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Energen 10-K 2006 Documents found in this filing:
Table of ContentsUNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2005
FOR THE TRANSITION PERIOD FROM TO
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:
Securities Registered Pursuant to Section 12(g) of the Act: NONE
Indicate by check mark if the registrants are a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES x NO ¨ Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES ¨ NO x Indicate by a check mark whether registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. YES x NO ¨ Indicate by a check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (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 a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act).
Aggregate market value of the voting stock held by non-affiliates of the registrants as of June 30, 2005:
Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO x Indicate number of shares outstanding of each of the registrant’s classes of common stock as of March 2, 2006:
Alabama Gas Corporation meets the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format pursuant to General Instruction I(2). DOCUMENTS INCORPORATED BY REFERENCE Energen Corporation Proxy Statement to be filed on or about March 24, 2006 (Part III, Item 10-13)
Table of ContentsINDUSTRY 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.
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Table of Contents2005 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS
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Table of ContentsThis Form 10-K is filed on behalf of Energen Corporation (Energen or the Company) and Alabama Gas Corporation (Alagasco). Forward-Looking Statements: Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisition, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise. All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, our ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict. Third Party Facilities: The forward-looking statements also assume generally uninterrupted access to third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources Corporation, the Company’s oil and gas subsidiary, relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company. Energen Resources Production: 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. Energen Resources Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas prices could materially affect the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options and fixed- price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position. Alagasco Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts.
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Table of ContentsA substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position. Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows. Alagasco Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company. 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 principal 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. The Company maintains a Web site with the address www.energen.com. The Company does not include the information contained on its Web site as part of this report nor is the information incorporated by reference into this report. The Company makes available free of charge through its Web site the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to these reports. Also, these reports are available in print upon shareholder request. These reports are provided as soon as reasonably practicable after being electronically filed with or furnished to the Securities and Exchange Commission. The Company’s Web site also includes its Code of Ethics, Corporate Governance Guidelines, Audit Committee Charter, Officers’ Review Committee Charter, Governance and Nominations Committee Charter and Finance Committee Charter each of which is available in print upon shareholder request. Financial Information About Industry Segments The information required by this item is provided in Note 22, Industry Segment Information, in the Notes to Financial Statements.
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Table of ContentsNarrative Description of Business
General: Energen’s oil and gas operations focus on increasing production and adding proved reserves through the acquisition and development of oil and gas properties. To a lesser extent, Energen Resources explores for and develops new reservoirs, primarily in areas in which it has an operating presence. Substantially all gas, oil and natural gas liquids production is sold to third parties. Energen Resources also provides operating services in the Black Warrior, San Juan and Permian basins for its joint interest and third parties. These services include overall project management and day-to-day decision-making relative to project operations. At the end of 2005, Energen Resources’ proved oil and gas reserves totaled 1,722 billion cubic feet equivalent (Bcfe). Substantially all of these reserves are located in the San Juan Basin in New Mexico, the Permian Basin in west Texas and the Black Warrior Basin in Alabama. Approximately 81 percent of Energen Resources’ year-end reserves are proved developed reserves. Energen Resources’ reserves are long-lived, with a year-end reserves-to-production ratio of 19 years. Natural gas represents approximately 63 percent of Energen Resources’ proved reserves, with oil representing approximately 26 percent and natural gas liquids comprising the balance. Growth Strategy: Energen has operated for more than ten years under a strategy to grow its oil and gas operations. Since the end of fiscal year 1995, Energen Resources has invested approximately $1.2 billion in property acquisitions, $838 million in related development, and $119 million in exploration and related development. Energen Resources’ capital investment for oil and gas activities over the five-year period ending December 31, 2010, is currently expected to approximate $372 million for development on existing properties and $38 million for exploratory and other activities. As an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. These investments would result in capital expenditures different than those outlined above. The Company is prepared to invest approximately $1 billion over the next five years for property acquisitions that meet Energen’s acquisition criteria. 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 will consider acquisitions of other types of properties which meet its investment requirements. In addition, Energen Resources may conduct limited exploration activities primarily in areas in which it has operations and remains open to considering exploration activities which complement its core expertise and meet its investment requirements. Following an acquisition, Energen Resources focuses on increasing production and reserves through development of the properties’ PUD and behind-pipe reserve potential as well as engaging in other activities. These activities include development well drilling, limited exploration, behind-pipe recompletions, pay-adds, workovers, secondary recovery and operational enhancements. Energen Resources prefers to operate its properties in order to better control the nature and pace of development activities. Energen Resources’ 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.
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Table of ContentsDuring the three years ended December 31, 2005, the Company’s development efforts have added 295 Bcfe of proved reserves from the drilling of 929 gross development wells and 333 well recompletions and pay-adds. In 2005, Energen Resources’ successful development wells and other activities added approximately 90 Bcfe of proved reserves. The company drilled 294 gross development wells, performed some 77 well recompletions and pay-adds, and conducted other operational enhancements in 2005. Energen Resources’ production from continuing operations totaled 91 Bcfe in 2005 and is estimated to total 92 Bcfe in 2006, including 91 Bcfe of estimated production from proved reserves owned at December 31, 2005. 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. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge more than two fiscal years forward. In the case of an acquisition, Energen Resources may hedge further forward to protect targeted returns. Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of equity and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change. The Company from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, put options and swaps on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. See the Forward-Looking Statements in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 1A, Risk Factors, for further discussion with respect to price and other risks. Environmental Matters: Energen Resources is subject to various environmental regulations. Management believes that Energen Resources is in compliance with currently applicable standards of the environmental agencies to which it is subject and anticipated environmental liabilities are minimal. To the extent that Energen Resources has operating agreements with various joint venture partners, environmental costs would be shared proportionately. During 2004, the State of New Mexico issued new regulations related to below-grade storage pits. Such pits are used to temporarily hold produced fluids until they can be disposed of permanently. Under the new regulations, the storage pits must be constructed above ground or with secondary containment and visual leak detection, and all such pits will require an annual certification attesting that the storage pits do not leak. As a result of this regulation, the Company expensed $1 million as lease operating expense during 2005. During 2004, the Company capitalized $0.5 million as part of its acquisition of properties in the San Juan Basin and expensed $1.6 million as lease operating expense under this regulation. The Company does not anticipate any further remediation charges on existing properties related to the new regulations.
