31, 2001 and $12,316,000 for the year ended September 30, 2001.
4. INCOME TAXES
The components of Energen's income taxes consisted of the following:
------------------------------------------------------------------------------------------------------------ Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------ Taxes estimated to be payable currently: Federal $ 8,904 $ 7,263 $ 3,774 $ 6,498 State 1,294 535 1,551 1,073 ------------------------------------------------------------------------------------------------------------ Total current 10,198 7,798 5,325 7,571 ------------------------------------------------------------------------------------------------------------ Taxes deferred: Federal 47,805 9,062 (7,211) 3,073 State 6,125 3,528 (1,396) 1,828 ------------------------------------------------------------------------------------------------------------ Total deferred 53,930 12,590 (8,607) 4,901 ------------------------------------------------------------------------------------------------------------ Total income tax expense (benefit) from continuing operations $ 64,128 $ 20,388 $ (3,282) $ 12,472 ------------------------------------------------------------------------------------------------------------ |
In addition, Energen recorded income tax expense (benefit), related to income from discontinued operations, of ($5,000) in current income tax benefit and $254,000 in deferred income tax expense for the year ended December 31, 2003, $2,418,000 in current income tax expense and ($2,123,000) in deferred income tax benefit for the year ended December 31, 2002, ($43,000) in current income tax benefit for the three months ended December 31, 2001, and $3,504,000 in current income tax expense for the year ended September 30, 2001.
The components of Alagasco's income taxes consisted of the following:
------------------------------------------------------------------------------------------------------------ Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------ Taxes estimated to be payable currently: Federal $ 5,827 $ 7,763 $ 9,167 $ 15,456 State 750 1,001 1,181 1,539 ------------------------------------------------------------------------------------------------------------ Total current 6,577 8,764 10,348 16,995 ------------------------------------------------------------------------------------------------------------ Taxes deferred: Federal 11,549 7,974 (7,807) (3,193) State 1,549 1,087 (994) (354) ------------------------------------------------------------------------------------------------------------ Total deferred 13,098 9,061 (8,801) (3,547) ------------------------------------------------------------------------------------------------------------ Total income tax expense from continuing Operations $ 19,675 $ 17,825 $ 1,547 $ 13,448 ------------------------------------------------------------------------------------------------------------ |
Temporary differences and carryforwards which gave rise to a significant portion of Energen's and Alagasco's deferred tax assets and liabilities for 2003, 2002 and 2001 were as follows:
-------------------------------------------------------------------------------------------------------------- Energen Corporation -------------------------------------------------------------------------------------------------------------- (in thousands) DECEMBER 31, 2003 December 31, 2002 -------------------------------------------------------------------------------------------------------------- CURRENT NONCURRENT Current Noncurrent ------------------------------------------------------------- Deferred tax assets: Minimum tax credit $ -- $ 59,313 $ -- $ 64,756 Pension and other costs -- 8,093 5,326 7,056 Unbilled and deferred revenue 10,578 -- 8,690 -- Enhanced stability reserve and other regulatory costs 1,346 -- 1,217 -- Allowance for doubtful accounts 3,611 -- 3,316 -- Insurance accruals 2,946 -- 2,736 -- Compensation accruals 3,639 -- 2,789 -- Inventories 1,001 -- 1,204 -- Other comprehensive income 12,548 6,116 5,980 3,053 Other, net 2,851 556 2,792 2,153 -------------------------------------------------------------------------------------------------------------- Total deferred tax assets 38,520 74,078 34,050 77,018 -------------------------------------------------------------------------------------------------------------- Deferred tax liabilities: Depreciation and basis differences -- 99,185 -- 53,622 Minimum pension liability -- 8,093 -- 7,056 Other comprehensive income -- -- -- -- Other, net 375 -- 109 7 -------------------------------------------------------------------------------------------------------------- Total deferred tax liabilities 375 107,278 109 60,685 -------------------------------------------------------------------------------------------------------------- Net deferred tax assets (liabilities) $ 38,145 $ (33,200) $ 33,941 $ 16,333 -------------------------------------------------------------------------------------------------------------- |
-------------------------------------------------------------------------------------------------------------- Alabama Gas Corporation -------------------------------------------------------------------------------------------------------------- (in thousands) DECEMBER 31, 2003 December 31, 2002 -------------------------------------------------------------------------------------------------------------- CURRENT NONCURRENT Current Noncurrent ------------------------------------------------------------- Deferred tax assets: Pension and other costs $ -- $ 8,093 $ 823 $ 7,056 Unbilled and deferred revenue 10,578 -- 8,690 -- Enhanced stability reserve and other regulatory costs 1,346 -- 1,217 -- Allowance for doubtful accounts 3,441 -- 3,100 -- Insurance accruals 2,503 -- 2,330 -- Compensation accruals 2,216 -- 1,680 -- Inventories 835 -- 1,171 -- Other, net 1,241 486 1,093 791 -------------------------------------------------------------------------------------------------------------- Total deferred tax assets 22,160 8,579 20,104 7,847 -------------------------------------------------------------------------------------------------------------- Deferred tax liabilities: Depreciation and basis differences -- 32,664 -- 21,538 Pension and other costs 4,498 -- -- -- Minimum pension liability -- 8,093 -- 7,056 Other, net 12 -- 11 -- -------------------------------------------------------------------------------------------------------------- Total deferred tax liabilities 4,510 40,757 11 28,594 -------------------------------------------------------------------------------------------------------------- Net deferred tax assets (liabilities) $ 17,650 $ (32,178) $ 20,093 $ (20,747) -------------------------------------------------------------------------------------------------------------- |
The Company files a consolidated federal income tax return with all of its subsidiaries. As of December 31, 2003,
the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $59.3 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:
-------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 -------------------------------------------------------------------------------------------------------------------- Income tax expense from continuing operations at statutory federal income tax rate $ 61,038 $ 31,774 $ 157 $ 26,211 Increase (decrease) resulting from: Nonconventional fuels tax credits -- (14,165) (3,481) (13,588) Enhanced oil recovery tax credits (469) -- -- (25) Deferred investment tax credits (448) (448) (112) (448) State income taxes, net of federal income tax benefit 5,108 2,453 41 1,518 Other, net (1,101) 774 113 (1,196) -------------------------------------------------------------------------------------------------------------------- Total income tax expense (benefit) from continuing operations $ 64,128 $ 20,388 $ (3,282) $ 12,472 -------------------------------------------------------------------------------------------------------------------- Effective income tax rate (%) 36.77 22.46 -- 16.65 -------------------------------------------------------------------------------------------------------------------- |
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 Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 -------------------------------------------------------------------------------------------------------------------- Income tax expense from continuing operations at statutory federal income tax rate $ 18,442 $ 15,886 $ 1,482 $ 13,812 Increase (decrease) resulting from: Deferred investment tax credits (448) (448) (112) (448) State income taxes, net of federal income tax benefit 1,480 1,236 116 799 Other, net 201 1,151 61 (715) -------------------------------------------------------------------------------------------------------------------- Total income tax expense from continuing operations $ 19,675 $ 17,825 $ 1,547 $ 13,448 -------------------------------------------------------------------------------------------------------------------- Effective income tax rate (%) 37.34 39.27 36.54 34.08 -------------------------------------------------------------------------------------------------------------------- |
5. EMPLOYEE BENEFIT PLANS
The Company has two defined benefit non-contributory pension plans: Plan A covers a majority of the employees and Plan B covers employees under certain labor union agreements. Benefits are based on years of service and final earnings for Plan A. Plan B provides benefits based on years of service and flat dollar amounts. The Company's policy is to use the projected unit credit actuarial method for funding and financial reporting purposes. For its pension plans, Energen used a September 30 measurement date.
The status of the plans was as follows:
------------------------------------------------------------------------------------------------------------- (in thousands) PLAN A ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Projected benefit obligation: Balance at beginning of period $ 101,399 $ 92,101 $ 90,613 Service cost 3,955 3,074 899 Interest cost 6,640 6,173 1,644 Actuarial loss (gain) 15,449 6,093 (46) Benefits paid (11,810) (6,042) (1,009) ------------------------------------------------------------------------------------------------------------- Balance at end of period 115,633 101,399 92,101 ------------------------------------------------------------------------------------------------------------- Plan assets: Fair value of plan assets at beginning of period 67,594 67,967 74,486 Actual return (loss) on plan assets 14,252 (5,331) (5,510) Employer contributions 19,900 11,000 -- Benefits paid (11,810) (6,042) (1,009) ------------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of period 89,936 67,594 67,967 ------------------------------------------------------------------------------------------------------------- Amounts recognized in the consolidated balance sheets: Funded status of plan (25,697) (33,805) (24,134) Prepaid pension costs (14,087) -- -- Unrecognized actuarial loss (gain) 37,991 30,565 12,996 Unrecognized prior service cost 1,793 2,027 2,262 Unrecognized net transition obligation (asset) -- -- (196) ------------------------------------------------------------------------------------------------------------- Accrued pension asset (liability) $ -- $ (1,213) $ (9,072) ------------------------------------------------------------------------------------------------------------- Accumulated benefit obligation $ 94,476 $ 83,871 $ 73,725 ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- (in thousands) PLAN B ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Projected benefit obligation: Balance at beginning of period $ 21,988 $ 17,945 $ 17,949 Service cost 491 396 80 Interest cost 1,417 1,422 320 Plan amendment -- 1,781 -- Actuarial loss (gain) 2,190 1,912 58 Benefits paid (1,799) (1,468) (462) ------------------------------------------------------------------------------------------------------------- Balance at end of period 24,287 21,988 17,945 ------------------------------------------------------------------------------------------------------------- Plan assets: Fair value of plan assets at beginning of period 15,688 18,420 20,666 Actual return (loss) on plan assets 2,946 (1,264) (1,784) Employer contributions 4,000 -- -- Benefits paid (1,799) (1,468) (462) ------------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of period 20,835 15,688 18,420 ------------------------------------------------------------------------------------------------------------- Amounts recognized in the consolidated balance sheets: Funded status of plan (3,452) (6,300) 475 Prepaid pension costs (3,609) -- -- Unrecognized actuarial loss (gain) 5,120 4,315 (481) Unrecognized prior service cost 1,941 2,295 869 Unrecognized net transition obligation (asset) -- -- 43 Company contribution 3,200 -- -- ------------------------------------------------------------------------------------------------------------- Accrued pension asset (liability) $ 3,200 $ 310 $ 906 ------------------------------------------------------------------------------------------------------------- Accumulated benefit obligation $ 24,287 $ 21,988 $ 17,945 ------------------------------------------------------------------------------------------------------------- |
Weighted average rate assumptions used to determine the projected benefit obligations at the measurement date:
------------------------------------------------------------------------------------------------------------- PLAN A ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Discount rate 6.00% 6.75% 7.50% Rate of compensation increase 4.00% 4.50% 4.50% ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- PLAN B ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Discount rate 6.00% 6.75% 7.50% ------------------------------------------------------------------------------------------------------------- |
The components of net pension expense were:
------------------------------------------------------------------------------------------------------------- (in thousands) PLAN A ------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ------------------------------------------------------------- Components of net periodic benefit cost: Service cost $ 3,955 $ 3,074 $ 899 $ 2,219 Interest cost 6,640 6,173 1,643 5,458 Expected long-term return on assets (6,858) (6,145) (1,537) (5,778) Prior service cost amortization 235 235 59 235 Actuarial loss (gain) -- -- 2 422 Net periodic benefit cost 628 -- -- -- Transition amortization -- (196) (65) (808) ------------------------------------------------------------------------------------------------------------- Net periodic expense $ 4,600 $ 3,141 $ 1,001 $ 1,748 ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- (in thousands) PLAN B ------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ------------------------------------------------------------- Components of net periodic benefit cost: Service cost $ 491 $ 396 $ 80 $ 255 Interest cost 1,417 1,422 320 1,267 Expected long-term return on assets (1,561) (1,619) (406) (1,466) Prior service cost amortization 354 354 59 235 Actuarial loss (gain) -- -- -- (28) Transition amortization -- 43 14 57 ------------------------------------------------------------------------------------------------------------- Net periodic expense $ 701 $ 596 $ 67 $ 320 ------------------------------------------------------------------------------------------------------------- |
Net pension expense for Alagasco was $4,370,000 and $3,224,000 for the years ended December 31, 2003 and 2002, respectively, $918,000 for the three months ended December 31, 2001 and $1,812,000 for the year ended September 30, 2001.
Weighted average rate assumptions to determine net periodic benefit costs for the period ending:
------------------------------------------------------------------------------------------------------------- PLAN A ------------------------------------------------------------------------------------------------------------- DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ------------------------------------------------------------- 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, December 31, September 30, 2003 2002 2001 2001 ------------------------------------------------------------- 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% ------------------------------------------------------------------------------------------------------------- |
The Company's weighted-average pension plan asset allocations by asset category were as follows:
------------------------------------------------------------------------------------------------------------- PLAN A ------------------------------------------------------------------------------------------------------------- DECEMBER 31, DECEMBER 31, DECEMBER 31, 2003 2002 2001 ------------------------------------------------ Asset category: Equity securities 64% 54% 56% Debt securities 34% 40% 41% Other 2% 6% 3% ------------------------------------------------------------------------------------------------------------- Total 100% 100% 100% ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- PLAN B ------------------------------------------------------------------------------------------------------------- DECEMBER 31, DECEMBER 31, DECEMBER 31, 2003 2002 2001 ------------------------------------------------ Asset category: Equity securities 71% 66% 61% Debt securities 27% 31% 36% Other 2% 3% 3% ------------------------------------------------------------------------------------------------------------- Total 100% 100% 100% ------------------------------------------------------------------------------------------------------------- |
Equity securities for Plan A and Plan B do not include the Company's common stock.
