-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Fv+IzCFO+Tfs+ntN1gA0NcxwV7a4sf8UwTZIINGzs99gkMs+Pd8re5P0KOa3ULCp lSvDe65UuhXFMPsYyUU8pQ== 0000950144-97-013534.txt : 19971223 0000950144-97-013534.hdr.sgml : 19971223 ACCESSION NUMBER: 0000950144-97-013534 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19970930 FILED AS OF DATE: 19971222 SROS: CSX SROS: NYSE SROS: PHLX FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENERGEN CORP CENTRAL INDEX KEY: 0000277595 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 630757759 STATE OF INCORPORATION: AL FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-07810 FILM NUMBER: 97741765 BUSINESS ADDRESS: STREET 1: 2101 SIXTH AVE N CITY: BIRMINGHAM STATE: AL ZIP: 35203 BUSINESS PHONE: 2053262742 MAIL ADDRESS: STREET 1: 2101 SIXTH AVE N CITY: BIRNINGHAM STATE: AL ZIP: 35203 FORMER COMPANY: FORMER CONFORMED NAME: ALAGASCO INC DATE OF NAME CHANGE: 19851002 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ALABAMA GAS CORP CENTRAL INDEX KEY: 0000003146 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 630022000 STATE OF INCORPORATION: AL FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 033-70466 FILM NUMBER: 97741766 BUSINESS ADDRESS: STREET 1: 2101 SIXTH AVE NORTH CITY: BIRMINGHAM STATE: AL ZIP: 35203 BUSINESS PHONE: 2053262742 MAIL ADDRESS: STREET 1: 2101 SIXTH AVE NORTH CITY: BIRMINGHAM STATE: AL ZIP: 35203 10-K405 1 ENERGEN CORPORATION /ALABAMA GAS CORPORATION 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED SEPTEMBER 30, 1997 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___
COMMISSION IRS EMPLOYER FILE STATE OF IDENTIFICATION NUMBER REGISTRANT INCORPORATION NUMBER - ------------------------------------------------------------------------------- 1-7810 Energen Corporation Alabama 63-0757759 2-38960 Alabama Gas Corporation Alabama 63-0022000
2101 Sixth Avenue North Birmingham, Alabama 35203 (205) 326-2700 http://www.energen.com Securities Registered Pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS EXCHANGE ON WHICH REGISTERED - ------------------- ---------------------------- Energen Corporation Common Stock, $0.01 par value New York Stock Exchange Energen Corporation Preferred Stock Purchase Rights New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: NONE Indicate by a check mark whether registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. YES X NO --- --- Indicate by a check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X) Aggregate market value of the voting stock held by non-affiliates of the registrants as of December 10, 1997: Energen Corporation $562,453,654 Indicate number of shares outstanding of each of the registrant's classes of common stock as of December 10, 1997: Energen Corporation 14,476,686 shares Alabama Gas Corporation 1,972,052 shares Alabama Gas Corporation meets the conditions set forth in General Instruction J(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format pursuant to General Instruction J(2). DOCUMENTS INCORPORATED BY REFERENCE - - Energen Corporation Proxy Statement to be filed on or about December 22, 1997 (Part III, Item 10-13) - - Portions of Energen Corporation 1997 Annual Report to Stockholders are incorporated by reference into Part II, Items 5, 6, 7, and 8 of this report 2 ENERGEN CORPORATION 1997 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS
PAGE PART I Item 1. Business.......................................................................................3 Item 2. Properties.....................................................................................8 Item 3. Legal Proceedings..............................................................................8 Item 4. Submission of Matters to a Vote of Security Holders............................................8 PART II Item 5. Market for Registrant's Common Stock and Related Stockholder Matters..........................11 Item 6. Selected Financial Data.......................................................................11 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.....................................................................11 Item 8. Financial Statements and Supplementary Data...................................................11 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......................................................................11 PART III Item 10. Directors and Executive Officers of the Registrants...........................................12 Item 11. Executive Compensation........................................................................12 Item 12. Security Ownership of Certain Beneficial Owners and Management................................12 Item 13. Certain Relationships and Related Transactions................................................12 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..............................13
2 3 (This page intentionally left blank) 4 This Form 10-K is filed on behalf of Energen Corporation (Energen or the Company) and Alabama Gas Corporation (Alagasco). PART I ITEM 1. BUSINESS GENERAL Energen is a Birmingham-based diversified energy holding company engaged in natural gas distribution and oil and natural gas exploration and production activities. Its two major subsidiaries are Alabama Gas Corporation (Alagasco) and Taurus Exploration Inc. (Taurus). Energen was incorporated in Alabama in 1978 in connection with the reorganization of its largest 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 late 1800s. Alagasco became a public company in 1953. Taurus was formed in 1971 as a subsidiary of Alagasco and became a subsidiary of Energen in the 1978 reorganization. FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS The information required by this item is incorporated