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
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Table of Contentsdistribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to industrial and commercial customers located on its distribution system. These transportation customers, using Alagasco as their agent or acting on their own, purchase gas directly from producers, marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system. Alagasco charges a fee to transport such customer-owned gas through its distribution system to the customers’ facilities. Alagasco’s service territory is located in central and parts of north Alabama and includes 191 cities and communities in 28 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.4 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During 2005, Alagasco served an average of 425,110 residential customers and 34,936 commercial, industrial and transportation customers. The Alagasco distribution system includes approximately 10,000 miles of main and more than 11,700 miles of service lines, odorization and regulation facilities, and customer meters. APSC Regulation: As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended RSE for a six-year period through January 1, 2008. Under the APSC order, Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the returns on equity of all major energy utilities operating under a similar methodology. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year). Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. RSE limits the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. The temperature adjustment rider to Alagasco’s rate tariff, approved by the APSC in 1990, was designed to mitigate the earnings impact of variances from normal temperatures. Alagasco calculates a temperature adjustment to customers’ monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco’s earnings. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers’ bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. Adjustments to customers’ bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider that permits 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.
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Table of ContentsGas 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, 2005, Alagasco had the following contracts in place for firm natural gas pipeline transportation and storage services:
Competition and Rate Flexibility: The price of natural gas is a significant competitive factor in Alagasco’s service territory, particularly among large commercial and industrial transportation customers. Propane, coal and fuel oil are readily available, and many industrial customers have the capability to switch to alternate fuels and/or alternate sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of flexible rate strategies to help it compete for the large customer gas load in the marketplace. Rate flexibility remains critical as the utility faces competition for this load. To date, the utility has been effective in utilizing its flexible rate strategies to minimize bypass and price-based switching to alternate fuels and alternate sources of gas. In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs; Alagasco’s core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential and its small commercial and industrial customers. In 2005, approximately 300 of Alagasco’s transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled more than $7.9 million. The Competitive Fuel Clause (CFC) and Transportation Tariff also have been important to Alagasco’s ability to compete effectively for customer load in its service territory. The CFC allows Alagasco to adjust large customer rates on a case-by-case basis to compete with alternate fuels and alternate sources of gas. The GSA rider to Alagasco’s tariff allows the Company to recover a reduction in charges allowed under the CFC because the retention of any customer, particularly large commercial and industrial transportation customers, benefits all customers by recovering a portion of the system’s fixed costs. The Transportation Tariff allows Alagasco to transport gas for customers, rather than buy and resell it to them, and is based on Alagasco’s sales profit margin so that operating margins are unaffected. During 2005 substantially all of Alagasco’s large commercial and industrial customer deliveries were the transportation of customer-owned gas. In addition, Alagasco served as gas purchasing agent for more than 99 percent of its transportation customers. Alagasco also uses long-term special contracts as a vehicle for retaining large customer load. At the end of 2005, 50 of the utility’s largest commercial and industrial transportation customers were under special contracts of varying lengths.
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Table of ContentsNatural gas service available to Alagasco customers falls into two broad categories: interruptible and firm. Interruptible service contractually is subject to interruption by Alagasco for various reasons; the most common occurrence is curtailment of industrial customers during periods of peak core market heating demand. Interruptible service typically is provided to large commercial and industrial transportation customers who can reduce their gas consumption by adjusting production schedules or by switching to alternate fuels for the duration of the service interruption. More expensive firm service, on the other hand, generally is not subject to interruption and is provided to residential and to small commercial and industrial customers; these core market customers depend on natural gas primarily for space heating. Growth: Customer growth presents a major challenge for Alagasco, given its mature, slow-growth service area. In 2005, Alagasco’s average number of customers decreased slightly. Alagasco will continue to concentrate on maintaining its current penetration levels in the residential new construction market and generating additional revenue in the small and large commercial and industrial market segments. Seasonality: Alagasco’s gas distribution business is highly seasonal since a material portion of the utility’s total sales and delivery volumes is to space heating customers. Alagasco’s rate tariff includes a temperature adjustment rider primarily for residential, small commercial and small industrial customers which substantially mitigates the effect of departures from normal temperature on Alagasco’s earnings. The calculation is performed monthly, and adjustments are made to customers’ bills in the actual month the weather variation occurs. Environmental Matters: Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns) and five manufactured gas distribution sites (one of which it still owns). An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco’s share, if any, of such costs will not materially affect the Company’s financial position, results of operations or cash flows. Employees The Company has approximately 1,500 employees, of which Alagasco employs 1,200 and Energen Resources employs 300. The Company believes that its relations with employees are good.
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Table of ContentsITEM 1A. RISK FACTORS Third Party Facilities: Energen Resources delivers to and Alagasco is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company. Energen Resources Production: 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. Energen Resources Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas prices could materially affect the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position. Alagasco Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position. Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows.
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Table of ContentsEnergen Resources Customer Concentration: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil and gas purchasers account for approximately 29 percent, 19 percent and 14 percent, respectively, of Energen Resources’ estimated 2006 production. Energen Resources’ other purchasers each bought less than 8 percent of production. Alagasco Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company. Access to Credit Markets: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by rating agency evaluations of the Company and of Alagasco. ITEM 1B. UNRESOLVED STAFF COMMENTS None
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Table of ContentsITEM 2. PROPERTIES The corporate headquarters of Energen, Alagasco and Energen Resources are located in leased office space in Birmingham, Alabama. Energen Resources maintains offices in Midland, Lehman, Seminole, Westbrook and Penwell, Texas, in Farmington, New Mexico, in Oak Grove, Vance and Tuscaloosa, 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 21, Oil and Gas Operations (Unaudited), in the Notes to Financial Statements.