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, 2003 and 2002, of $8 million and $21.7 million, respectively. Alagasco established a regulatory asset of $18.1 million and $14.7 million as of December 31, 2003 and 2002, respectively, 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 $3.7 million and $4.3 million at December 31, 2003 and 2002, respectively, and the balance of $2.5 million and $1.7 million at December 31, 2003 and 2002, respectively, was recorded as a component of accumulated other comprehensive income, net of tax. Subsequent to December 31, 2003, Energen contributed an additional $773,000 to Plan A assets and $46,000 to Plan B assets. The Company does not expect to make additional contributions to Plan A or Plan B assets during 2004.
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 years ended December 31, 2003 and 2002, the three months ended December 31, 2001 and the year ended September 30, 2001 was $386,000 $314,000, $(125,000), and $381,000, respectively. At September 30, 2003, 2002 and 2001, the accumulated post-retirement benefit obligation related to these agreements was $15,760,000, $10,093,000 and $9,198,000, respectively, and the projected benefit obligation was $23,203,000, $15,209,000 and $14,082,000, respectively. An accrued post-retirement benefit liability of $5,327,000 and $5,860,000 was recorded at December 31, 2003 and 2002, respectively. The Company has established and funded a trust of $5.9 million and $2.9 million as of December 31, 2003 and December 31, 2002, respectively. While intended for payment of this benefit, the trusts' assets remain subject to the claims of our creditors. The Company is not required to make any contributions to the supplemental retirement plans for 2004 but is currently evaluating possible discretionary contributions. For its supplemental retirement plans, the Company used a September 30 measurement date.
The Company recorded a minimum pension liability for supplemental retirement plans of $9.9 million and $4.2 million at December 31, 2003 and 2002, respectively. A corresponding amount was recognized as an intangible
asset for the unrecognized prior service cost of $76,000 and $81,000 at December 31, 2003 and 2002, respectively, and the balance was recorded as a component of accumulated other comprehensive income, net of tax, of $6.4 million and $2.6 million at December 31, 2003 and 2002, respectively.
In addition to providing pension benefits, the Company provides certain post-retirement health care and life insurance benefits. Substantially all of the Company's employees may become eligible for certain benefits if they reach normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability. For its post-retirement benefit programs, the Company used a September 30 measurement date.
The status of the post-retirement benefit programs was as follows:
------------------------------------------------------------------------------------------------------------- (in thousands) SALARIED EMPLOYEES ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Projected post-retirement benefit obligation: Balance at beginning of period $ 31,008 $ 35,888 $ 36,518 Service cost 823 831 261 Interest cost 2,045 2,120 649 Actuarial loss (gain) 7,262 (6,264) (1,274) Benefits paid (1,663) (1,567) (266) ------------------------------------------------------------------------------------------------------------- Balance at end of period 39,475 31,008 35,888 ------------------------------------------------------------------------------------------------------------- Plan assets: Fair value of plan assets at beginning of period 24,127 30,921 36,142 Actual return (loss) on plan assets 5,064 (7,073) (5,184) Company contribution 1,762 1,846 229 Benefits paid (1,663) (1,567) (266) ------------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of period 29,290 24,127 30,921 ------------------------------------------------------------------------------------------------------------- Amounts recognized in the consolidated balance sheets: Funded status of plan (10,185) (6,881) (4,967) Unrecognized actuarial loss (gain) 2,235 (1,259) (4,035) Unrecognized net transition obligation 7,126 7,809 8,491 Company contribution 650 265 410 ------------------------------------------------------------------------------------------------------------- Accrued benefit asset (liability) $ (174) $ (66) $ (101) ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- (in thousands) UNION EMPLOYEES ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Projected post-retirement benefit obligation: Balance at beginning of period $ 30,609 $ 40,077 $ 40,986 Service cost 412 807 218 Interest cost 2,010 2,800 727 Plan amendment (158) 248 -- Actuarial loss (gain) 3,256 (11,282) (1,450) Benefits paid (2,320) (2,041) (404) ------------------------------------------------------------------------------------------------------------- Balance at end of period 33,809 30,609 40,077 ------------------------------------------------------------------------------------------------------------- Plan assets: Fair value of plan assets at beginning of period 23,895 27,954 31,917 Actual return (loss) on plan assets 5,829 (4,159) (4,628) Company contribution 1,224 2,141 1,069 Benefits paid (2,320) (2,041) (404) ------------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of period 28,628 23,895 27,954 ------------------------------------------------------------------------------------------------------------- Amounts recognized in the consolidated balance sheets: Funded status of plan (5,181) (6,714) (12,123) |
Unrecognized actuarial loss (gain) (8,066) (7,869) (3,314) Unrecognized prior service costs 63 237 -- Unrecognized net transition obligation (asset) 12,526 13,811 15,096 Company contribution 500 392 494 ------------------------------------------------------------------------------------------------------------- Accrued benefit asset (liability) $ (158) $ (143) $ 153 ------------------------------------------------------------------------------------------------------------- |
Weighted average rate assumptions used to determine post-retirement benefit obligations at the measurement date:
------------------------------------------------------------------------------------------------------------- SALARIED EMPLOYEES ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Discount rate 6.00% 6.75% 7.50% Rate of compensation increase 4.00% 4.50% 4.50% ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- UNION EMPLOYEES ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Discount rate 6.00% 6.75% 7.50% ------------------------------------------------------------------------------------------------------------- |
Net periodic post-retirement benefit expense included the following:
------------------------------------------------------------------------------------------------------------- (in thousands) SALARIED EMPLOYEES ------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ------------------------------------------------------------- Components of net periodic benefit cost: Service cost $ 823 $ 831 $ 261 $ 1,095 Interest cost 2,045 2,120 649 2,327 Expected long-term return on assets (1,298) (1,678) (490) (1,994) Actuarial loss (gain) -- (434) (111) (1,098) Transition amortization 682 682 181 723 ------------------------------------------------------------------------------------------------------------- Net periodic expense $ 2,252 $ 1,521 $ 490 $ 1,053 ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- (in thousands) UNION EMPLOYEES ------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ------------------------------------------------------------- Components of net periodic benefit cost: Service cost $ 412 $ 807 $ 218 $ 733 Interest cost 2,010 2,800 727 3,095 Expected long-term return on assets (2,102) (2,472) (720) (1,723) Actuarial loss (gain) (283) (93) (57) (336) Prior service cost 16 12 -- -- Transition amortization 1,285 1,285 321 1,285 ------------------------------------------------------------------------------------------------------------- Net periodic expense $ 1,338 $ 2,339 $ 489 $ 3,054 ------------------------------------------------------------------------------------------------------------- |
Net periodic post-retirement benefit expense for Alagasco was $2,902,000, $3,493,000 for the years ended December 31, 2003 and 2002, respectively, $905,000 for the three months ended December 31, 2001 and $3,959,000 for the year ended September 30, 2001.
Weighted average rate assumptions to determine net periodic benefit costs for the period ending:
------------------------------------------------------------------------------------------------------------- SALARIED EMPLOYEES ------------------------------------------------------------------------------------------------------------- DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ------------------------------------------------------------- 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% 4.50% ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- UNION EMPLOYEES ------------------------------------------------------------------------------------------------------------- DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ------------------------------------------------------------- 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% ------------------------------------------------------------------------------------------------------------- |
Assumed post-65 health care cost trend rates used to determine the post-retirement benefit obligation at the measurement date:
------------------------------------------------------------------------------------------------------------- SALARIED EMPLOYEES ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Health care cost trend rate assumed for next year 10.00% 11.00% 7.50% Rate to which the cost trend rate is assumed to decline 6.00% 6.00% 7.50% Year that rate reaches ultimate rate 2008 2008 -- ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- UNION EMPLOYEES ------------------------------------------------------------------------------------------------------------- SEPTEMBER 30, September 30, September 30, 2003 2002 2001 ------------------------------------------------- Health care cost trend rate assumed for next year 10.00% 11.00% 7.50% Rate to which the cost trend rate is assumed to decline 6.00% 6.00% 7.50% Year that rate reaches ultimate rate 2008 2008 -- ------------------------------------------------------------------------------------------------------------- |
Assumed health care cost trend rates used in determining the accumulated post-retirement benefit obligation have a significant effect on the amounts reported. For example, increasing the weighted average health care cost trend rate by 1 percentage point would have the following effects:
------------------------------------------------------------------------------------------------------------- (in thousands) SALARIED EMPLOYEES ------------------------------------------------------------------------------------------------------------- 1-PERCENTAGE POINT INCREASE 1-PERCENTAGE POINT DECREASE ---------------------------------------------------------- Effect on total of service and interest cost $ 331 $ (271) Effect on net post-retirement benefit obligation $ 4,215 $ (3,330) ------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------- (in thousands) UNION EMPLOYEES ------------------------------------------------------------------------------------------------------------- 1-PERCENTAGE POINT INCREASE 1-PERCENTAGE POINT DECREASE ---------------------------------------------------------- Effect on total of service and interest cost $ 200 $ (172) Effect on net post-retirement benefit obligation $ 2,496 $ (2,070) ------------------------------------------------------------------------------------------------------------- |
The Company's weighted-average post-retirement benefit program asset allocations by asset category were as follows:
-------------------------------------------------------------------------------------------- SALARIED EMPLOYEES -------------------------------------------------------------------------------------------- DECEMBER 31, December 31, December 31, 2003 2002 2001 -------------------------------------------- Asset category: Equity securities 91% 90% 90% Debt securities 7% 9% 8% Other 2% 1% 2% -------------------------------------------------------------------------------------------- Total 100% 100% 100% -------------------------------------------------------------------------------------------- |
UNION EMPLOYEES
-------------------------------------------------------------------------------------------- UNION EMPLOYEES -------------------------------------------------------------------------------------------- DECEMBER 31, December 31, December 31, 2003 2002 2001 -------------------------------------------- Asset category: Equity securities 92% 89% 90% Debt securities 7% 8% 9% Other 1% 3% 1% -------------------------------------------------------------------------------------------- Total 100% 100% 100% -------------------------------------------------------------------------------------------- |
Equity securities for the post-retirement benefit programs do not include the Company's common stock.
The Company expects to contribute $3.7 million to post-retirement benefit program assets during 2004.
For both defined benefit plans and other post-retirement plans, certain financial assumptions are used in determining the Company's projected benefit obligation. These assumptions are examined periodically by the Company, and any required changes are reflected in the subsequent determination of projected benefit obligations.
The Company employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition, and market conditions.
The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Because the post-retirement plans have lower short and intermediate-term cash requirements and, accordingly, are less impacted by short-term investment performance volatility, the Company has elected to allocate a large percentage of investments in equity securities with higher expected returns. Investment managers are retained by the Company to manage separate pools of assets, and funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment mangers are performing satisfactorily.
The Company has a long-term disability plan covering most salaried employees. The Company had expense for the years ended December 31, 2003 and 2002 of $265,000 and $304,000, respectively. The Company had no expense for this plan in the three months ended December 31, 2001 and in the year ended September 30, 2001.
On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Although the company anticipates that the benefits it pays after 2006 will be lower as a result of the new Medicare provisions, the retiree medical obligations and costs reported do not reflect the impact of this legislation. Deferring the recognition of the new Medicare provisions' impact is permitted by FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," due to open issues related to the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information.
6. COMMON STOCK PLANS
A majority of Company employees are eligible to participate in the Energen Employee Savings Plan (ESP) by electing to contribute a portion of their compensation in the ESP. The Company matches a percentage of the contributions and may make additional contributions in the form of Company common stock (new issue or treasury shares) or funds for the purchase of Company common stock. Prior to January 1, 2004, employees were allowed to invest their elective contributions in Company stock. Effective January 1, 2004, the Company stock is no longer an investment option for new elective contributions and vested employees may diversify 100% of their ESP Company stock account into other ESP investment options regardless of whether the Company stock was acquired through elective contribution, Company match, Company contribution or reinvestment of earnings. In 2003 an additional 1,000,000 shares were reserved for issuance under the ESP resulting in total shares reserved for issuance of 1,005,239 at December 31, 2003. Expense associated with Company contributions to the ESP was $4,199,000 and $3,963,000 for the years ended December 31, 2003 and 2002, respectively, $803,000 for the three months ended December 31, 2001, and $3,597,000 for the year ended September 30, 2001.
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 Company performance criteria at the end of a four-year award period. Under the Plan, a portion of the performance units is payable with Company common stock. Under the Plan, 76,120 performance units were awarded in the year ended September 30, 2001; no additional performance units can be awarded after September 30, 2001, according to the provisions of the Plan. 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, 117,500 performance units were awarded in the year ended December 31, 2003 and 111,760 performance units were awarded in the three months ended December 31, 2001. The Company recorded expense of $5,653,100 and $2,136,250 for the years ended December 31, 2003 and 2002, respectively, $722,500 for the three months ended December 31, 2001, and $2,311,000 for the year ended September 30, 2001, 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 53,475 shares awarded in the year ended December 31, 2003, 22,775 shares awarded in the three months ended December 31, 2001 and 57,190 shares awarded in the year ended September 30, 2001. The sale or transfer of the shares is limited during restricted periods. The Company recorded expense of $1,076,000 and $743,000 for the years ended December 31, 2003 and 2002, respectively, $188,000 for the three months ended December 31, 2001 and $583,000 for the year ended September 30, 2001, 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:
---------------------------------------------------------------------------------------------------------------- 1997 STOCK INCENTIVE PLAN 1988 STOCK OPTION PLAN ---------------------------------------------------------------------------------------------------------------- Weighted Average Weighted Average Shares Exercise Price Shares Exercise Price ---------------------------------------------------------------------------------------------------------------- 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 ---------------------------------------------------------------------------------------------------------------- Granted 122,080 29.71 -- -- Exercised (122,153) 21.97 (32,514) 15.16 ---------------------------------------------------------------------------------------------------------------- Outstanding at December 31, 2003 485,420 $ 23.95 103,000 $ 14.39 ---------------------------------------------------------------------------------------------------------------- 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 Exercisable at December 31, 2003 243,000 $ 21.70 103,000 $ 14.39 ---------------------------------------------------------------------------------------------------------------- Remaining reserved for issuance at December 31, 2003 1,529,011 -- -- -- ---------------------------------------------------------------------------------------------------------------- |
The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), for all stock-based employee compensation on a prospective basis effective January 1, 2003. Of the total shares granted during 2003 55,300 had stock appreciation rights on which expense of $209,000 was recorded for the year ended December 31, 2003. The Company recorded expense of $269,000 during the year ended December 31, 2003, on the remaining 66,780 shares which had a weighted average grant-date fair value of $12.10.