by reference from Note 15, Industry Segment Information, to the Consolidated Financial Statements of the 1997 Annual Report to Shareholders and is attached herein as Part IV, Item 14, Exhibit 13. NARRATIVE DESCRIPTION OF BUSINESS - - NATURAL GAS DISTRIBUTION GENERAL: Alagasco is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate marketers and suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. Alagasco also provides transportation services to industrial and commercial customers located on its distribution system. These transportation customers, acting on their own or using Alagasco as their agent, purchase gas directly from producers, marketers or suppliers and arrange for delivery of the gas into the Alagasco distribution system; Alagasco then charges a fee to transport this customer-owned gas through its distribution system to the customer's facility. Alagasco acted as agent for approximately 98 percent of its transportation customers in fiscal year 1997. Alagasco's service territory is located in central Alabama and in parts of north Alabama and includes more than 185 cities and communities in 27 counties. The aggregate population of the counties served by Alagasco is estimated to be 2.3 million. Among the cities served by Alagasco are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During fiscal year 1997, Alagasco served an average of 422,878 residential customers, 34,432 small commercial and industrial customers, and 54 large commercial and industrial customers. The Alagasco distribution system includes approximately 8,950 miles of main and more than 9,800 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also operates two liquefied natural gas (LNG) facilities which it uses to meet peak demand. APSC REGULATION: As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). Alagasco's rate-setting process, Rate Stabilization and Equalization (RSE), was established by the APSC in 1983, was extended with modifications in 1985, 1987 and 1990, and was further extended in 1996. RSE replaces the traditional utility rate case with quarterly reviews and adjustments designed to give 3 5 Alagasco an opportunity to earn a return on average equity at year-end within a designated range, which presently is 13.15 percent to 13.65 percent. Alagasco has earned at or near its allowed range since fiscal 1990, when RSE was modified to include a forward-looking test year. Most recently, on October 7, 1996, the APSC unanimously voted to extend RSE without change for a five-year period, through January 1, 2002. Under the terms of the extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue its operation. Under RSE as extended, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and fiscal year-to-date performance, whether Alagasco's return on equity for the fiscal 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 fiscal 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 expenses (O&M). If the change in O&M per customer falls within 1.25 percentage points above or below the Consumer Price Index for All Urban Customers (index range), no adjustment is required. If the change in O&M 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. In 1990 the APSC approved a temperature adjustment rider to Alagasco's rate tariff designed to mitigate the earnings impact of variances from normal temperatures. Alagasco performs this real-time temperature adjustment calculation monthly, and the adjustments to customers' bills are made in the same billing cycle in which the weather variations occurred. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply, including Gas Supply Realignment (GSR) surcharges. These surcharges were imposed by Alagasco's suppliers as a result of changes in gas supply purchases related to the implementation of Federal Energy Regulatory Commission (FERC) Order 636. On October 7, 1996, the APSC issued an order providing for the refund to customers of approximately $17 million of supplier refunds, including interest. Alagasco refunded these amounts to customers during January 1997. The refunds were collected from a variety of sources and most related to the settlement of rate case and FERC Order 636 proceedings of Southern Natural Gas Company (Southern). GAS SUPPLY: Alagasco's distribution system is connected to and has firm transportation contracts with two major interstate pipeline systems -- Southern and Transcontinental Gas Pipe Line Corporation (Transco). On Southern's system, Alagasco has 250,924 Mcfd (thousand cubic feet per day) of No-Notice Firm Transportation service through October 31, 2008, and 91,946 Mcfd, 40,000 Mcfd and 10,000 Mcfd of Firm Transportation service through October 31 of 2008, 2002, and 1998, respectively. Alagasco also has 12,426,687 Mcf of storage capacity on Southern's system, with a maximum withdrawal rate of 250,924 Mcfd and a maximum injection rate of 95,590 Mcfd. The Transco Firm Transportation contract, which expires in 2002, provides for up to 100,000 Mcfd. As a result, Alagasco has a peak day firm interstate pipeline transportation capacity of 492,870 Mcfd. Alagasco purchases gas from various gas producers and marketers, including affiliates of Southern and Transco, and from certain intrastate producers and marketers. Alagasco has contracts in place to purchase up to 281,468 Mcfd of firm supply, of which 241,946 Mcfd is supported by firm transportation on the Transco and Southern systems and approximately 24,000 Mcfd is purchased at the city gate under intrastate firm supply contracts. These firm supply volumes along with Alagasco's maximum withdrawal from storage of 250,924 Mcfd and LNG peak-shaving capacity of 200,000 Mcfd, give Alagasco a peak day firm supply of 732,392 Mcfd. Alagasco also utilizes the Southern and