The properties of Alagasco consist primarily of its gas distribution system, which includes approximately 10,000 miles of main and more than 11,700 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two LNG facilities, four division commercial offices, three division business centers, two payment centers, four district offices, six service centers, and other related property and equipment, some of which are leased by Alagasco. ITEM 3. LEGAL PROCEEDINGS Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specific relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive or other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results. Cochran County, Texas In January 2005, a lawsuit was tried in Cochran County, Texas in which the plaintiff alleged preferential purchase right claims against Energen Resources with respect to certain properties acquired by Energen Resources in 2002. The jury rendered a verdict in Energen Resources’ favor on all counts. Subsequently, in March 2005, the Judge issued a decision overruling the jury verdict. Energen Resources is pursuing an appeal of the Judge’s order and expects to prevail. Under the Judge’s order, Energen Resources potential pre-tax charge to income would be approximately $3.3 million as of December 31, 2005, none of which has been accrued. This amount includes the net cash flows attributable to the property since its acquisition. Jefferson County, Alabama In January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources’ calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. RGGS seeks a declaratory judgment with respect to the parties’ rights under the lease, reformation of the lease, monetary damages and termination of Energen Resources’ rights under the lease. The Occluded Gas Lease dated January 1, 1986 was originally between Energen Resources and United States Steel Corporation (U.S. Steel) as lessor. RGGS became the lessor under the lease as a result of a 2004 conveyance from U.S. Steel to RGGS. Approximately 120,000 acres in Jefferson and Tuscaloosa counties, Alabama, are subject to the lease. Separately on February 6, 2006, Energen Resources
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Table of Contentsreceived notice of immediate lease termination from RGGS. As of December 31, 2005, Energen’s consolidated balance sheet included approximately $96 million in net oil and gas properties associated with the lease. During 2005, Energen Resources’ production associated with the lease was approximately 11 Bcf. RGGS has adopted positions contrary to the seventeen years of course of dealing between Energen Resources and its original contracting partner, U.S. Steel. The Company believes that RGGS’ assertions are without merit and that the notice of lease termination is ineffective. Energen Resources intends to vigorously defend its rights under the lease. The Company remains in possession of the lease, believes that the likelihood of a judgment in favor of RGGS is remote, and has made no accrual with respect to the litigation or purported lease termination. Other Various other pending or threatened legal proceedings are in progress currently and the Company has accrued a provision for the estimated liability. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of 2005.
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Table of ContentsEXECUTIVE OFFICERS OF THE REGISTRANTS Energen Corporation
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Table of ContentsITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Quarterly Market Prices and Dividends Paid Per Share
Energen’s common stock is listed on the New York Stock Exchange under the symbol EGN. On February 1, 2006, there were 7,662 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:
The following table summarizes information concerning purchases of equity securities by the issuer:
Share and per share data have been restated to reflect a 2-for-1 stock split effective June 1, 2005.
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Table of ContentsITEM 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
All information has been restated to reflect a 2-for-1 stock split effective June 1, 2005.
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Table of ContentsSELECTED BUSINESS SEGMENT DATA Energen Corporation
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Table of ContentsITEM 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. The application of these accounting policies necessarily requires managements’ most subjective or complex judgments regarding estimates and projected outcomes of future events which could have a material impact on the financial statements: Oil and Gas Operations Accounting for Natural Gas and Oil Producing Activities and Related Reserves: The Company utilizes the successful efforts method of accounting for its natural gas and oil producing activities. Under this accounting method, acquisition and development costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of total proved and proved developed reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Estimated oil and gas reserves are based on currently available reservoir data and are subject to future revision. Estimates of physical quantities of oil and gas reserves have been determined by Company engineers. Independent oil and gas reservoir engineers have reviewed the estimates of proved reserves of natural gas, crude oil and natural gas liquids attributed to the Company’s net interests in oil and gas properties as of December 31, 2005. The independent reservoir engineers have issued reports covering approximately 91 percent of the Company’s ending proved reserves and in their judgment these estimates are reasonable in the aggregate. The Company’s production of undeveloped reserves requires the installation or completion of related infrastructure facilities such as pipelines and the drilling of development wells. Changes in oil and gas prices, operating costs and expected performance from the properties can result in a revision to the amount of estimated reserves held by the Company. If reserves are revised upward, earnings could be affected due to lower depreciation and depletion expense per unit of production. Likewise, if reserves are revised downward, earnings could be affected due to higher depreciation and depletion expense or due to an immediate writedown of the property’s book value if an impairment is warranted. The table below reflects the estimated increase in 2006 depreciation, depletion and amortization expense associated with assumed downward changes in oil and gas reserve quantities from the reported amounts at December 31, 2005.
Asset Impairments: Oil and gas developed 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’s oil and gas subsidiary, Energen Resources Corporation, makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, the Company will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows.