The following table summarizes information about options outstanding as of December 31, 2003:
------------------------------------------------------------------------------------------------------------------- 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-$18.81 142,120 4.59 years $10.06-$11.06 28,000 1.42 years $27.44 104,200 6.83 years $15.00-$18.25 75,000 3.48 years $22.63 117,020 7.83 years -- -- -- $29.71 122,080 9.08 years -- -- -- ------------------------------------------------------------------------------------------------------------------- $18.25-$29.71 485,420 6.98 years $10.06-$18.25 103,000 2.92 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, 7,500 shares were awarded during the year ended December 31, 2003, 6,000 shares were awarded during the three months ended December 31, 2001 and 4,800 shares were awarded during the year ended September 30, 2001, leaving 137,139 shares reserved for issuance as of December 31, 2003.
The Company's Dividend Reinvestment and Direct Stock Purchase Plan includes a direct stock purchase feature which allows purchases by non-shareholders. As of December 31, 2003, 789,612 common shares were reserved under this Plan.
By resolution adopted May 25, 1994, and supplemented by a resolution adopted April 26, 2000, the Board authorized the Company to repurchase of up to 1,782,200 shares of the Company's common stock. For the year ended December 31, 2003, the three months ended December 31, 2001 and the year ended September 30, 2001, the Company repurchased 650 shares, 54,600 shares and 91,600 shares, respectively, pursuant to its repurchase authorization. As of December 31, 2003, a total of 1,075,350 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company's stock compensation plans. For the years ended December 31, 2003 and 2002, and the three months ended December 31, 2001, the Company acquired 29,232 shares, 5,319 shares and 474 shares, respectively, in connection with its stock compensation plans.
On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan) designed to protect shareholders from coercive or unfair takeover tactics. Under certain circumstances, the 1998 Plan provides shareholders with the right to acquire the Company's Series 1998 Junior Participating Preferred Stock (or, in certain cases, securities of an acquiring person) at a significant discount. Terms and conditions are set forth in a Rights
Agreement between the Company and its Rights Agent. Under the 1998 Plan, one right is associated with each outstanding share of common stock. Rights outstanding under the 1998 Plan at December 31, 2003, were convertible into 362,235 shares of Series 1998 Junior Participating Preferred Stock (1/100 share of preferred stock for each full right) subject to adjustment upon occurrence of certain take-over related events. No rights were exercised or exercisable during the period. The price at which the rights would be exercised is $70 per right, subject to 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 2013. These contracts typically contain minimum demand charge obligations on the part of Alagasco.
ENVIRONMENTAL MATTERS: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company's financial position and results of operations and is not expected to do so in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.
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.
LEGAL MATTERS: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards may bear little or no relation to culpability or actual damages, thus making it increasingly difficult to predict litigation results.
Various pending or threatened legal proceedings arising in the normal course of business are in progress currently, and the Company has accrued a provision for estimated costs.
LEASE OBLIGATIONS: 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, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Energen's total lease payments related to leases included as operating lease expense, inclusive of the sale-leaseback, were $8,412,000 and $8,273,000 for the years ended December 31, 2003 and 2002, $1,837,000 for
the three months ended December 31, 2001, $7,324,000 for the year ended September 30, 2001. Minimum future rental payments required after 2003 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
-------------------------------------------------------------------------------- Years Ending December 31, (in thousands) -------------------------------------------------------------------------------- 2004 2005 2006 2007 2008 2009 AND THEREAFTER -------------------------------------------------------------------------------- $ 3,388 $ 3,054 $ 2,676 $ 2,421 $ 2,093 $ 30,531 -------------------------------------------------------------------------------- |
Alagasco's total payments related to leases included as operating expense, inclusive of the sale-leaseback, were $2,602,000 and $2,362,000 for the years ended December 31, 2003 and 2002, $587,000 for the three months ended December 31, 2001 and $2,343,000 for the year ended September 30, 2001. Minimum future rental payments required after 2003 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
-------------------------------------------------------------------------------- Years Ending December 31, (in thousands) -------------------------------------------------------------------------------- 2004 2005 2006 2007 2008 2009 AND THEREAFTER -------------------------------------------------------------------------------- $ 2,209 $ 1,904 $ 1,531 $ 1,503 $ 1,483 $ 22,004 -------------------------------------------------------------------------------- |
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 $564,533,000, would be $614,950,000 at December 31, 2003. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, with a carrying value of $169,533,000, would be $188,201,000 at December 31, 2003. The fair values were based on the market value of debt with similar maturities and current interest rates.
Alagasco has an agreement with a financial institution whereby it may sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $15 million. Alagasco sold installment receivables of $4,992,000 and $5,010,000 in the years ended December 31, 2003 and 2002, respectively, $2,120,000 in the three months ended December 31, 2001 and $5,444,000 in the year ended September 30, 2001. At December 31, 2003 and 2002, the balances of these installment receivables were $8,167,000 and $10,566,000, 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. The fair value of these guarantees is not significant to the Company and is recorded as a non-current other liability. Effective February 1, 2004, Alagasco is no longer selling its installment receivables.
Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the consolidated balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. At December 31, 2003, the gas guaranteed had an aggregate purchase price of $14.6 million and a market value of $16.3 million. The maximum term over which Alagasco has guarantees outstanding is through December 2004.
PRICE RISK: The Company adopted SFAS No. 133 on October 1, 2000. This statement
requires all derivatives to be recognized on the balance sheet and measured at
fair value. If a derivative is designated as a cash flow hedge, the Company is
required to measure the effectiveness of the hedge, or the degree that the gain
(loss) for the hedging instrument offsets the loss (gain) on the hedged item, at
each reporting period. The effective portion of the gain or loss on the
derivative instrument is recognized in other comprehensive income as a component
of equity and subsequently reclassified into earnings in operating revenues when
the forecasted transaction affects earnings.
The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues
immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.
Energen Resources periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically 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 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.
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 in operating revenues as originally forecasted to occur. As a result, Energen's net income in the three-month transition period ended December 31, 2001, reflected a 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.
At December 31, 2003, the Company had current gains on the fair value of derivatives of $0.6 million included in prepayments and other, current losses of $34.6 million included in accounts payable and $3.5 of non-current losses included in deferred credits and other liabilities on the consolidated balance sheet. 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.
As of December 31, 2003, $19.6 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to operating revenues in earnings during the next twelve-month period. Gains and losses on derivative instruments that are not accounted for as cash flow hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. The Company recorded a $1.5 million after-tax loss in 2003 for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, the Company recorded an after-tax loss of $634,000 in 2003 on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of December 31, 2003, all of the Company's swaps and hedges met the definition of a cash flow hedge. The Company had $13.9 million and $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, 2003 and 2002, respectively.
Energen Resources has entered into the following transactions for 2004 and subsequent years:
------------------------------------------------------------------------------------------- PRODUCTION TOTAL HEDGED VOLUMES AVERAGE CONTRACT DESCRIPTION PERIOD PRICE ------------------------------------------------------------------------------------------- NATURAL GAS ------------------------------------------------------------------------------------------- 2004 15.8 Bcf $4.83 Mcf NYMEX Swaps 20.6 Bcf $4.17 Mcf Basin Specific Swaps 2.4 Bcf $4.05 - $4.44 Mcf NYMEX Collars 2005 1.2 Bcf $3.75 Mcf NYMEX Swaps 6.0 Bcf $3.96 Mcf Basin Specific Swaps |
------------------------------------------------------------------------------------------- OIL ------------------------------------------------------------------------------------------- 2004 1,428 MBbl $27.75 Bbl NYMEX Swaps 360 MBbl $27.85 Bbl West Texas Sour (WTS) Swaps ------------------------------------------------------------------------------------------- OIL BASIS DIFFERENTIAL ------------------------------------------------------------------------------------------- 2004 300 MBbl ** Basis Swaps ------------------------------------------------------------------------------------------- NATURAL GAS LIQUIDS ------------------------------------------------------------------------------------------- 2004 37 MMGal $0.41 Gal Liquids Swaps ------------------------------------------------------------------------------------------- |
** Average contract prices not meaningful due to the varying nature of each contract
All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness in hedging the exposure to the hedged transaction's variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 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 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. In accordance with SFAS No. 71, Alagasco had recorded a current regulatory asset of $0.3 million, a current regulatory liability of $17 million and a noncurrent regulatory liability of $8.7 million representing the fair value of derivatives as of December 31, 2003. As of December 31, 2002, Alagasco recorded a current regulatory liability of $16.8 million representing the fair value of derivatives.
CONCENTRATION OF CREDIT RISK: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, in that the Company's oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. 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. Energen Resources monitors the credit quality for its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.
Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 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.
9. RECONCILIATION OF EARNINGS PER SHARE
-------------------------------------------------------------------------------------------------------------------- YEAR ENDED Year Ended (in thousands, except per share amounts) DECEMBER 31, 2003 December 31, 2002 -------------------------------------------------------------------------------------------------------------------- PER SHARE Per Share INCOME SHARES AMOUNT Income Shares Amount -------------------------------------------------------------------------------------------------------------------- Basic EPS $110,654 35,434 $3.12 $68,639 33,605 $2.04 Effect of dilutive securities Long-range performance shares 73 88 Stock options 201 143 Restricted stock 9 2 -------------------------------------------------------------------------------------------------------------------- Diluted EPS $110,654 35,717 $3.10 $68,639 33,838 $2.03 -------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------- Three Months Ended Year Ended (in thousands, except per share amounts) December 31, 2001 September 30, 2001 -------------------------------------------------------------------------------------------------------------------- Per Share Per Share Income Shares Amount Income Shares Amount -------------------------------------------------------------------------------------------------------------------- Basic EPS $3,658 31,052 $0.12 $67,896 30,726 $2.21 Effect of dilutive securities Long-range performance shares 96 165 Stock options 127 187 Restricted stock 2 6 -------------------------------------------------------------------------------------------------------------------- Diluted EPS $3,658 31,277 $0.12 $67,896 31,084 $2.18 -------------------------------------------------------------------------------------------------------------------- |
For the year ended December 31, 2003, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.
10. ASSET RETIREMENT OBLIGATIONS
In 2002, the Company adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Upon adoption of SFAS No. 143, the Company recognized a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalized an equal amount as a cost of the asset as of January 1, 2002. Upon initial application of the Statement, the Company recorded a cumulative effect of a change in accounting principle to recognize a liability for existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost. For the year ended December 31, 2002, Energen Resources recognized additional capitalized costs of $20.1 million, depreciation expense of $1.7 million, accretion expense of $1.8 million, a deferred tax asset of $1.3 million and an after-tax charge of $2.2 million for the cumulative effect on prior years. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligation for its recorded amount and will record the resulting gain or loss.
In 2002 and 2003, Energen Resources recognized activity representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:
-------------------------------------------------------------------------------- (in thousands) -------------------------------------------------------------------------------- Balance of ARO as of January 1, 2002 $ 20,493 Liabilities incurred during the year ended December 31, 2002 4,923 Accretion expense 1,819 -------------------------------------------------------------------------------- Balance of ARO as of December 31, 2002 $ 27,235 -------------------------------------------------------------------------------- Liabilities incurred during the year ended December 31, 2003 1,139 Liabilities settled during the year ended December 31, 2003 (3,750) Accretion expense 1,891 -------------------------------------------------------------------------------- Balance of ARO as of December 31, 2003 $ 26,515 -------------------------------------------------------------------------------- |
The Company's gas distribution system operates under various property easement agreements primarily related to
public rights of way. In some instances, the entity granting the easement retains the option to require certain actions in the event the Company abandons the asset. Since the Company expects its gas distribution assets to be operated in perpetuity and historical abandonment costs resulting from such easement agreements have been de minimis, no asset retirement obligation has been recorded. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. In 2003, Alagasco revised its balance sheet presentation to reclassify the accrual for net removal costs from accumulated depreciation to a regulatory liability in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result, regulatory liabilities increased for accumulated asset removal costs by $103.7 million, $94.7 million and $87.5 million for December 31, 2003, 2002 and 2001, respectively.
11. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental information concerning Energen's cash flow activities is as follows:
------------------------------------------------------------------------------------------------------------------------ Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------ Interest paid, net of amount capitalized $39,963 $43,085 $11,418 $42,905 Income taxes paid $10,929 $ 9,838 $ 4,261 $11,636 Noncash investing activities: First Permian, L.L.C. stock issuance $ -- $72,891 $ -- $ -- Capitalized depreciation $ 123 $ 223 $ 51 $ 243 Allowance for funds used during construction $ 1,529 $ 1,336 $ 122 $ 2,098 ------------------------------------------------------------------------------------------------------------------------ |
Under SFAS No. 143, the Company recorded a non-cash adjustment for accretion expense of $1.9 million during 2003. During 2002, additional capitalized costs of $20.1 million, a non-current liability of $27.2 million, accretion expense of $1.8 million, depreciation expense of $1.7 million, and a deferred tax asset of $1.3 million were recorded, all of which are non-cash adjustments concerning Energen's cash flow activities.