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Table of ContentsCash flow and fair value estimates require Energen Resources to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future. These variables can, and often do, differ from the estimates and can have a positive or negative impact on the Company’s need for impairment or on the amount of impairment. In addition, further changes in the economic and business environment can impact the Company’s original and ongoing assessments of potential impairment. Energen Resources adheres to Statement of Financial Accounting Standards (SFAS) No.19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relates to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. The Company considers a combination of geologic and engineering factors to evaluate the need for impairment of these costs. Derivatives: Energen Resources periodically enters into commodity derivative contracts to manage its exposure to oil, natural gas and natural gas liquids price volatility. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended requires all derivatives to be recognized on the balance sheet and measured at fair value. Realized gains and losses from derivatives designated as cash flow hedges are recognized in oil and gas production revenues when the forecasted transaction occurs. Energen Resources from time to time enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to be valid economic hedges. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period operating revenues, rather than in the period in which the hedge transaction is settled. Energen Resources does not enter into derivatives or other financial instruments for trading purposes. The use of derivative contracts to mitigate price risk may cause the Company’s financial position, results of operations and cash flow to be materially different from results that would have been obtained had such risk mitigation activities not occurred. Natural Gas Distribution Regulated Operations: Alabama Gas Corporation (Alagasco), Energen’s utility subsidiary, applies SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to its regulated operations. This standard requires a cost to be capitalized as a regulatory asset that otherwise would be charged to expense if it is probable that the cost is recoverable in the future through regulated rates. Likewise, if current recovery is provided for a cost that will be incurred in the future, SFAS No. 71 requires the cost to be recognized as a regulatory liability. The Company anticipates SFAS No. 71 will continue as the applicable accounting standard for its regulated operations. Alagasco’s rate setting methodology, Rate Stabilization and Equalization, has been in effect since 1983. Consolidated Employee Pension Plans: The Company calculates net periodic pension expense and liabilities on an actuarial basis under the provisions of SFAS No. 87, “Employers’ Accounting for Pensions.” The key assumptions used in determining these calculations are disclosed in Note 5, Employee Benefit Plans, in the Notes to Financial Statements. Actuarial assumptions attempt to anticipate future events and are used in calculating the expenses and liabilities related to these plans. The calculation of the liability related to the Company’s defined benefit pension plans requires assumptions regarding the appropriate weighted average discount rate, estimated weighted average rate of increase in the compensation level of its employee base and the expected long-term rate of return on the plans’ assets. The selection and use of such assumptions affects the amount of expense recorded in the Company’s financial statements related to its defined benefit pension plans. In selecting the discount rate, consideration is given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments. The discount rate used for actuarial purposes covering a majority of employees was 5.75 percent for the year ended December 31, 2005. A
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Table of Contentshypothetical 25 basis point change in the discount rate would impact total pension expense by approximately $1,010,000. The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The return on assets used for actuarial purposes was 8.5 percent for the year ended December 31, 2005. A hypothetical 25 basis point change in the return on assets would impact total pension expense by approximately $320,000. The estimated weighted average rate of increase in the compensation level of the Company’s employees was 4 percent for the year ended December 31, 2005. A hypothetical 25 basis point change in the estimated rate of increase in the compensation level of applicable employees would impact total pension expense by approximately $670,000. The discount rate, return on plan assets and estimated rate of compensation increase used in the actuarial assumptions for 2006 is 5.5 percent, 8.5 percent, and 3.5 percent, respectively. Asset Retirement Obligation: The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligation for its recorded amount and the resulting gain or loss. Energen Resources has an obligation to remove tangible equipment and restore land at the end of oil and gas production operations. Alagasco has certain removal cost obligations related to its gas distribution assets and a conditional asset retirement obligation to purge and cap its distribution and transmission lines upon abandonment. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in contractual, regulatory, political, environmental, safety and public relations considerations. RESULTS OF OPERATIONS Consolidated Net Income Energen Corporation’s net income for the year ended December 31, 2005 totaled $173 million, or $2.35 per diluted share and compared favorably to the year ended December 31, 2004 net income of $127.5 million, or $1.74 per diluted share. This 35.1 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 3.5 billion cubic feet equivalent (Bcfe) increase in production volumes from Energen Resources. For the year ended December 31, 2005, Energen Resources earned $135.3 million, as compared with $94.1 million in the previous year. Alagasco generated a 9.4 percent increase in net income, earning $37 million in the current year as compared with net income in the prior period of $33.8 million. For the year ended December 31, 2003, Energen reported earnings of $110.7 million, or $1.55 per diluted share. 2005 vs 2004: Energen Resources’ net income rose 43.8 percent to $135.3 million in 2005. Energen Resources’ income from continuing operations totaled $135.2 million in 2005 as compared with $93.9 million in 2004. Discontinued operations in 2005 generated income of $126,000 as compared with income of $158,000 in 2004. The primary factors positively influencing income from continuing operations included increased commodity prices of approximately $62 million after-tax along with the impact of increased production volumes of approximately $10 million after-tax. These increases were partially offset by higher lease operating expense of approximately $16 million after-tax, higher production taxes of approximately $9 million after-tax, increased depreciation, depletion and amortization (DD&A) expense of approximately $5 million after-tax and increased administrative expenses of approximately $5 million after-tax. Alagasco earned net income of $37 million in 2005 as compared with net income of $33.8 million in 2004. This increase in earnings largely reflected the utility’s ability to earn on a higher level of equity. Alagasco’s return on average equity (ROE) was 13.5 percent in 2005 compared with 12.8 percent in 2004. 2004 vs 2003: For the year ended December 31, 2004, Energen Resources’ net income totaled $94.1 million as compared with $78.9 million for the 12 months ended December 31, 2003. Energen Resources’ income from continuing operations totaled $93.9 million in 2004 as compared with $78.4 million in 2003, primarily due to higher commodity prices of approximately $31 million after-tax along with the impact of increased production volumes of approximately $6 million after-tax. The primary negative influences on income from continuing operations were higher lease operating expense of approximately $7 million after-tax, higher production taxes of approximately $6 million after-tax and increased administrative expenses of approximately $4 million after-tax.