Supplemental information concerning Alagasco's cash flow activities is as follows:
------------------------------------------------------------------------------------------------------------------------ Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------ Interest paid, net of amount capitalized $12,477 $14,012 $5,666 $12,154 Income taxes paid $12,754 $15,519 $9,425 $18,318 Noncash investing activities: Capitalized depreciation $ 123 $ 223 $ 51 $ 243 Allowance for funds used during construction $ 1,529 $ 1,336 $ 122 $ 2,098 ------------------------------------------------------------------------------------------------------------------------ |
12. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS
On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which retains the previous asset impairment requirements of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses in the sale of certain oil and gas properties and 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. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale must be reported at the lower of the carrying amount or fair value.
Accordingly, during 2003, Energen Resources recorded a pre-tax writedown to fair value based upon expected market value of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region. These properties were subsequently sold during 2003 for a pre-tax gain of $0.4 million. The gain on disposals for the year ended December 31, 2003, totaled $9.4 million primarily due to sales of properties in the San Juan Basin. As of December 31, 2003, the Company had no properties classified as held-for-sale. During 2002, Energen Resources recorded a pre-tax writedown of $2.8 million on certain non-strategic gas properties located in the Gulf Coast region, adjusting the carrying amount of the properties to their fair value based upon expected future discounted cash flows. In November 2002, the Company sold these properties for approximately the carrying amount. The gain on disposals for the year ended December 31, 2002, totaled $3.7 million largely due to sales of property located in the Permian Basin. In 2001, prior to adopting SFAS No. 144, a pre-tax gain of $0.8 million was recorded in operating revenues from continuing operations for certain non-strategic property sales.
The following are the results of operations from discontinued operations:
------------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands, except per share data) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------------- Oil and gas revenues $ 3,586 $ 10,362 $ 3,696 $22,157 ------------------------------------------------------------------------------------------------------------------------------- Pretax income (loss) from discontinued operations $ 1,594 $ (133) $ (115) $ 8,983 Income tax expense (benefit) 621 (53) (43) 3,504 ------------------------------------------------------------------------------------------------------------------------------- INCOME (LOSS) FROM DISCONTINUED OPERATIONS 973 (80) (72) 5,479 ------------------------------------------------------------------------------------------------------------------------------- Impairment charge on held-for-sale property (10,404) (2,815) -- -- Gain on disposal 9,448 3,706 -- -- Income tax expense (benefit) (372) 348 -- -- ------------------------------------------------------------------------------------------------------------------------------- GAIN (LOSS) ON DISPOSAL (584) 543 -- -- ------------------------------------------------------------------------------------------------------------------------------- TOTAL INCOME (LOSS) FROM DISCONTINUED OPERATIONS $ 389 $ 463 $ (72) $ 5,479 ------------------------------------------------------------------------------------------------------------------------------- DILUTED EARNINGS PER AVERAGE COMMON SHARE Income (Loss) from Discontinued Operations $ 0.03 $ -- $ -- $ 0.17 ------------------------------------------------------------------------------------------------------------------------------- Gain (Loss) on Disposal (0.02) 0.02 -- -- ------------------------------------------------------------------------------------------------------------------------------- Total Income from Discontinued Operations $ 0.01 $ 0.02 $ -- $ 0.17 ------------------------------------------------------------------------------------------------------------------------------- BASIC EARNINGS PER AVERAGE COMMON SHARE Income (Loss) from Discontinued Operations $ 0.03 $ -- $ -- $ 0.18 Gain (Loss) on Disposal (0.02) 0.02 -- -- ------------------------------------------------------------------------------------------------------------------------------- Total Income from Discontinued Operations $ 0.01 $ 0.02 $ -- $ 0.18 ------------------------------------------------------------------------------------------------------------------------------- |
13. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
The Company's business is seasonal in character. The following data summarizes quarterly operating results. The summarized quarterly information may differ from amounts previously reported due to changes in the classification of properties reported as discontinued operations as required by SFAS No. 144 (see Note 12).
------------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 2003 ---------------------------- (in thousands, except per share amounts) First Second Third Fourth ------------------------------------------------------------------------------------------------------------------- Operating revenues $309,658 $184,030 $146,141 $202,392 Operating income $ 96,614 $ 50,512 $ 29,356 $ 43,296 Income from continuing operations before cumulative effect of change in accounting principle $ 53,323 $ 24,459 $ 11,457 $ 21,026 |
Net income $ 54,581 $ 23,347 $ 11,896 $ 20,830 Diluted earnings per average common share Continuing operations $ 1.52 $ 0.69 $ 0.32 $ 0.58 Net income $ 1.56 $ 0.66 $ 0.33 $ 0.57 Basic earnings per average common share Continuing operations $ 1.54 $ 0.70 $ 0.32 $ 0.58 Net income $ 1.57 $ 0.67 $ 0.33 $ 0.58 ------------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 2002 ---------------------------- (in thousands, except per share amounts) First Second Third Fourth ------------------------------------------------------------------------------------------------------------------- Operating revenues $241,413 $137,844 $114,844 $174,450 Operating income $ 61,252 $ 25,762 $ 13,137 $ 35,624 Income from continuing operations before cumulative effect of change in accounting principle $ 39,042 $ 12,771 $ 97 $ 18,486 Net income $ 36,682 $ 12,744 $ 127 $ 19,086 Diluted earnings per average common share Continuing operations $ 1.24 $ 0.37 $ 0.00 $ 0.53 Net income $ 1.17 $ 0.37 $ 0.00 $ 0.55 Basic earnings per average common share Continuing operations $ 1.25 $ 0.37 $ 0.00 $ 0.53 Net income $ 1.18 $ 0.37 $ 0.00 $ 0.55 ------------------------------------------------------------------------------------------------------------------- |
Alagasco's business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco's quarterly operating results.
------------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 2003 ---------------------------- (in thousands, except per share amounts) First Second Third Fourth ------------------------------------------------------------------------------------------------------------------- Operating revenues $221,139 $ 94,248 $ 58,147 $115,565 Operating income (loss) $ 57,200 $ 6,988 $ (9,575) $ 12,235 Net income (loss) $ 33,447 $ 2,135 $ (7,781) $ 5,216 ------------------------------------------------------------------------------------------------------------------- |
------------------------------------------------------------------------------------------------------------------- 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 ------------------------------------------------------------------------------------------------------------------- |
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.
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 purchase of assets had occurred at the beginning of each period presented. The pro forma 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 seller, after giving effect to the issuance of 3,043,479 shares of common stock. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above nor are they indicative of results of the future operations of the combined enterprises.
------------------------------------------------------------------------------------------------------------ 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 $675,156 $151,406 $787,629 Income from continuing operations before cumulative effect of change in accounting principle $ 71,529 $ 4,459 $ 61,083 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 on the consolidated balance sheets:
Energen Corporation
----------------------------------------------------------------------------------------------------- (in thousands) DECEMBER 31, 2003 December 31, 2002 ----------------------------------------------------------------------------------------------------- CURRENT NONCURRENT Current Noncurrent ----------------------------------------------------------------------------------------------------- Regulatory assets: Pension asset $ -- $ 18,082 $ -- $ 14,744 Risk management activities 251 -- -- -- ----------------------------------------------------------------------------------------------------- Total regulatory assets $ 251 $ 18,082 $ -- $ 14,744 ----------------------------------------------------------------------------------------------------- Regulatory liabilities: Enhanced stability reserve $ 3,481 $ -- $ 2,963 $ -- Gas supply adjustment 4,903 -- 3,845 -- Risk management activities 17,025 8,650 16,750 -- RSE 2,619 -- 256 -- Unbilled service margin 26,118 -- 17,370 -- Asset removal costs, net -- 103,727 -- 94,751 Other -- 1,050 -- 1,468 ----------------------------------------------------------------------------------------------------- Total regulatory liabilities $ 54,146 $113,427 $ 41,184 $ 96,219 ----------------------------------------------------------------------------------------------------- |
16. EQUITY AND DEBT OFFERINGS
In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. The sale of shares began May 9, 2003, and concluded on July 16, 2003, generating net proceeds of $32.1 million. In October 2003, Energen issued $50 million of long-term debt due October 1, 2013. The 5% coupon notes were priced at 99.557 percent to yield 5.057 percent. These proceeds were be used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.
17. TRANSACTIONS WITH RELATED PARTIES
Alagasco purchased natural gas from affiliates of $3,195,000 and $1,820,000 for the years ended December 31, 2003 and 2002, $375,000 for the three months ended December 31, 2001 and $5,254,000 for the year ended September 30, 2001. These amounts are included in gas purchased for resale. Alagasco had net payables to affiliates of $37,290,000 and $1,432,000 at December 31, 2003 and December 31, 2002, respectively.
18. OTHER INCOME AND EXPENSE
The following table details Energen's other income and expense amounts on the consolidated income statements:
----------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ----------------------------------------------------------------------------------------------------------- Allowance for funds used during construction $ 948 $ 1,336 $ 122 $ 2,098 Merchandise revenues 7,696 14,155 4,226 14,535 Other 100 153 6 192 ----------------------------------------------------------------------------------------------------------- Total other income $ 8,744 $15,644 $ 4,354 $16,825 ----------------------------------------------------------------------------------------------------------- Cost of goods sold $ 8,549 $10,215 $ 3,181 $10,136 Other merchandise expense 1,428 4,888 1,204 4,756 ----------------------------------------------------------------------------------------------------------- Total other expense $ 9,977 $15,103 $ 4,385 $14,892 ----------------------------------------------------------------------------------------------------------- |
The following table details Alagasco's other income and expense amounts on the income statements:
----------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ----------------------------------------------------------------------------------------------------------- Merchandise revenues $ 5,080 $ 5,520 $ 1,596 $ 5,978 ----------------------------------------------------------------------------------------------------------- Total other income $ 5,080 $ 5,520 $ 1,596 $ 5,978 ----------------------------------------------------------------------------------------------------------- Cost of goods sold $ 5,142 $ 2,702 $ 946 $ 3,051 Other merchandise expense 127 3,578 892 3,534 ----------------------------------------------------------------------------------------------------------- Total other expense $ 5,269 $ 6,280 $ 1,838 $ 6,585 ----------------------------------------------------------------------------------------------------------- |
The sale of merchandise inventory items are reflected in other income and expense. In 2003, a key supplier of certain merchandise inventories ended its business relationship with the Company. Alagasco no longer participates in direct sales of natural gas merchandise effective February 1, 2004. Alagasco continues to work closely with various contractors and retail companies to meet the merchandise requirements of its customers.
19. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," were issued by the FASB in June 2001 and became effective on July 1, 2001, and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142 establishes new guidelines in accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain intangible assets that have indefinite useful lives are not amortized, but rather are reviewed annually for impairment. The appropriate application of SFAS No. 141 and SFAS No. 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is currently being considered. One interpretation relative to these standards is that oil and gas mineral rights for both undeveloped and developed leaseholds could be classified separately from oil and gas properties as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. In addition, the disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements. The Company anticipates that this interpretation of SFAS No. 141 and SFAS No. 142 would only affect balance sheet classifications of oil and gas leaseholds. Results of operations and cash flows are not anticipated to be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with
SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Company will continue to evaluate the impact of the application of these standards as further guidance is provided.
The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to four years; therefore, the cost related to stock-based employee compensation included in the determination of net income is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123.
In December 2003, the FASB revised SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits - an amendment of FASB Statements No. 87, 88 and 106." The revised Statement added additional disclosures relating to the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other postretirement plans and is effective for financial statements with fiscal years ending after December 15, 2003, with an exception for the disclosure of estimated future benefit payments effective for fiscal years ending after June 15, 2004. The Company has incorporated within this report the additional required disclosures (See Note 5).
20. 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
-------------------------------------------------------------------------------------------------- (in thousands) DECEMBER 31, 2003 December 31, 2002 -------------------------------------------------------------------------------------------------- Proved $1,191,528 $1,091,536 Unproved 5,812 11,936 -------------------------------------------------------------------------------------------------- Total capitalized costs 1,197,340 1,103,472 Accumulated depreciation, depletion, and amortization 310,368 269,616 -------------------------------------------------------------------------------------------------- Capitalized costs, net $ 886,972 $ 833,856 -------------------------------------------------------------------------------------------------- |
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 Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ----------------------------------------------------------------------------------------------------------------------- Property acquisition: Proved $ 40,219 $173,984 $ 238 $ 33,764 Unproved 267 10,193 81 552 Exploration 468 527 339 1,734 Development 122,094 122,494 24,757 103,574 ----------------------------------------------------------------------------------------------------------------------- Total costs incurred $163,048 $307,198 $ 25,415 $139,624 ----------------------------------------------------------------------------------------------------------------------- |
RESULTS OF CONTINUING OPERATIONS: The following table sets forth results of the Company's oil and gas continuing operations:
----------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ----------------------------------------------------------------------------------------------------------------------- Gross revenues $354,816 $245,397 $ 50,613 $208,592 Production (lifting costs) 95,651 75,395 14,861 72,106 Exploration expense 1,053 3,595 827 4,206 Depreciation, depletion and amortization 78,241 66,594 14,986 49,563 Accretion expense 1,820 1,890 -- -- Income tax expense 66,419 23,102 4,103 15,688 ----------------------------------------------------------------------------------------------------------------------- Results of continuing operation from producing activities $111,632 $ 74,821 $ 15,836 $ 67,029 ----------------------------------------------------------------------------------------------------------------------- |
AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE FROM CONTINUING OPERATIONS
----------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ----------------------------------------------------------------------------------------------------------------------- Average sales price including the effects of hedging: Gas (Mcf) $ 4.25 $ 3.17 $ 2.99 $ 3.01 Oil (per barrel) $ 25.56 $ 24.13 $ 24.01 $ 23.43 Natural gas liquids (per barrel) $ 16.32 $ 12.77 $ 10.01 $ 17.57 Average sales price excluding the effects of hedging: Gas (Mcf) $ 4.97 $ 2.96 $ 2.34 $ 4.85 Oil (per barrel) $ 29.19 $ 24.82 $ 19.52 $ 27.42 Natural gas liquids (per barrel) $ 18.40 $ 12.77 $ 10.01 $ 17.57 Average production (lifting) cost (per Mcfe) $ 1.12 $ 1.01 $ 0.88 $ 1.13 Average production tax (per Mcfe) $ 0.32 $ 0.25 $ 0.20 $ 0.36 Average depreciation rate (per Mcfe) $ 0.92 $ 0.89 $ 0.89 $ 0.78 ----------------------------------------------------------------------------------------------------------------------- |
DRILLING ACTIVITY: The following table sets forth the total number of net productive and dry exploratory and development wells drilled:
---------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, 2003 2002 2001 2001 ---------------------------------------------------------------------------------------- Exploratory: Productive 0.7 0.1 0.3 0.1 Dry 0.3 0.1 -- 1.3 ---------------------------------------------------------------------------------------- Total 1.0 0.2 0.3 1.4 ---------------------------------------------------------------------------------------- Development: Productive 194.2 145.9 23.8 90.7 Dry 3.0 4.3 -- -- ---------------------------------------------------------------------------------------- Total 197.2 150.2 23.8 90.7 ---------------------------------------------------------------------------------------- |
As of December 31, 2003, the Company was participating in the drilling of 6 gross development wells, with the Company's interest equivalent to 4.21 wells.
PRODUCTIVE WELLS AND ACREAGE: The following table sets forth the total gross and net productive gas and oil wells as of December 31, 2003, and developed and undeveloped acreage as of the latest practicable date prior to year-end:
-------------------------------------------------------------------------------- Gross Net -------------------------------------------------------------------------------- Gas Wells 3,388 1,747 Oil Wells 2,233 996 -------------------------------------------------------------------------------- Developed Acreage 740,786 451,319 Undeveloped Acreage 101,034 55,439 -------------------------------------------------------------------------------- |
There were 44 wells with multiple completions in 2003. 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.
Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, Miller and Lents, Ltd., and T. Scott Hickman and Associates, Inc., independent oil and gas reservoir engineers, have reviewed the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2003. Ryder Scott Company reviewed the reserve estimates for the Black Warrior Basin and substantially all of the Permian Basin reserves. Miller and Lents, Ltd. reviewed the reserves for the north Louisiana/east Texas regions. T. Scott Hickman and Associates, Inc. reviewed the reserves for the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 97 percent of the Company's ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.
--------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 2003 Gas MMcf Oil MBbl NGL MBbl --------------------------------------------------------------------------------------------- Proved reserves at beginning of period 803,748 49,833 26,697 Revisions of previous estimates (10,847) 1,237 (826) Purchases 93,700 1,172 -- Discoveries and other additions 80,124 5,051 4,068 Production (55,796) (3,458) (1,602) Sales (24,622) (1,307) (1,092) --------------------------------------------------------------------------------------------- Proved reserves at end of period 886,307 52,528 27,245 --------------------------------------------------------------------------------------------- Proved developed reserves at end of period 714,866 40,802 23,552 --------------------------------------------------------------------------------------------- |
--------------------------------------------------------------------------------------------- Year ended December 31, 2002 Gas MMcf Oil MBbl NGL MBbl --------------------------------------------------------------------------------------------- Proved reserves at beginning of period 714,395 19,128 25,944 Revisions of previous estimates (3,916) (1,303) 624 Purchases 6,263 36,779 -- Discoveries and other additions 141,435 1,367 2,030 Production (48,051) (3,193) (1,794) Sales (6,378) (2,945) (107) --------------------------------------------------------------------------------------------- Proved reserves at end of period 803,748 49,833 26,697 --------------------------------------------------------------------------------------------- Proved developed reserves at end of period 672,633 36,782 24,009 --------------------------------------------------------------------------------------------- |
--------------------------------------------------------------------------------------------- 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 --------------------------------------------------------------------------------------------- |
During 2003, Energen Resources sold approximately 39 Bcfe of proved reserves, recording a net pre-tax loss of $1 million, which includes a $10.4 million writedown on assets held-for-sale and subsequently sold during the year partially offset by gains on property sales of $9.4 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, 2003, December 31, 2002, December 31, 2001, and September 30, 2001, the Company had a deferred hedging loss of $35.6 million and $17.2 million, and a deferred hedging gain of $15.2 million and $25.7 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.
------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------- Future gross revenues $ 7,211,830 $ 5,455,802 $ 2,181,148 $ 1,672,436 Future production costs 2,189,464 1,754,700 829,968 693,817 Future development costs 204,513 183,818 114,317 83,781 ------------------------------------------------------------------------------------------------------------------------- Future net cash flows before income taxes 4,817,853 3,517,284 1,236,863 894,838 Future income tax expense 1,609,324 1,100,392 265,611 124,803 ------------------------------------------------------------------------------------------------------------------------- Future net cash flows after income taxes 3,208,529 2,416,892 971,252 770,035 Discount at 10% per annum 1,635,450 1,172,635 399,810 272,493 ------------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 1,573,079 $ 1,244,257 $ 571,442 $ 497,542 ------------------------------------------------------------------------------------------------------------------------- |
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 Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------------- Balance at beginning of year $ 1,244,257 $ 571,442 $ 497,542 $ 1,105,265 ------------------------------------------------------------------------------------------------------------------------- Revisions to reserves proved in prior years: Net changes in prices, production costs and future development costs 365,816 658,956 100,710 (1,015,900) Net changes due to revisions in quantity estimates (14,804) (8,380) 49,579 (81,076) Development costs incurred, previously estimated 80,878 49,418 8,812 50,768 Accretion of discount 124,426 57,144 11,398 144,266 Other 39,134 (8,669) (24,012) 95,165 ------------------------------------------------------------------------------------------------------------------------- Total revisions 595,450 748,469 146,487 (806,777) New field discoveries and extensions, net of future production and development costs 200,880 213,625 5,562 33,685 Sales of oil and gas produced, net of production costs (311,189) (162,151) (23,699) (220,220) Purchases 74,201 218,799 20 32,811 Sales (48,107) (14,203) (2,271) (26,256) Net change in income taxes (182,413) (331,724) (52,199) 379,034 ------------------------------------------------------------------------------------------------------------------------- Net change in standardized measure of discounted future net cash flows 328,822 672,815 73,900 (607,723) ------------------------------------------------------------------------------------------------------------------------- Balance at end of year $ 1,573,079 $ 1,244,257 $ 571,442 $ 497,542 ------------------------------------------------------------------------------------------------------------------------- |
21. INDUSTRY SEGMENT INFORMATION
The Company is principally engaged in two business segments: the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution). The accounting policies of the segments are the same as those described in Note 1. Certain reclassifications have been made to conform the prior years' financial statements to the current year presentation.
-------------------------------------------------------------------------------------------------------------------------------- Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 -------------------------------------------------------------------------------------------------------------------------------- Operating revenues from continuing operations Oil and gas operations $ 353,122 $ 244,120 $ 46,954 $ 208,954 Natural gas distribution 489,099 424,431 96,678 553,862 -------------------------------------------------------------------------------------------------------------------------------- Total $ 842,221 $ 668,551 $ 143,632 $ 762,816 -------------------------------------------------------------------------------------------------------------------------------- Operating income (loss) from continuing operations Oil and gas operations $ 153,591 $ 76,286 $ 3,496 $ 66,416 Natural gas distribution 66,848 59,370 8,034 50,288 -------------------------------------------------------------------------------------------------------------------------------- Subtotal $ 220,439 $ 135,656 $ 11,530 $ 116,704 Eliminations and corporate expenses (2,551) (1,700) (417) (1,678) -------------------------------------------------------------------------------------------------------------------------------- Total $ 217,888 $ 133,956 $ 11,113 $ 115,026 -------------------------------------------------------------------------------------------------------------------------------- Depreciation, depletion and amortization expense from continuing operations Oil and gas operations $ 79,687 $ 68,009 $ 15,317 $ 50,907 Natural gas distribution 37,171 33,682 8,151 30,933 -------------------------------------------------------------------------------------------------------------------------------- Total $ 116,858 $ 101,691 $ 23,468 $ 81,840 -------------------------------------------------------------------------------------------------------------------------------- Interest expense Oil and gas operations $ 28,577 $ 29,635 $ 7,042 $ 30,244 Natural gas distribution 13,967 14,557 3,680 12,316 -------------------------------------------------------------------------------------------------------------------------------- Subtotal $ 42,544 $ 44,192 $ 10,722 $ 42,560 Eliminations and other (282) (479) (88) (490) -------------------------------------------------------------------------------------------------------------------------------- Total $ 42,262 $ 43,713 $ 10,634 $ 42,070 -------------------------------------------------------------------------------------------------------------------------------- Income tax expense (benefit) from continuing operations Oil and gas operations $ 46,616 $ 3,820 $ (4,741) $ (611) Natural gas distribution 19,675 17,825 1,547 13,448 -------------------------------------------------------------------------------------------------------------------------------- Subtotal $ 66,291 $ 21,645 $ (3,194) $ 12,837 Other (2,163) (1,257) (88) (365) -------------------------------------------------------------------------------------------------------------------------------- Total $ 64,128 $ 20,388 $ (3,282) $ 12,472 -------------------------------------------------------------------------------------------------------------------------------- Capital expenditures Oil and gas operations $ 163,338 $ 305,476 $ 25,052 $ 136,886 Natural gas distribution 57,906 65,815 12,873 56,090 Other -- 5 -- 60 -------------------------------------------------------------------------------------------------------------------------------- Total $ 221,244 $ 371,296 $ 37,925 $ 193,036 -------------------------------------------------------------------------------------------------------------------------------- Identifiable assets Oil and gas operations $ 959,815 $ 926,839 $ 687,776 $ 716,043 Natural gas distribution 797,693 715,330 651,211 606,808 -------------------------------------------------------------------------------------------------------------------------------- Subtotal $1,757,508 $1,642,169 $1,338,987 $1,322,851 Eliminations and other 23,924 843 3,359 (8,966) -------------------------------------------------------------------------------------------------------------------------------- Total $1,781,432 $1,643,012 $1,342,346 $1,313,885 -------------------------------------------------------------------------------------------------------------------------------- Property, plant and equipment, net Oil and gas operations $ 891,682 $ 838,526 $ 620,305 $ 617,592 Natural gas distribution 541,769 512,849 472,659 466,207 Other -- 179 237 253 -------------------------------------------------------------------------------------------------------------------------------- Total $1,433,451 $1,351,554 $1,093,201 $1,084,052 -------------------------------------------------------------------------------------------------------------------------------- |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
ENERGEN CORPORATION
------------------------------------------------------------------------------------------------------------------ Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------ ALLOWANCE FOR DOUBTFUL ACCOUNTS BALANCE AT BEGINNING OF YEAR $ 8,874 $ 11,783 $ 10,031 $ 6,681 ------------------------------------------------------------------------------------------------------------------ Additions: Charged to income 5,820 5,482 1,819 7,953 Recoveries and adjustments (616) (495) 139 (901) ------------------------------------------------------------------------------------------------------------------ Net additions 5,204 4,987 1,958 7,052 ------------------------------------------------------------------------------------------------------------------ Less uncollectible accounts written off (4,226) (7,896) (206) (3,702) ------------------------------------------------------------------------------------------------------------------ BALANCE AT END OF YEAR $ 9,852 $ 8,874 $ 11,783 $ 10,031 ------------------------------------------------------------------------------------------------------------------ |
ALABAMA GAS CORPORATION
------------------------------------------------------------------------------------------------------------------ Three Months YEAR ENDED Year Ended Ended Year Ended DECEMBER 31, December 31, December 31, September 30, (in thousands) 2003 2002 2001 2001 ------------------------------------------------------------------------------------------------------------------ ALLOWANCE FOR DOUBTFUL ACCOUNTS BALANCE AT BEGINNING OF YEAR $ 8,200 $ 11,100 $ 9,500 $ 5,800 ------------------------------------------------------------------------------------------------------------------ Additions: Charged to income 5,668 5,410 1,816 7,799 Recoveries and adjustments (601) (565) (38) (452) ------------------------------------------------------------------------------------------------------------------ Net additions 5,067 4,845 1,778 7,347 ------------------------------------------------------------------------------------------------------------------ Less uncollectible accounts written off (4,167) (7,745) (178) (3,647) ------------------------------------------------------------------------------------------------------------------ BALANCE AT END OF YEAR $ 9,100 $ 8,200 $ 11,100 $ 9,500 ------------------------------------------------------------------------------------------------------------------ |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
A. Our chief executive officer and chief financial officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
B. Our chief executive officer and chief financial officer have concluded that during the period covered by this report there were no changes in our internal controls that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004. The proxy statement will be filed on or about March 29, 2004.
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 28, 2004.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information regarding the security ownership of the beneficial owners of more than five percent of Energen's common stock is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004.
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 28, 2004.
C. SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The information regarding securities authorized for issuance under equity compensation plans is included in Part 2 under Item 5.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information regarding Principal Accountant Fees and Services is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004.
PART IV
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 January 15, 2003, reporting Drayton Nabers, Jr., former chairman and chief executive officer of Protective Life Corporation, resigned from the Board of Directors of Energen Corporation effective January 15, 2003.
Form 8-K/A dated January 24, 2003, reporting Drayton Nabers, Jr., former chairman and chief executive officer of Protective Life Corporation, resigned from the Board of Directors of Energen Corporation effective January 15, 2003.
Form 8-K dated April 24, 2003, reporting Energen and Alagasco issued a press release announcing financial results for the first quarter of 2003.
Form 8-K dated July 18, 2003, reporting the sale of 1,000,000 shares of Energen common stock.