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Table of ContentsAlagasco earnings increased to $33.8 million in 2004 from $33 million in 2003 largely as a result of the utility earning on a higher level of equity. Alagasco achieved a ROE of 12.8 percent in 2004 compared with 13.5 percent in 2003. Operating Income Consolidated operating income in 2005, 2004 and 2003 totaled $315.7 million, $244.8 million and $217.6 million, respectively. This growth in operating income has been influenced by strong financial performance from Energen Resources under Energen’s diversified growth strategy, implemented in fiscal 1996. Alagasco also contributed to this growth in operating income consistent with increases in the levels of equity upon which it has been able to earn a return. Oil and Gas Operations: Revenues from oil and gas operations rose in the current year largely as a result of increased commodity prices and increased production volumes. Increases in production primarily related to the August 2004 purchase of San Juan Basin coalbed methane properties and increased drilling of wells in North Louisiana. Negatively affecting production was a normal production decline in excess of new production coming on-line primarily in the Permian Basin. Revenue per unit of production for natural gas production increased 23.8 percent to $5.99 per thousand cubic feet (Mcf), oil revenue per unit of production rose 22.8 percent to $35.18 per barrel and natural gas liquids revenue per unit of production increased 22.2 percent to an average price of $0.55 per gallon during 2005. Production from continuing operations increased 4 percent to 91 Bcfe during 2005. Natural gas production rose 6.8 percent to 61 billion cubic feet (Bcf) and oil volumes declined 3.4 percent to 3,316 thousand barrels (MBbl). Production of natural gas liquids increased 3.4 percent to 70.5 million gallons (MMgal). In 2004, revenues from oil and gas operations increased primarily as a result of increased commodity prices, an increase in volumes related to the August 2004 acquisition of coalbed methane properties and additional drilling of coalbed methane wells in the San Juan and Black Warrior basins. Revenue per unit of production related to natural gas increased 13.9 percent to $4.84 per Mcf, oil revenues per unit of production rose 12.1 percent to $28.66 per barrel and natural gas liquids revenue per unit of production increased 15.4 percent to an average price of $0.45 per gallon during the year ended December 31, 2004. Production from continuing operations rose 2.6 percent to 87.5 Bcfe in 2004. Natural gas production increased 3.4 percent to 57.2 Bcf, oil volumes increased slightly to 3,434 MBbl and natural gas liquids production increased 2.4 percent to 68.2 MMgal. Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes and operating expenses. Revenues from operating fees were $8.7 million, $6.6 million and $6.1 million in 2005, 2004 and 2003, respectively.
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Table of ContentsEnergen 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”. During 2005, Energen Resources recorded a pre-tax gain of $213,000 primarily from a property sale located in the Permian Basin. Energen Resources had no property sales during 2004. In 2003, Energen Resources recorded a pre-tax gain of $9.4 million in discontinued operations from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in 2003 for a pre-tax gain of $0.4 million. Operations and maintenance (O&M) expense increased $31.1 million and $19 million in 2005 and 2004, respectively. Lease operating expense (excluding production taxes) in 2005 increased $25.1 million primarily due to increased workover and maintenance expenses, increased ad valorem taxes, higher transportation costs and other overall price increases related to higher commodity prices. Partially offsetting these increases were lower compliance costs related to prior year regulations for below-grade storage pits. In 2004, lease operating expense (excluding production taxes) increased by $11.4 million primarily due to increased workover and maintenance expense, costs associated with storage pit regulatory requirements and higher transportation costs. Administrative expense increased $7.5 million in 2005 largely due to labor-related costs. In 2004, administrative expense increased $6.6 million primarily due to labor-related costs as well as costs related to the San Juan Basin property acquisition. Exploration expense decreased $1.4 million in 2005 largely due to decreased exploratory efforts. In 2004, exploration expense increased $1 million. DD&A expense increased $8.4 million in 2005 and $1.4 million in 2004. The average depletion rates were $0.96 per Mcfe in 2005, $0.90 per Mcfe in 2004 and $0.92 per Mcfe in 2003. The increase in the 2005 rate was largely due to a higher depletion rate on coalbed methane properties purchased in the prior year as well as to the current year production mix that reflects a higher percentage of the Company’s shorter-lived North Louisiana/East Texas production. Increased production volumes also contributed to the increase in DD&A expense during 2005. Energen Resources’ expense for taxes other than income primarily reflected production-related taxes. Energen Resources recorded severance taxes of $52.3 million, $37.3 million and $27.7 million for 2005, 2004 and 2003, respectively. Increased severance taxes were the result of increased commodity prices and production. Natural Gas Distribution: As discussed more fully in Note 2, Regulatory Matters, in the Notes to Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend the utility’s rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the company and a hearing, the Commission votes to either modify or discontinue its operation. Alagasco generates revenues through the sale and transportation of natural gas. The transportation rate does not contain an amount representing the cost of gas, and Alagasco’s rate structure allows similar margins on transportation and sales gas. Weather can cause variations in space heating revenues, but operating margins essentially remain unaffected due to a temperature adjustment mechanism that requires Alagasco to adjust certain customer bills monthly to reflect changes in usage due to departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.
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Table of ContentsAlagasco’s natural gas and transportation sales revenues totaled $600.7 million, $526.7 million and $489.1 million in 2005, 2004 and 2003, respectively. Sales revenue in 2005 and 2004 increased primarily due to an increase in commodity gas costs. In 2005, weather was 3.6 percent colder than in the prior year. Residential sales volumes declined 3.1 percent while commercial and industrial volumes increased 1.4 percent. Large transportation volumes decreased 8.3 percent primarily related to higher gas prices. During 2004, weather that was 6 percent warmer than in the prior year contributed to a 6.8 percent decline in residential sales volumes and a 1.9 percent decrease in commercial and industrial volumes. Large transportation volumes decreased 2.2 percent. In 2005, higher commodity gas costs along with increased gas purchase volumes contributed to a 21.6 percent increase in cost of gas. Higher commodity gas cost generated a 10.9 percent increase in cost of gas in 2004. O&M expense at the utility increased 3.4 percent in 2005 largely due to higher bad debt expense and distribution maintenance expenses. These increases were partially offset by decreased labor-related expense, primarily as a result of additional labor costs capitalized in the current year. In 2004, O&M expense increased 6.9 percent primarily due to increased labor-related costs. The increase in O&M expense per customer for the rate years ended September 30, 2004 and 2003 were above the inflation-based Cost Control Measurement (CCM) established by the APSC as part of the utility’s rate-setting mechanism; as a result, three quarters of the differences, or $1.2 million and $0.1 million pre-tax, respectively, were returned to the customers through RSE (see Note 2, Regulatory Matters, in the Notes to Financial Statements). Alagasco’s O&M expense fell within the index range for the rate year ended September 30, 2005. Depreciation expense rose 6.2 percent and 7.3 percent in 2005 and 2004, respectively, due to normal growth of the utility’s distribution and support systems. Alagasco’s expense for taxes other than income primarily reflects various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.