Form 8-K dated July 23, 2003, reporting Energen and Alagasco issued a press release announcing financial results for the second quarter of 2003.
Form 8-K dated October 3, 2003, reporting Energen and Alagasco issued a series of 5% Notes due October 3, 2013. The aggregate principal amount of notes offered was $50,000,000.
Form 8-K dated October 29, 2003, reporting Energen and Alagasco issued a press release announcing financial results for the third quarter of 2003.
Form 8-K dated December 10, 2003, reporting Energen and Alagasco issued a press release announcing financial results earnings guidance for 2004, the election of David W. Wilson as a Director of Energen Corporation effective January 1, 2004 and Wm. Michael Warren, Jr., Chairman of the Board and Chief Executive Officer of Energen Corporation adopted a Securities Trading Plan. Mr. Warren adopted the plan pursuant to Rule 10b5-1 of the Securities Exchange Act of 1934 and during an open trading window.
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO EXHIBITS
ITEM 14(A)(3)
Exhibit Number Description ------ ----------- *3(a) Restated Certificate of Incorporation of Energen Corporation (composite, as amended February 2, 1998) which was filed as Exhibit 3(a) to Energen's Annual Report on Form 10-K for the year ended September 30, 1998 (File No. 1-7810) *3(b) Articles of Amendment to Restated Certificate of Incorporation of Energen, designating Series 1998 Junior Participating Preferred Stock (July 27, 1998) which was filed as Exhibit 4(b) to Energen's Post Effective Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 333-00395) *3(c) Bylaws of Energen Corporation (as amended through October 30, 2002) which was filed as Exhibit 4(c) to Energen's Registration Statement on Form S-8 (Registration No. 33-46641) *3(d) Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1995 (file No. 1-7810) 3(e) Bylaws of Alabama Gas Corporation (as amended through October 30, 2002). *4(a) Rights Agreement, dated as of July 27, 1998, between Energen Corporation and First Chicago Trust Company of New York, Rights Agent, which was filed as Exhibit 1 to Energen's Registration Statement on Form 8-A, dated July 10, 1998 (File No. 1-7810) *4(b) Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September 1, 1996 (the "Energen 1996 Indenture"), and which was filed as Exhibit 4(i) to the Registrant's Registration Statement on Form S-3 (Registration No. 333-11239) *4(b)(i) Officers' Certificate, dated September 13, 1996, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the Series A Notes which was filed as Exhibit 4(d)(i) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810) *4(b)(ii) Officers' Certificate, dated July 8, 1997, pursuant to Section 301 of the Energen 1996 Indenture amending the terms of the Series A Notes which was filed as Exhibit 4(d)(ii) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810) *4(b)(iii) Amended and Restated Officers' Certificate, dated February 27, 1998, setting forth the terms of the Series B Notes which was filed as Exhibit 4(d)(iii) to Energen's Annual Report on Form 10-K for the year ended September 30, 2001 (File No. 1-7810) *4(b)(iv) Officers' Certificate, dated October 3, 2003, pursuant to Section 301 of the Energen 1996 Indenture setting forth the terms of the 5% Notes due October 1, 2013, which was filed as Exhibit 4 to Energen's Current Report on Form 8-K, dated October 3, 2003 (File No. 1-7810) *4(d) Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia, National Association, Trustee, ("Alagasco 1993 Indenture"), which was filed as Exhibit 4(k) to Alabama Gas' Registration Statement on Form S-3 (Registration No. 33-70466) |
*4(d)(i) Officers' Certificate, dated August 30, 2001, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 6.25 percent Notes due September 1, 2016, which was filed as Exhibit 4.01 to Alabama Gas' Current Report on Form 8-K filed September 27, 2001 *4(d)(ii) Officers' Certificate, dated August 30, 2001, pursuant to Section 301 of the Alagasco 1993 Indenture setting forth the terms of the 6.75 percent Notes due September 1, 2031, which was filed as Exhibit 4.02 to Alabama Gas' Current Report on Form 8-K filed September 27, 2001 *10(a) Form of Service Agreement Under Rate Schedule CSS (No. S10710), between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(a) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810) *10(b) Form of Service Agreement Under Rate Schedule FT-NN (No. 866941), between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810) *10(c) Form of Service Agreement Under Rate Schedule FT (No. 866940) between Southern Natural Gas Company and Alabama Gas Corporation which was file as Exhibit 10(d) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810) *10(d) Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation which was filed as Exhibit 10(b) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810) 10(e) Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alabama Gas Corporation, dated August 1, 1991. *10(f) Form of Executive Retirement Supplement Agreement between Energen Corporation and it's executive officers (as revised October 2000) which was filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810) *10(g) Form of 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(h) 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(i) 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(j) 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(k) 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(l) 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(m) 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(n) 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(o) Energen Corporation Officer Split Dollar Life Insurance Plan, effective October 1, 1999 which was filed as Exhibit 10(l) to Energen's Annual Report on Form 10-K for the year ended September 30, 2000 (File No. 1-7810) *10(p) 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(q) 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(a) Consent of Independent Accountants (PricewaterhouseCoopers LLP) 23(b) Consent of Independent Oil and Gas Reservoir Engineers (Ryder Scott Company) 23(c) Consent of Independent Oil and Gas Reservoir Engineers (Miller and Lents, Ltd.) 23(d) Consent of Independent Oil and Gas Reservoir Engineers (T. Scott Hickman and Associates, Inc.) 31(a) Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) 31(b) Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) 32 Certification pursuant to Section 1350 |
*Incorporated by reference
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.
ENERGEN CORPORATION
(Registrant)
ALABAMA GAS CORPORATION
(Registrant)
March 12, 2004 By /s/ Wm. Michael Warren, Jr. -------------- ------------------------------ Wm. Michael Warren, Jr. Chairman, President and Chief Executive Officer of Energen, Chairman and Chief Executive Officer of Alabama Gas Corporation |
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrants and in the capacities and on the dates indicated:
March 12, 2004 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 12, 2004 By /s/ Geoffrey C. Ketcham -------------- -------------------------------------- Geoffrey C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer of Energen and Alabama Gas Corporation March 12, 2004 By /s/ Grace B. Carr -------------- -------------------------------------- Grace B. Carr Vice President and Controller of Energen March 12, 2004 By /s/ Paula H. Rushing -------------- -------------------------------------- Paula H. Rushing Vice President-Finance of Alabama Gas Corporation March 12, 2004 By /s/ Julian W. Banton -------------- -------------------------------------- Julian W. Banton Director March 12, 2004 By /s/ James S. M. French -------------- -------------------------------------- James S. M. French Director March 12, 2004 By /s/ T. Michael Goodrich -------------- -------------------------------------- T. Michael Goodrich Director March 12, 2004 By /s/ Judy M. Merritt -------------- -------------------------------------- Judy M. Merritt Director March 12, 2004 By /s/ David W. Wilson -------------- -------------------------------------- David W. Wilson Director |
EXHIBIT 3(E)
ALABAMA GAS CORPORATION
BY-LAWS
As Amended Through October 30, 2002
ARTICLE I
SECTION 1. The annual meeting, for the purpose of electing Directors and transacting any other proper business, shall be held at 10:00 A.M. on the fourth Wednesday in January of each year, if not a legal holiday, and if a legal holiday then on the first succeeding business day not a legal holiday, or at such other date and time as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting. Special meetings may be held, and shall be called by the Secretary, whenever directed by the Chairman of the Board or the President or whenever requested by a majority of the directors, either by vote at a meeting or in writing.
SECTION 2. At least ten days before each annual and each special meeting and in any event such number of days as will conform with any statutory requirement, the Secretary shall mail or cause to be mailed to each stockholder entitled to vote at the meeting, at his address appearing on the books of the corporation, a notice which shall state the time and the place of the meeting, and, in the case of a special meeting, shall state also the objects or purposes of the meeting.
SECTION 3. All meetings of the stockholders, including meetings for the election of directors, shall be held at the principal office of the corporation in the City of Birmingham, Alabama.
SECTION 4. Prior to each meeting of stockholders, the Board of Directors shall either fix a period of not less than ten days preceding the day of the meeting during which the stock transfer books shall be closed, or fix a date not less than ten days preceding the day of the meeting as a record date for the determination of the stockholders entitled to notice of and to vote at such meeting, and when a record date shall have been so fixed, only stockholders of record on such date shall be entitled to notice of and to vote at such meeting.
SECTION 5. Stockholders may vote in person or by proxy. The vote of stockholders for the election of directors, or upon any question before a meeting, need not be by ballot except when required by statute or demanded by a stockholder of record entitled to vote at the meeting; when so required or demanded, the vote shall be by ballot. All questions shall be decided by the vote of a majority of the shares voting on the question, except where otherwise required by statute or by the Certificate of Incorporation, as now or hereafter amended.
SECTION 6. The Chairman of the Board, and in his absence, the President, or in the absence of both, the Executive Vice President, shall call meetings of stockholders to order and act as Chairman of such meeting. In the absence of all these officers the Board of Directors shall appoint a chairman of the meeting, but if the Board shall not make such appointment, then, any stockholder or the proxy of any stockholder may call the meeting to order, and a chairman shall be elected.
SECTION 7. The Secretary or any Assistant Secretary may act as Secretary of any meeting of stockholders; but the Board of Directors before the meeting may designate any person to act as secretary thereof, and if no such designation shall have been made, then the Chairman of the meeting may appoint any person to act as secretary thereof.
SECTION 8. At each meeting of the stockholders at which the voting shall be by ballot, the voting shall be conducted and all questions touching the qualifications of the voters, the validity of proxies and the acceptance or rejection of votes shall be decided by one judge. Such judge may be an officer of the corporation and may be appointed before the meeting by the board of directors, but if no such appointment shall have been made, then by the Chairman of the meeting; and if for any reason any judge previously appointed shall fail to attend, or refuse or be unable to serve, then a judge to act in his place shall be appointed by the Chairman of the meeting. No such judge need be a stockholder.
SECTION 9. At each meeting of stockholders, except as otherwise provided by statute or by the Certificate of Incorporation or an amendment thereof, the holders of a majority of all of the stock which at the time shall be entitled to vote, present in person or represented by proxy, shall be requisite for the transaction of business and shall constitute a quorum. A meeting of the stockholders may be adjourned to any day, and from time to time, as such meeting shall determine, whether or not a quorum be present The time and place to which an adjournment is taken shall be publicly announced at the meeting, and no further notice thereof shall be necessary.
ARTICLE II
Board of Directors
SECTION 1. The general management of the property, business and affairs of the Corporation shall be vested in a Board of Directors, eleven in number, who shall hold office until the next annual meeting of the stockholders and until others are duly chosen in their place and shall have qualified.
SECTION 2. The Board of Directors may provide for stated meetings at regular intervals to be held pursuant to a standing resolution of the Board. No notice of such meetings need be given. Special meetings of the Board may be called upon written instructions signed by the Chairman of the Board, the President or a Vice President, or at least two of the directors, and delivered to the Secretary of the Corporation, stating the time and place thereof. The Secretary
shall give, or cause to be given, notice of the time and place of holding each special meeting by mailing the same at least thirty-six (36) hours before the meeting or by causing the same to be transmitted by telephone, cable or wire message at least twenty-four (24) hours before the meeting to each director to his address on file with the Secretary of the Company.
The directors may hold their meetings at such place or places, either within or without the State of Alabama, as the board shall designate from time to time.
SECTION 3. A majority of the directors shall constitute a quorum for the transaction of business at meetings of the board. Subject to the provisions of the Certificate of Incorporation, as amended, vacancies in the board shall be filled by a majority of the directors then in office. A majority of the directors present at any meeting may adjourn the meeting until a later day or hour, or sine die, whether or not a quorum be present. A minute of such adjournment shall be entered on the records by the Secretary, and no further notice thereof shall be necessary.
SECTION 4. The Board of Directors may adopt such rules and regulations for the conduct of its meetings and the management of the affairs of the corporation as it may deem proper not inconsistent with these by-laws or the certificate of incorporation and the amendments thereof.
SECTION 5. The Board of Directors shall fix and authorize the payment of compensation for all officers of the corporation, including such officers as may be directors of the corporation, for services to the corporation; and shall fix and authorize the payment of compensation and expenses to the directors for services to the corporation, including fees and expenses for attendance at meetings of the board, of the executive committee and of all other committees.
ARTICLE III
Officers and Agents
SECTION 1. The officers of this corporation shall consist of a Chairman of the Board, a President, one or more Vice Presidents, a Secretary, and a Treasurer. In addition, the Board of Directors of this corporation may, but shall not be required to, elect one or more of the following: Executive Vice President, Senior Vice President, Assistant Vice President, Assistant Secretary, and Assistant Treasurer. In addition, the Board of Directors of this Corporation may, but shall not be required to, elect a Controller. The Chairman of the Board and the President shall be members of the Board of Directors; the other officers may, but need not be Directors. The Chairman of the Board and the President may be the same person, and the Secretary and Treasurer may be the same person; and the Executive Vice President, a Senior Vice President, or a Vice President may also hold the office of Secretary or Assistant Secretary or Treasurer or Assistant Treasurer or Controller, provided, however, that the Chairman of the Board may not also hold the offices of either Executive Vice President, Senior Vice President, or Vice President; that the President may not also hold the office of Executive Vice President, Senior Vice President, or Vice President; and that an Executive Vice President, a Senior Vice President, or a Vice President may not hold both the offices of Secretary and Treasurer.
Except where otherwise expressly provided in a written contract duly authorized by the Board of Directors, all officers, agents and employees shall be subject to removal at any time by the affirmative vote of a majority of the Directors for the time being in office, and all officers, agents and employees other than officers elected or appointed by the Board of Directors shall also be subject to removal at any time by the officer appointing them.