Non-Operating Items Consolidated: Interest expense in 2005 increased $4.1 million primarily due to the issuance of $100 million of Floating Rate Senior Notes by Energen in November 2004, Alagasco’s issuance of $80 million of long-term debt in January 2005 and Alagasco’s $80 million issuance of long-term debt in November 2005. Positively impacting interest expense was Alagasco’s redemption of $56.7 million, $18 million and $30 million of long-term debt in December 2005, August 2005 and April 2004, respectively. Interest expense in 2004 increased $0.5 million largely due to a full year’s interest on $50 million of long-term debt issued by Energen in October 2003 and increased short-term borrowings due to the acquisition of San Juan Basin coalbed methane properties in August 2004. The average daily outstanding balance under short-term credit facilities was $17.7 million in 2005. The average daily outstanding balance under short-term credit facilities was $92.6 million in 2004 as compared to $81.1 million in 2003.
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Table of ContentsIncome tax expense increased in the periods presented primarily due to higher pre-tax income. As of December 31, 2005, the amount of minimum tax credit that has been previously recognized and can be carried forward indefinitely to reduce future regular tax liability is $34.8 million. Exposure to Natural Disaster The Company’s production properties and distribution system did not suffer significant damage from Hurricanes Katrina and Rita which occurred in the third quarter of 2005. Energen Resources experienced minimal loss of production and Alagasco had no significant supply disruptions as a result of these hurricanes. These events, however, highlight the potential for a period of production shut-in for Energen Resources resulting from a prolonged interruption of service in areas which have a concentration of fractionation plants and refineries through which a substantial portion of the Company’s natural gas liquids and oil production flow. Alagasco’s customer base is geographically concentrated in central Alabama. Damage to Alagasco’s delivery infrastructure, Energen Resources’ production infrastructure or to third party facilities which serve Alagasco and/or Energen Resources due to a natural disaster or other event could result in significant adverse financial consequences to Alagasco and/or the Company. FINANCIAL POSITION AND LIQUIDITY The Company’s net cash from operating activities totaled $335.1 million, $291.1 million and $243.1 million in 2005, 2004 and 2003, respectively. Operating cash flow in 2005, 2004 and 2003 benefited from higher realized commodity prices and production volumes at Energen Resources. During the periods presented, working capital needs at Alagasco were primarily affected by increased gas costs compared to the prior period and storage gas inventory. Other working capital items, which primarily are the result of changes in throughput and the timing of payments, combined to create the remaining increases for all years. During 2005, the Company made net investments of $400.7 million. Energen Resources invested $188.4 million in property acquisitions, $157.5 million for development costs including approximately $123 million to drill 294 gross development wells and $5.1 million for exploration. In December 2005, Energen Resources completed its purchase of oil properties located in the Permian Basin from a private company for a contract price of approximately $168 million. The acquisition added approximately 131 Bcfe of proved reserves and had an effective date of November 1, 2005. Energen Resources sold certain properties during 2005, resulting in cash proceeds of $10.8 million. Utility expenditures in 2005 totaled $73.3 million and primarily represented system distribution expansion and support facilities. Cash used in investing activities totaled $453.4 million in 2004. Energen Resources invested $274.4 million in property acquisitions, $124.6 million for development costs including approximately $89 million to drill 288 gross development wells and $5 million for exploration. In August 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million adding approximately 245 Bcfe of proved reserves. Utility expenditures in 2004 totaled $58.2 million. During 2003, the Company made net investments of $190.4 million. Energen Resources invested $40.5 million in property acquisitions, $121.9 million for development costs including approximately $89 million to drill 347 gross development wells and $0.4 million for exploration. Energen Resources sold certain properties during 2003, resulting in cash proceeds of $29.1 million. Utility expenditures in 2003 totaled $57.9 million. During 2005, the Company added approximately 131 Bcfe of reserves from the Permian Basin acquisition. Energen Resources expects this acquisition to utilize approximately $9 million, net of development costs, of pretax cash flows in 2006. Over the five-year period ending December 31, 2010, the Company expects this acquisition to contribute approximately $14 million, net of development costs, to pretax cash flows. Also during 2005, Energen Resources added 90 Bcfe of reserves from discoveries and other additions, primarily the result of improved drilling technology that increased the number of available drilling locations for certain wells in the San Juan Basin as well as continued downspacing in the Permian Basin. Energen Resources added approximately 315 Bcfe and 236 Bcfe of reserves in 2004 and 2003, respectively. In 2005, net cash provided from financing activities totaled $69.8 million. In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. In November 2005, Alagasco issued $80 million of long-term debt with an interest rate of 5.368 percent due December 1, 2015. Long-term debt was reduced by $84.8
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Table of Contentsmillion including Alagasco’s redemption of $18 million in Medium-Term Notes maturing June 27, 2007 to July 5, 2022 in August 2005 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 in December 2005. The Company provided $164.6 million from financing activities in 2004. Energen issued $100 million of Floating Rate Senior Notes in November 2004. Long-term debt was reduced by $40.1 million in 2004, including $30 million of Medium-Term Notes called by Alagasco in April 2004. In 2003, net cash used in financing activities totaled $55.4 million. In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration which generated net proceeds of $32.1 million. Energen issued $50 million of long-term debt in October 2003. Long-term debt was reduced by $23 million for current maturities in 2003. 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 benefit plans. Capital Expenditures Oil and Gas Operations: Energen Resources spent a total of $924.3 million for capital projects during the years ended December 31, 2005, 2004 and 2003. Property acquisition expenditures totaled $503.3 million, development activities totaled $403.9 million, and exploratory expenditures totaled $10.5 million.
Natural Gas Distribution: During the years ended December 31, 2005, 2004 and 2003, Alagasco invested $189.4 million for capital projects: $134.1 million for normal expansion, replacements and support of its distribution system and $55.3 million for support facilities, including the replacement of liquifaction equipment and the development and implementation of information systems.
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, 2005, Energen’s EPS grew at an average compound rate of 19.8 percent a year. Over the next five years, Energen is targeting an average diluted EPS growth rate over each rolling five-year period of approximately 7 to 8 percent a year. Over the five-year planning period ending December 31, 2010, Energen Resources’ plans to spend approximately $372 million for development of existing properties and $38 million for exploratory and other activities. During the five year period, Energen Resources anticipates spending approximately $271 million on development of previously identified proved undeveloped reserves and incurring approximately $29 million in exploratory exposure. In 2006, Energen Resources plans to invest approximately $153 million in capital expenditures primarily for development and exploratory activities. Included in this $153 million is approximately $87 million for the development of previously identified proved undeveloped reserves. Approximately $6 million is estimated for
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Table of Contentsexploratory exposure in 2006. Capital investment at Energen Resources in 2007 is expected to approximate $87 million for development and exploration. Of this $87 million, development of previously identified proved undeveloped reserves is estimated to be $71 million and exploratory exposure is estimated to be $6 million. 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 will pursue acquisitions that meet Energen’s acquisition criteria which could result in capital expenditures different than those outlined above. The Company is prepared to invest approximately $1 billion over the next five years in addition to the estimates given above, for property acquisitions that meet Energen’s acquisition criteria. In addition, Energen Resources may conduct limited exploration activities primarily in areas in which it has operations and remains open to considering exploration activities which complement its core expertise and meet its investment requirements. To finance Energen Resources’ investment program, the Company expects primarily to utilize its short-term credit facilities to supplement internally generated cash flow. The Company may also periodically issue long-term debt and equity to replace short-term obligations, enhance liquidity and provide for permanent financing. Energen currently has available short-term credit facilities aggregating $320 million to help finance its growth plans and operating needs. Energen Resources’ continued ability to invest in property acquisitions is subject to market conditions and industry trends. Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, higher workover and maintenance expenses, increased taxes and other field-service-related expenses. The Company anticipates influences such as weather, natural disasters, changes in global economics and political unrest will continue to contribute to increased price volatility in the near term. For the 2005-2006 winter heating season, Alagasco has hedged or intends to use storage for its estimated, weather-normalized, core-market gas supply purchases. The Company’s efforts to minimize commodity price volatility through hedging is reflected in Alagasco’s current rates. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Company’s cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management gains and losses. Sustained high prices may decrease Alagasco’s customer base and could result in a decline of per customer use and number of customers. The utility will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are impacted by natural gas prices. In December 2005, the APSC requested Alagasco and the other major natural gas utility under its jurisdiction to refrain from additional rate increases through the winter heating season ending March 31, 2006, citing concerns over the potential negative impact on customers from the high natural gas prices being experienced across the country following hurricanes Katrina and Rita. Alagasco agreed to comply with the APSC’s request and subsequently reduced rates in response to moderating gas prices. Alagasco maintains an investment in storage gas that is expected to average approximately $67 million in 2006 but may vary depending upon the price of natural gas. During 2006 and 2007, Alagasco plans to invest approximately $62 million and $65 million, respectively, in utility capital expenditures for normal distribution and support systems. Over the Company’s five-year planning period ending December 31, 2010, Alagasco anticipates capital investments of approximately $322 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. In January 2005, Alagasco issued $80 million in long-term debt to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes recalled by Alagasco in April 2004. In November 2005, Alagasco issued an additional $80 million of long-term debt largely to refinance $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 recalled by Alagasco in August 2005 and December 2005, respectively. 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. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets,
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Table of Contentscontinued access could be adversely affected by future economic and business conditions or credit rating downgrades. Energen and Alagasco’s corporate credit ratings are currently rated BBB+ with a stable outlook by Standard & Poor’s. Moody’s Investors Service has currently rated Energen as Baa 2 senior unsecured and Alagasco as A1 senior unsecured. Dividends Energen expects to pay annual cash dividends of $0.44 per share on the Company’s common stock in 2006. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors. On April 27, 2005, Energen’s shareholders approved a 2-for-1 split of the Company’s common stock. The split was effected in the form of a 100 percent stock dividend and was effective on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split. Contractual Cash Obligations and Other Commitments In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes the Company’s significant contractual cash obligations, other than hedging contracts, as of December 31, 2005.
Energen Resources operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement. The Company has two defined non-contributory pension plans and provides certain post-retirement healthcare and life insurance benefits. The Company is not required to make any funding payments during 2006 for the pension plans and does not currently plan to make discretionary contributions. The Company may reevaluate discretionary payments to its pension plans in the fourth quarter of 2006 based on the outcome of the September 30, 2006, measurement of pension obligations. Additionally, the Company expects to make discretionary payments of $1.4 million to post-retirement benefit program assets during 2006.
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Table of ContentsOUTLOOK Oil and Gas Operations: Energen Resources plans to continue to implement its growth strategy with capital spending in 2006 and 2007 as outlined above. Production in 2006 is estimated to reach approximately 92 Bcfe, including 91 Bcfe of estimated production from proved reserves owned at December 31, 2005. In 2007, production is estimated to be approximately 89 Bcfe, including approximately 88 Bcfe produced from proved reserves currently owned. Production estimates above do not include amounts for potential future acquisitions. In the event Energen Resources is unable to fully invest its 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. Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced natural gas and oil to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil and gas purchasers account for approximately 29 percent, 19 percent and 14 percent, respectively, of Energen Resources’ estimated 2006 production. Energen Resources’ other purchasers each bought less than 8 percent of production. Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company. In cases where these arrangements exist, the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Company’s credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company in the event credit ratings are below investment grade. At December 31, 2005, Energen Resources was in a net loss position with all counterparties but was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of December 31, 2005. The two largest counterparties represented approximately 48 percent and 22 percent of Energen Resources’ fair value of derivatives. The Company believes the creditworthiness of these counterparties is satisfactory. Energen Resources’ other counterparties each represented less than 14 percent of the fair value of derivatives. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. Energen Resources does not hedge more than 80 percent of its estimated annual production and generally does not hedge this production more than two years forward. Production may be hedged for a longer period immediately following an acquisition in order to protect targeted returns. Energen Resources entered into the following transactions for 2006 and subsequent years:
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Table of ContentsThe 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, 2005, the Company estimated that a 10 percent increase or decrease in the commodities prices would have resulted in a $73.2 million change in the fair value of open derivative contracts; however, gains and losses on derivative contracts are expected to be similarly offset by sales at the spot market price. The hypothetical change in fair value was calculated by multiplying the difference between the hypothetical price and the contractual price by the contractual volumes and did not include the impact of related taxes on actual cash prices. Natural Gas Distribution: The extension of RSE in June 2002 provides Alagasco the opportunity to continue earning an allowed ROE between 13.15 percent and 13.65 percent through January 1, 2008. Under the terms of that extension, RSE will continue beyond that date, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue its operations. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. Also as discussed in Note 2, Regulatory Matters, in the Notes to Financial Statements, 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. As required by SFAS No. 133, Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability as required by SFAS No. 71. At December 31, 2005, Alagasco recorded a $6.3 million loss as a liability in accounts payable with a corresponding current regulatory asset of $6.3 million representing the fair value of derivatives. The gains or losses related to these derivative contracts, as adjusted for any changes in the fair value, will be recognized in the GSA during the first quarter of 2006. Forward-Looking Statements: Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company’s forward-looking statements do not reflect the impact of possible or pending acquisition, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.