In addition to the powers and duties of the officers of the corporation as set forth in these By-laws and except as otherwise provided in the Certificate of Incorporation, they shall have such authority and shall perform such duties as from time to time may be determined by the Board of Directors.
SECTION 2. The Board of Directors shall by resolution duly adopted, designate one of the executive officers of the corporation as the chief executive officer of the corporation and the officer so designated by the Board of Directors shall, subject to the control of the Board of Directors, have general charge and control of the business and affairs of the corporation and shall perform such other duties as may from time to time be assigned to him by the Board of Directors. The designation by the Board of Directors of one of such executive officers other than the Chairman of the Board as the chief executive officer of the corporation shall not affect the duties required to be performed by the Chairman of the Board of the corporation under the provisions of Sections 6 and 8 of Article I of these By-laws. The Chairman of the Board shall preside at all meetings of the stockholders and of the Directors at which he is present, and shall perform such other duties as may, from time to time, be assigned to him by the Board of Directors.
SECTION 3. The President shall be the chief operating officer of the corporation. He shall, from time to time, obtain information concerning the affairs and business of the corporation and shall promptly lay such information before the Board of Directors. He shall communicate to the Board of Directors all matters presented by any officer of the corporation for its consideration and shall, from time to time, communicate to the officers such action of the Board of Directors as may, in his judgment, affect the performance of their official duties. He shall have power to appoint and remove all servants, agents and employees of the corporation (other than its officers), and shall perform all such other duties as are incident to the office of President and such specific duties as may, from time to time, be assigned to him by the Board of Directors.
In the absence of the Chairman of the Board he shall preside at all meetings of stockholders and at all meetings of the Board of Directors at which he is present.
SECTION 4. The Chairman of the Board shall in the absence of the President or in case of his inability to act, perform the duties and exercise the authority of the President. Each Vice President may have such title designation, and each Vice President, and the Executive Vice President, if there be one, each Senior Vice President, if there be one or more of them, and each Assistant Vice President, if there be one or more of them, shall perform such duties and exercise such authority as from time to time may be prescribed and conferred by the Board of Directors.
SECTION 5. The Secretary shall attend all meetings of the stockholders and of the Board of Directors and shall keep a record of all their proceedings. He shall give due notices of all meetings of the Stockholders and of the Board of Directors. He shall notify the several officers of the corporation of all action taken at any such meeting concerning matters in their respective departments, and shall transmit to the Treasurer for proper record copies of all contracts and resolutions providing for the payment of money to or by the corporation. He shall procure and keep in his files certified copies of the minutes of all meetings of the stockholders and of the Board of Directors of all companies a majority of whose capital stock is owned by this corporation. He shall be the custodian of the seal of the corporation, of mortgages, leases, and of such other papers and documents as shall be committed to his care by the Board of Directors. He shall have charge of the transfer department and supervision of the transfer of the stocks and of the registration and transfer of the bonds issued by the corporation. He shall have power to affix the seal of the corporation to instruments authorized by the Board of Directors and to attest the same; and shall perform such other duties as shall be assigned to him by the Board of Directors. He shall be sworn to the faithful discharge of his duty.
SECTION 6. The Assistant Secretaries shall exercise such of the powers and perform such of the duties of the Secretary as shall be assigned to them by the Secretary or the Board of Directors. Each Assistant Secretary of this corporation be and he hereby is authorized, in the absence or disability of the Secretary, to perform all the duties and exercise all the powers of the Secretary. Any action which in Article I or Article II of these by-laws it is stated shall be taken by or in connection with the Secretary may be taken by or in connection with any Assistant Secretary with the same effect as if he were the Secretary.
SECTION 7. The Treasurer is authorized to receive and collect all moneys due to the corporation and to receipt therefor, and to endorse for deposit to the credit of the corporation in depositories designated by the Board of Directors, checks, drafts or vouchers drawn to the order of the corporation or payable to it. He is authorized to pay interest on obligations and dividends on stock when due and payable. He shall cause to be kept in his office true and full accounts of all receipts and disbursements. He shall disburse the funds of the corporation as may be ordered by the Board of Directors, taking proper vouchers for such disbursements. He shall also perform such other duties as shall be assigned to him by the Board of Directors.
SECTION 8. The Controller, if there be one, shall, subject to the Board of Directors, provide and maintain financial and accounting controls over the business and affairs of the Corporation. He shall maintain, among others, adequate records of the assets, liabilities, and financial transactions of the Corporation, and shall direct the preparation of financial statements, reports, and analyses. He shall perform all acts incident to the position of Controller, subject to the control of the Board of Directors, the Chairman, and any Vice President or other executive officer charged by Board of Directors with general supervision of the financial affairs of the Corporation. If there shall be no Controller, the duties set out above in this Section 8 shall be performed by the Treasurer.
SECTION 9. The Assistant Treasurers shall exercise such of the powers and perform such of the duties of the Treasurer as shall be assigned to them by the Treasurer or by the Board of Directors. Each Assistant Treasurer of this corporation be and he hereby is authorized, in the absence or disability of the Treasurer, to perform all the duties and exercise all the powers of the Treasurer.
SECTION 10. In case of the absence or incapacity of any officer of this corporation, the Board of Directors may delegate his powers and duties for the time being to any other officer or to any Director.
ARTICLE IV
Issue and Transfer of Stock Certificates
SECTION 1. The Board of Directors shall provide for issue, transfer and registration of the certificates representing the capital stock of the corporation, and shall appoint the necessary officers, transfer agents and registrars of transfers for that purpose.
SECTION 2. Until otherwise ordered by the Board of Directors, stock certificates shall be signed by the President or by a Vice President, and by the Secretary or an Assistant Secretary thereunto authorized by the Board of Directors.
SECTION 3. Unless otherwise ordered by the Board of Directors, the signatures on stock certificates of the President, the Executive Vice President or a Vice President and Secretary or Assistant Secretary of the Company may be facsimiles engraved or printed and the corporate seal to be affixed thereto may be a facsimile, engraved or imprinted thereon. In case any officer or officers whose facsimile signatures may be used on any stock certificate cease to be such officer or officers, whether because of death, resignation, or otherwise, before such certificates have been issued, such certificates shall nevertheless be deemed to have been adopted by the corporation and may be countersigned and issued by any transfer agent or registrar as though such person or persons whose facsimile signatures have been used thereon had not ceased to be such officer or officers of the corporation.
SECTION 4. Transfers of stock shall be made on the books of the corporation only by order of the person in whose name such stock is registered or by his attorney lawfully constituted in writing, and unless otherwise authorized by the Board of Directors, only upon surrender and cancellation of the old certificate. No new stock certificate shall be issued to a transferee until the transfer has been made on the books of the corporation.
SECTION 5. In case any stock certificate shall be lost, by theft or otherwise, or destroyed, the Board of Directors in its absolute discretion may order the issuance of a new certificate in lieu thereof, upon delivery to the corporation of a bond of indemnity satisfactory to the board.
SECTION 6. The Board of Directors may fix in advance any period of not more than thirty days preceding any dividend payment date or any date for the allotment of rights, during which the stock transfer books shall be closed; or in the event that the Board of Directors shall not have fixed such period, it may fix a date not more than thirty days preceding any dividend payment date or any date for the allotment of rights, as a record date for the determination of the stockholders entitled to receive such dividends or rights, as the case may be; and only stockholders of record on such date shall be entitled to receive such dividends or rights, as the case may be.
ARTICLE V
Checks - Notes - Drafts - Etc.
SECTION 1. Unless otherwise directed by the Board of Directors, all notes, acceptances, checks, drafts and orders for the payment of money shall be signed by the Treasurer, Controller, or an Assistant Treasurer and any one of the following officers of the corporation: Chairman of the Board, President, Executive Vice President, Senior Vice President, any Vice President, Secretary, Treasurer, Controller, Assistant Secretary and Assistant Treasurer.
ARTICLE VI
INDEMNIFICATION OF DIRECTORS, OFFICERS, EMPLOYEES AND AGENTS
SECTION 1. Indemnification.
(a) The Corporation shall indemnify, to the fullest extent permitted by law, including, without limitation, the Alabama Business Corporation Act, any person who is or was a director or officer of the Corporation, and any director or officer of the Corporation (and any other person, as evidenced by a duly adopted resolution of the board of directors of the Corporation) who is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against liability or other expenses incurred in connection with the defense of any proceeding, or of any claim, issue or matter in such proceeding, in which such director, officer or other person is a party because such person is or was a director or officer of the Corporation or is or was serving at the request of the Corporation in one of the capacities referred to above. If the amount, extent, or quality of indemnification permitted by law should be in any way restricted after the adoption of these bylaws, then the Corporation shall indemnify such persons to the fullest extent permitted by law as in effect at the time of the occurrence of the omission or the act giving rise to the claimed liability with respect to which indemnification is sought.
(b) The Corporation shall indemnify, to the same extent as provided in
Section 1 (a) of this Article VI of these bylaws with respect to officers and
directors of the Corporation, any employee of the Corporation, and any employee
of the Corporation (and any other person, as evidenced by a duly adopted
resolution of the board of directors of the Corporation) who is or was serving
at the request of the Corporation as a director, officer, partner, trustee,
employee or agent of another foreign or domestic corporation, partnership, joint
venture, trust, employee benefit plan or other enterprise, against liability or
other expenses incurred in connection with the defense of any proceeding, or of
any claim, issue or matter in such proceeding, in which proceeding both such
employee or other person is a party because such person is or was an employee of
the Corporation or is or was serving at the request of the Corporation in one of
the capacities referred to above and the Corporation is obligated to provide,
and is providing, indemnification to one or more officers or directors of the
Corporation pursuant to Section 1 (a) above of this Article VI.
(c) In connection with indemnification of officers, directors and other persons pursuant to Sections 1 (a) and 1 (b) of this Article VI of these bylaws, the Corporation shall advance expenses to such persons as and to the extent permitted by law, including, without limitation, the Alabama Business Corporation Act.
(d) The Corporation may indemnify, and may advance expenses to, an employee or agent of the Corporation who is not an officer or director of the Corporation and any other person not described in, or not provided indemnification pursuant to the provisions of, Sections 1 (a), 1 (b) or 1 (c) of this Article VI who is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise to the same extent as provided in Section 1 (a) of this Article VI of these bylaws with respect to officers and directors of the Corporation. Notwithstanding the foregoing, nothing contained in this Section (d) shall, or shall be deemed to, constitute or create an entitlement on the part of any employee or agent of the Corporation to be indemnified or to have expenses advanced to or for such employee's or agent's benefit.
(e) The indemnification and advancement of expenses pursuant to this Article VI shall be in addition to, and not exclusive of, any other right that the person seeking indemnification may have under these bylaws, the articles of incorporation of the Corporation, any separate contract or agreement or applicable law.
SECTION 2. Insurance.
The Corporation may purchase and maintain insurance on behalf of any person who is or was a director, officer, partner, trustee, employee or agent of the Corporation, or any person who is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee, or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against any liability asserted against such person and incurred by such person in any such capacity, or arising out of such person's status as such, whether or not the Corporation would have the power to indemnify such person against such liability under applicable law.
SECTION 3. Survival of Right.
Any right to indemnification or advancement of expenses provided by or granted pursuant to this Article VI shall continue as to a person who has ceased to be a director, officer, employee or agent or to serve as a director, officer, partner, trustee, employee or agent of such other foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise and shall inure to the benefit of the heirs, executors, administrators and personal representatives of such a person. Any repeal or modification of this Article VI which serves to restrict or lessen the rights to indemnification or advancement of expenses provided by this Article VI shall be prospective only and shall not lessen the right to indemnification or advancement of expenses existing at the time of such repeal or modification with respect to liabilities arising out of claimed acts or omissions occurring prior to such repeal or modification.
ARTICLE VII
General Provisions
SECTION 1. All officers, agents and employees, in exercise of the powers conferred and the performance of the duties imposed upon them, by these by-laws or otherwise, shall at all times be subject to the direction, supervision and control of the Board of Directors.
SECTION 2. Except as otherwise ordered by the Board of Directors, the Chairman of the Board, the President, the Executive Vice President and each Vice President shall severally have power to execute on behalf of the corporation any deed, bond, indenture, certificate, contract or other instrument, and to cause the corporate seal to be thereto affixed and attested by the Secretary or an Assistant Secretary.
SECTION 3. Unless otherwise ordered by the Board of Directors, the Chairman of the Board, the President or any Vice-President, or such other officer as may be designated by the Board of Directors to act in the absence of the Chairman of the Board, the President or any Vice President, shall have full power and authority on behalf of the corporation to attend and to act and to vote, and to execute a proxy or proxies empowering others to attend and to act and to vote, at any meetings of security holders of any corporation in which the corporation may hold
securities, and at such meetings the Chairman of the Board, or such other officer of the corporation, or such proxy shall possess and may exercise any and all rights and powers incident to the ownership of such securities, and which as the owner thereof the corporation might have possessed and exercised, if present. The Chairman of the Board, or such other officer of the corporation, or such proxy may also exercise any part or all of such voting and other authority, rights and power through execution of an action by written consent in lieu of a meeting of shareholders. The Secretary or any Assistant Secretary may affix the corporate seal to any such proxy or proxies so executed by the Chairman of the Board, or such other officer, and attest the same. The Board of Directors by resolution from time to time may confer like powers upon any other person or persons.
SECTION 4. Any stockholder, director or officer may waive any notice required to be given to him under these by-laws.
SECTION 5. In addition to its principal office in the State of Alabama, the corporation may have an office or offices, either within or without the State.
SECTION 6. The corporate seal shall be an impression on wax or paper, circular in form, with the words "Alabama Gas Corporation, Alabama" on the outer margin thereof and bearing on the inner portion the words "Corporate Seal, 1929."