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Table of ContentsAll statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, our ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict. Third Party Facilities: The forward looking statements also assume generally uninterrupted access to third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company. Energen Resources Production: 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. Energen Resources Hedging: Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate price risk, fluctuations in future oil and gas prices could materially affect the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps and fixed price contracts. A substantial failure to meet sales volume targets whether caused by miscalculations, weather events, natural disaster, accident, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position. Alagasco Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position. Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows.
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Table of ContentsAlagasco Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB) In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment (SFAS No. 123R),” which requires a fair value base method of accounting using pricing models that reflect the specific economics of a company’s transactions. This statement is effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 as amended, which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company will adopt SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. Although, the Company is currently evaluating its stock-based compensation and the application of SFAS No. 123R, it does not anticipate that the adoption of SFAS No. 123R will have a material impact on the financial condition or results of operations of the Company. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards will be made in the form of Company common stock with no portion of an award paid in cash. Accordingly, the Company will value such awards at fair value under the provisions of SFAS No. 123R as of the date of modification or grant. During April 2005, the FASB issued FSP No. 19-1, “Accounting for Suspended Well Costs,” which allows exploratory wells to be capitalized when the well has a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. This interpretation was effective for the first reporting period beginning after April 4, 2005. The Company has adopted this standard and has no exploratory wells with capitalized costs that exceed more than one year. In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 (Accounting Changes) and FASB Statement No. 3 (Reporting Accounting Changes in Interim Financial Statements)”. Opinion No. 20 required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. 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.
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Table of ContentsITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ALABAMA GAS CORPORATION INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.
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Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Energen Corporation: We have completed an integrated audit of Energen Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below. Consolidated financial statements and financial statement schedule In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Energen Corporation and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. Internal control over financial reporting Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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Table of ContentsBecause of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PricewaterhouseCoopers LLP Birmingham, Alabama March 15, 2006 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholder of Alabama Gas Corporation: In our opinion, the financial statements of Alabama Gas Corporation listed in the accompanying index present fairly, in all material respects, the financial position of Alabama Gas Corporation at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. PricewaterhouseCoopers LLP Birmingham, Alabama March 15, 2006
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Table of ContentsCONSOLIDATED STATEMENTS OF INCOME Energen Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsCONSOLIDATED BALANCE SHEETS Energen Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsCONSOLIDATED BALANCE SHEETS Energen Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsCONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY Energen Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsCONSOLIDATED STATEMENTS OF CASH FLOWS Energen Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsSTATEMENTS OF INCOME Alabama Gas Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsBALANCE SHEETS Alabama Gas Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsBALANCE SHEETS Alabama Gas Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsSTATEMENTS OF SHAREHOLDER’S EQUITY Alabama Gas Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of ContentsSTATEMENTS OF CASH FLOWS Alabama Gas Corporation
The accompanying Notes to Financial Statements are an integral part of these statements.
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Table of Contents1. 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.
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.
Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves. Gains and losses in the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for current and prior periods. Operating Revenue: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no material production imbalances at December 31, 2005 and 2004. Derivative Commodity Instruments: Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company. In cases where these arrangements exist, the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Company’s credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company in the event credit ratings are below investment grade.
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Table of ContentsEnergen Resources applies Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended 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 effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income as a component of shareholders’ equity and subsequently reclassified to operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized in operating revenues immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 are recorded at fair value with gains or losses recognized in operating revenues in the period of change. Additionally, the Company may also enter into derivatives that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, basis hedges without a corresponding NYMEX hedge, put options and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness in hedging the exposure to the hedged transaction’s variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.
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, 2005, 2004 and 2003. Inventories: Inventories, which consist primarily of gas stored underground, are stated at average cost. Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2005 and 2004. Regulatory Accounting: Alagasco is subject to the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” In general, SFAS No. 71 requires utilities to capitalize or defer certain costs or revenues, based upon approvals received from regulatory authorities, to be recovered from or refunded to customers in future periods.
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Table of ContentsDerivative Commodity Instruments: On December 4, 2000, the APSC authorized Alagasco to engage in energy-risk management activities. Accordingly, Alagasco from time to time enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability as required by SFAS No. 71. Taxes on revenues: Collections and payments of excise taxes are reported on a gross basis. These amounts are included in taxes other than income taxes on the consolidated statements of income as follows:
The Company uses the liability method of accounting for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.
Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The Company determines the allowance based on historical experience and reviews the allowance for doubtful accounts monthly. Account balances are charged off against the allowance when it is anticipated the receivable will not be recovered.
The Company includes highly liquid marketable securities and debt instruments purchased with a maturity of three months or less in cash equivalents.
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).
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 January 1, 2003. Awards under the Company’s plan vest over periods ranging from one to six years; therefore, the cost related to stock-based employee compensation included in the determination of net income is different than that which would have been recognized if the fair value method had been applied to all awards. The following table illustrates the effect on net income and diluted earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period:
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