SECTION 7. These by-laws may be altered, amended or repealed at any meeting of stockholders, by vote of the holders, present in person or by proxy, of a majority of all of the stock which at the time shall be entitled to vote at elections of directors, or at any meeting of the Board of Directors, by vote of a majority of all the members of the board.
EXHIBIT 10(E)
87 1533 004
System Contract #.1983
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
SERVICE AGREEMENT
between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
and
TRANSCO ENERGY MARKETING COMPANY
As Agent for ALABAMA GAS CORPORATION
DATED
AUGUST 1, 1991
87 1533 004
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
SERVICE AGREEMENT
THIS AGREEMENT entered into this lst day of August, 1991, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as "Seller," first party, and TRANSCO ENERGY MARKETING COMPANY, as Agent for ALABAMA GAS CORPORATION, hereinafter referred to as "Buyer;" second party,
W I T N E S S E T H
WHEREAS, Buyer has requested Seller to receive certain quantities of natural gas at various points downstream of Seller's Compressor Station No. 70 on Seller's mainline in the State of Mississippi and transport such gas, on a firm basis, to the existing interconnections between Seller and Alabama Gas Corporation ("Alagasco") in Chilton and Dallas Counties, Alabama; and
WHEREAS, Seller agrees to receive, transport and redeliver or cause the redelivery of such quantities of natural gas as requested under the terms and conditions hereinafter set forth;
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of Seller's Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm equivalent of a Transportation Contract Quantity ("TCQ") of 100,000 Mcf per day.
2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Seller's FERC Gas Tariff.
ARTICLE II
POINT(S) OF RECEIPT
Buyer shall deliver or cause to be delivered gas at the point(s) of receipt hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline system at the varying pressures that may exist in such system from time to time; provided, however, that such pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressure(s) specified below. In the event the maximum operating pressure(s) of Seller's pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas
delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon written notification of Seller to Buyer. The point(s) of receipt for natural gas received for transportation pursuant to this agreement shall be:
See EXHIBIT A for Points of Receipt
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point(s) of delivery and at a pressure(s) of:
See EXHIBIT B for Points of Delivery
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be in effect as of August 1, 1991 and shall remain in
force and effect until 8:00 a.m. Eastern Standard Time October 31, 2002 and
thereafter until terminated by Seller or Buyer upon at least three (3) years
written notice; provided, however, this agreement shall terminate immediately
and, subject to the receipt of necessary authorizations, if any, Seller may
discontinue service hereunder if (a) Buyer, in Seller's reasonable judgement
fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate
security in accordance with Section 8.3 of Seller's Rate Schedule FT. As set
forth in Section 8 of Article II of Seller's August 7, 1989 revised Stipulation
and Agreement in Docket 88-68 et. al., (a) pregranted abandonment under Section
284.221 (d) of the Commission's Regulations shall not apply to any long term
conversions from firm sales service to transportation service under Seller's
Rate Schedule FT and (b) Seller shall not exercise its right to terminate this
service agreement as it applies to transportation service resulting from
conversions from firm sales service so long as Buyer is willing to pay rates no
less favorable than Seller is otherwise able to collect from third parties for
such service.
ARTICLE V
RATE SCHEDULE AND PRICE
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Seller's Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume No. 1 of this Tariff which relates to service under this agreement and which is incorporated herein.
3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyer's request for service under Seller's Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction.
ARTICLE VI
MISCELLANEOUS
1. This Agreement supersedes and cancels as of the effective date hereof the following contract(s) between the parties hereto:
Agreement between Buyer and Seller dated November 21, 1987.
2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.
3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address:
(a) If to Seller:
Transcontinental Gas Pipe Line Corporation
P. O. Box 1396
Houston, Texas 77251
Attention: Customer Services
(b) If to Buyer:
Transco Energy Marketing Company
as Agent for Alabama Gas Corporation
P. O. Box 1396
Houston, Texas 77251
Attention: Natural Gas Marketing
Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE LINE
CORPORATION
(Seller)
TRANSCO ENERGY MARKETING COMPANY
as Agent for ALABAMA GAS CORPORATION
(Buyer)
87 1533 004
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
EXHIBIT "A"
(FT)
Buyer's Mainline Capacity Entitlement Point(s) of Receipt (Mcf/d)* ------------------- ----------------- 1. Discharge Side of Seller's Compressor 100,000 Station 70 at M.P. 661.77 in Walthall County, Mississippi. (M.P. 661.77 - Station 70 Discharge TP# 7142) 2. Existing Point of Interconnection between 100,000 Seller and United Gas Pipe Line Company at Walthall (Seller Meter No. 3095), Walthall County, Mississippi. (Walthall- UGPL TP# 6310)*** 3. Existing Point of Interconnection between 100,000 Seller and Meter named Darbun-Pruett 34-10 (Seller Meter No. 3446) at M.P. 668.46 on Sellers Main Transmission Line, Darbun Field, Walthall County, Mississippi. (Darbun Pruett TP# 6750) 4. Existing Point of Interconnection between 100,000 Seller and Meter named Ivy Newsome (Seller Meter No. 3413) in Marion County, Mississippi. (Ivy Newsome TP# 6179) 5. Existing Point of Interconnection between 100,000 Seller and West Oakvale Field at M.P. 680.47-Marion County, Mississippi. (M.P. 680.47-West Oakvale Field TP# 7144) 6. Existing Point of Interconnection between 100,000 Seller and East Morgantown Field at M.P. 680.47 in Marion County, Mississippi. (M.P. 680.47-E. Morgantown Field TP# 7145) 7. Existing Point of Interconnection between 100,000 Seller and Greens Creek Field, at M.P. 681.84 Marion County, Mississippi. (M.P. 681.84 Greens Creek Field TP# 7146) |
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
EXHIBIT "A"
(Continued)
Buyer's Mainline Capacity Entitlement Point(s) of Receipt (Mcf/d)* ------------------- ----------------- 8. Existing Point of Interconnection between 100,000 Seller and Meter named M.P. 685.00-Oakville Unit 6-6 in Jefferson Davis County, Mississippi. (M.P. 685.00-Oakville Unit 6-6 TP# 1376) 9. Existing Point of Interconnection between 100,000 Seller and Meter named M.P. 687.23-Oakvale Field in Marion County, Mississippi. (M.P. 687.23-Oakvale Field TP# 7147) 10. Existing Point of Interconnection between 100,000 Seller and Bassfield at named M.P. 696.40 in Marion County, Mississippi. (M.P. 696.40 Bassfield TP# 9439) 11. Existing Point of Interconnection between 100,000 Seller and Meter named Lithium/Holiday Creek-Frm (Seller Meter No. 3418), in Jefferson Davis County, Mississippi. (Lithium/Holiday Creek-Frm TP# 7041). 12. Existing Point of Interconnection between 100,000 Seller and S. W. Sumrall Field and Holiday Creek at M.P. 692.05-Holiday Creek in Jefferson Davis, Mississippi. (M.P. 692.05- Holiday Creek TP# 7159) 13. Exiting Point of Interconnection between 100,000 Seller and ANR Pipe Line Company at Holiday Creek (Seller Meter No. 3241), Jefferson Davis County, Mississippi. (Holiday Creek-ANR TP# 398) |
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
EXHIBIT "A"
(Continued)
Buyer's Mainline Capacity Entitlement Point(s) of Receipt (Mcf/d)* ------------------- ----------------- 14. Existing Point of Interconnection between 100,000 Seller and Mississippi Fuel Company at Jeff Davis (Seller Meter No. 3252), Jefferson Davis County, Mississippi. (Jefferson Davis County-Miss Fuels TP# 6579)*** 15. Existing Point of Interconnection between 100,000 Seller and Meter named Jefferson Davis-Frm (Seller Meter No. 4420), in Jefferson Davis County, Mississippi. (Jefferson Davis-Frm TP# 7033) 16. Existing Point of Interconnection between 100,000 Seller and Carson Dome Field M.P. 696.41, in Jefferson Davis County, Mississippi. (M.P. 696.41-Carson Dome Field TP# 7148) 17. Existing Point of Interconnection between 100,000 Seller and Meter Station named Bassfield- ANR Company at M.P. 703.17 on Seller's Main Transmission Line (Seller Meter No. 3238), Covington County, Mississippi. (Bassfield- ANR TP# 7029) 18. Existing Point of Interconnection between 100,000 Seller and Meter named Patti Bihm # l (Seller Meter No. 3468), in Covington County, Mississippi. (Patti Bihm # 1 TP# 7629) 19. Discharge Side of Seller's Compressor 100,000 at Seller's Eminence Storage Field (Seller Meter No. 4166 and 3160) Covington County, Mississippi. (Eminence Storage TP# 5561) |
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
EXHIBIT "A"
(Continued)
Buyer's Mainline Capacity Entitlement Point(s) of Receipt (Mcf/d)* ------------------- ----------------- 20. Existing Point of Interconnection between 100,000 Seller and Dont Dome Field at M.P. 713.39 in Covington County, Mississippi. (M.P. 713.39 - Dont Dome TP# 1396) 21. Existing Point of Interconnection between 100,000 Seller and Endevco in Covington County, Mississippi. (Hattiesburg-Interconnect Storage TP# 1686) 22. Existing Point at U.P. 719.58 on Seller's 100,000 Main Transmission Line (Seller Meter No. 354.4), Centerville Dome Field, Jones County, Mississippi. (Centerville Dome Field TP# 1532) 23. Existing Point at M.P. 727.78 on 100,000 Seller's Main Transmission Line, Jones County, Mississippi. (Jones County-Gitano TP# 7166) 24. Existing Point of Interconnection between 100,000 Seller and a Meter named Koch Reedy Creek (Seller Meter No. 3333), Jones County, Mississippi. (Reedy Creek-Koch TP# 670) 25. Existing Point of Interconnection between 100,000 Seller and Meter named Sharon Field (Seller Meter No. 3000), in Jones County, Mississippi. (Sharon Field TP# 419) 26. Existing Point of Interconnection between 100,000 Seller and Tennessee Gas Transmission Company at Heidelberg (Seller Meter No. 3109), Jasper County, Mississippi. (Heidelberg- Tennessee TP# 6120)*** |
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
EXHIBIT "A"
(Continued)
Buyer's Mainline Capacity Entitlement Point(s) of Receipt (Mcf/d)* ------------------- ----------------- 27. Existing Point of Interconnection between 100,000 Seller and Mississippi Fuel Company at Clarke (Seller Meter No. 3254), Clarke County, Mississippi. (Clarke County- Miss Fuels TP# 6047)*** 28. Existing Point of Interconnection between 100,000 Seller and Meter named Clarke County-Koch at M.P. 757.29 in Clarke County, Mississippi. (Clarke County-Koch TP# 5566) 29. Existing Point of Interconnection between 100,000 Seller and Meter named M.P. 784.66 - Mobile Bay in Butler Co., Alabama (M.P. 784.66 - MB But TP #8244) |
Buyer shall not tender, without the prior consent of Seller, at any point(s) of receipt on any day a quantity in excess of the applicable Buyer's Mainline Capacity Entitlement for such point(s) of receipt.
* These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article V, 2 hereof. Receipt of gas limited to physical capacity of the receipt point.
** Receipt of gas by displacement only.
*** Receipt of gas limited to physical capacity of Seller's lateral line facilities.
87 1533 004
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
Exhibit B
Point(s) of Delivery Pressure -------------------- -------- 1. Existing interconnection between Seller Not less than fifty (50) pounds per and Alagasco at Milepost 875.80 in square inch gauge or at such other Dallas County, AL (Selma). pressures as may be agreed upon in the day-to-day operations of Buyer and Seller. 2. Existing interconnection between Seller Not less than fifty (50) pounds per and Alagasco at Milepost 904.06 in square inch gauge or at such other Chilton County, AL (Verbena). pressures as may be agreed upon in the day-to-day operations of Buyer and Seller. 3. Seller's Eminence Storage Field, Prevailing pressure in Seller's Covington County, MS. pipeline system not to exceed maximum allowable operating pressure. |
EXHIBIT 21
SUBSIDIARIES OF ENERGEN CORPORATION
Alabama Gas Corporation*
Energen Resources Corporation*
Energen Resources TEAM, Inc.*
* Incorporated in the State of Alabama
EXHIBIT 23(A)
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 March 2, 2004 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 12, 2004
EXHIBIT 23(B)
CONSENT
We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-43245 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 to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K.
Ryder Scott Company, L.P.
Houston, Texas
March 1, 2004
EXHIBIT 23(C)
CONSENT
We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-43245 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 to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K.
Miller and Lents, Ltd.
Birmingham, Alabama
March 12, 2004
EXHIBIT 23(D)
CONSENT
We hereby consent to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K. In addition, we hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (File No. 333-00395, File No. 333-43245 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 to the reference to our firm name and our review of the estimates of proved reserves of natural gas, oil and natural gas liquids that Energen Corporation attributed to its net interests in oil and gas properties located in the U.S. as of December 31, 2003, which appears in this Form 10-K.
T. Scott Hickman & Associates, Inc.
March 12, 2004
EXHIBIT 31(A)
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 officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
March 12, 2004 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 |
EXHIBIT 31(B)
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 officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
March 12, 2004 By /s/ G. C. Ketcham -------------- ----------------------------------- G. C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation |
EXHIBIT 32
CERTIFICATION PURSUANT TO
18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Report of Energen Corporation and Alabama Gas Corporation (the "Registrants") on Form 10-K for the period ended December 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned hereby certifies with respect to each registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Dated as of March 12, 2004
By /s/ Wm. Michael Warren, Jr. ------------------------------ Wm. Michael Warren, Jr. Chief Executive Officer By /s/ G. C. Ketcham ------------------------------ G. C. Ketcham Chief Financial Officer |
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Energen Corporation and Alabama Gas Corporation and will be retained by Energen Corporation and Alabama Gas Corporation and furnished to the Securities and Exchange Commission or its staff upon request.