Transco pipeline systems to access spot market gas in order to supplement its firm system supply and serve its industrial and large commercial transportation customers. RATE FLEXIBILITY AND COMPETITION: The price of natural gas is a significant competitive factor in Alagasco's service territory, particularly among large commercial and industrial customers. Propane, coal and fuel oil are readily available, and many industrial customers have the capability to switch to alternate fuels and/or alternate 4 6 sources of gas. In the residential and small commercial and industrial markets, electricity is the principal competitor. With the support of the APSC, Alagasco has implemented a variety of flexible rate strategies to help it compete for the large customers' gas load in the deregulated marketplace. Rate flexibility remains critical as the utility faces intense competition for the large customer load. To date, the utility has been effective in utilizing its flexible rate strategies to limit bypass and minimize price-based switching to alternate fuels and alternate sources of gas. In 1994 Alagasco implemented the P Rate in response to the competitive challenge of interstate pipeline capacity release. Under this tariff provision, Alagasco releases much of its excess pipeline capacity and repurchases it as agent for its transportation customers under 12 month contracts. The transportation customers benefit from lower pipeline costs. Alagasco's core market customers benefit, as well, since the utility uses the revenues received from the P Rate to decrease gas costs for its residential and small commercial and industrial customers. In fiscal 1997, approximately 280 of Alagasco's transportation customers utilized the P Rate, and the resulting reduction in core market gas costs totaled approximately $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 increases the rates paid by other customers to recover the reduction in rates allowed under the CFC because the retention of any customer, particularly large commercial and industrial 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. The Transportation Tariff is based on Alagasco's sales profit margin, so net income is unaffected. The Transportation Tariff also may be adjusted under the CFC. Alagasco also uses long-term special contracts as a vehicle for retaining large customer load. At the end of fiscal 1997, 35 of the utility's largest commercial and industrial customers were under special contracts of varying lengths. During 1997 substantially all of Alagasco's large commercial and industrial customer deliveries were the transportation of customer-owned gas. In addition, Alagasco served as gas purchasing agent for approximately 98 percent of its transportation customers. Natural gas service available to Alagasco customers generally falls into two categories: interruptible and firm. Interruptible service is contractually subject to interruption by Alagasco for various reasons, the most common of which is curtailment of industrial customers during periods of peak residential heating demand. Firm service, in general, is not subject to interruption and, therefore, is more expensive. Firm service is generally provided to residential and small commercial and industrial customers, while interruptible service is generally provided to large commercial and industrial customers which typically have the capacity to reduce gas consumption by adjusting their production schedules or by switching to alternate fuels during periods of interruption. Deliveries of sales and transportation gas totaled 106,533 million cubic feet (MMcf) in fiscal 1997. GROWTH: Customer growth presents a major challenge for Alagasco, and its low customer growth rate in 1997 underscores the utility's mature nature and the slow-growth character of its service territory. Customer growth in fiscal 1997 was less than 1 percent. At the same time, the utility penetrated 89 percent of the new single-family homes built in its service territory and 27 percent of the new multi-family construction. Meanwhile, Alagasco's saturation rate of approximately 70 percent exceeds the national average of approximately 51 percent. A vehicle for supplementing Alagasco's normal growth continues to be Alagasco's municipal acquisition program. Since 1985 Alagasco has acquired 22 municipally-owned systems, adding more than 42,000 customers through initial system purchases and subsequent customer additions. Alagasco has been successful in increasing the systems' relatively low saturation rates subsequent to purchase through a variety of marketing efforts including offering natural gas service to propane customers already situated on the municipal system's lines, expanding into 5 7 nearby neighborhoods that desire natural gas service, and marketing natural gas appliances to existing and new customers. Approximately 80 municipal systems representing about 250,000 customers remain in Alabama. Although Alagasco did not acquire any new municipal gas systems in 1997, it continues to pursue their purchase and company management believes they offer future growth opportunities. WEATHER: Alagasco's gas distribution business is highly seasonal since a material portion of the utility's total sales and delivery volumes is to customers (principally residential and small commercial and industrial) whose use varies depending upon temperature. Alagasco's rate tariff includes a temperature adjustment rider which is designed to mitigate the effect of departures from normal temperature on Alagasco's earnings. The calculation is performed monthly, and adjustments are made to customers' bills in the actual month the weather variation occurs. ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former manufactured gas plant sites and five manufactured gas distribution sites. It still owns four of the plant sites and one of the distribution sites. Preliminary investigations do not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco's share of any associated costs will not materially affect the results of its operations or financial condition. OTHER: For a discussion of risks inherent in the Company's businesses, see Management's Discussion and Analysis in the 1997 Annual Report to Shareholders (pages 27 and 28) which is attached herein as Part IV, Item 14, Exhibit 13. - - OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES GENERAL: Taurus is involved primarily in the acquisition and development of producing oil and natural gas properties with varying levels of development potential and in the exploration and development of new reservoirs. Taurus also provides fee-based coalbed methane operating services in the Black Warrior Basin for its partners and third parties. All of Taurus's operations are located in the United States. At the end of fiscal 1997, Taurus's remaining recoverable reserves totaled 673.3 billion cubic feet equivalent (Bcfe) and were located primarily in Alabama, New Mexico, Texas, Mississippi, Louisiana and the Gulf of Mexico. GROWTH STRATEGY: Fiscal 1997 marked the end of the second year of Energen's growth plan which calls for significant capital investment in Taurus's oil and gas activities. During fiscal years 1996 and 1997, Taurus invested $357 million under the plan, adding an estimated 638 Bcfe of proved reserves: $280 million was spent to acquire producing properties, $32 million was invested in associated development, and $45 million was used for exploration and related development. Also under the plan, Taurus invested $16 million to obtain a 9 percent working interest in an exploration joint venture in east Texas. Over the next three fiscal years, Taurus anticipates spending $300 to $450 million for property acquisitions, $50 million in associated development and $150 million for exploration and related development. PROPERTY ACQUISITIONS AND DEVELOPMENT: Taurus's acquisition efforts focus on the purchase of producing properties which have varying degrees of potential for increased reserves and production. During fiscal years 1996 and 1997, Taurus acquired an estimated 620 Bcfe of proved reserves for $280 million, resulting in an average acquisition cost of 45 cents per Mcfe. In addition, Taurus spent $32 million over the last two years in development costs and plans to spend approximately $12.5 million over the next several years to substantially develop these predominantly proved developed producing (PDP) reserves. Taurus has replaced through acquisitions approximately 12 times its two-year production of 53 Bcfe. In fiscal 1997, Taurus invested $172 million to acquire an estimated 452 Bcfe of proved reserves at an average acquisition cost of 38 cents per Mcfe, and Taurus's two largest property acquisitions to date occurred in fiscal 1997. Effective January 1, 1997, Taurus purchased an estimated 319 Bcfe of high BTU content natural gas reserves in the San Juan Basin of New Mexico from Burlington Resources Inc. for $77 million. Taurus operates more than 1,000 of the approximately 1,900 producing wells. Since assuming operations in August 1997, Taurus has 6 8 enhanced the performance of its San Juan Basin properties. After bringing on-line some shut-in wells and performing some modifications to surface facilities, daily net production increased from 26 MMcf to approximately 33 MMcf at the end of the fiscal year. During fiscal 1997, Taurus's nine months of production totaled 10.5 Bcfe, and production is expected to exceed 14.5 Bcfe in fiscal 1998. Taurus plans to spend approximately $8 million on additional operational improvements and fully develop these long-lived, predominantly PDP reserves. Taurus also plans to capitalize on exploitation opportunities presented by these properties and could invest an additional $15 million over the next three years to develop the additional reserve potential; depending on Taurus's drilling success, the company could invest another $15 million in years four and five. In its second largest acquisition, Taurus closed August 1, 1997, on the $72 million purchase of 107 Bcf of coalbed methane reserves in the Black Warrior Basin of Alabama from Amoco Corporation. Net annual production from the more than 260 producing wells, all operated by Taurus, is expected to exceed 7.5 Bcf during fiscal 1998. Through the year 2002, all production qualifies for the nonconventional fuels tax credit, which presently is valued at approximately $1.05 per Mcf and increases annually with inflation. Combined with Taurus's other credit-qualifying coalbed methane production, the Company expects to produce more than $14.5 million in tax credits in 1998. EXPLORATION AND DEVELOPMENT: Exploration is an integral part of Energen's growth strategy. In the first two year's of Energen's growth plan, Taurus has invested $45 million in exploration and related development, adding 18 Bcfe of proved reserves. Taurus also invested $16 million to acquire a 9 percent interest in a joint venture in the east Texas salt basin. During fiscal 1997, Taurus achieved its target 50 percent success rate with seven successful exploration wells out of 14 drilled. Proved reserve additions totaled 12 Bcfe. In light of Taurus's large, predominantly PDP acquisitions in the Black Warrior and San Juan basins, the Company decided during 1997 to increase its exploration involvement in order to achieve the proper mix of activities and returns needed to realize target growth objectives. Taurus increased its working interest position with United Meridian Corporation (UMC), its primary offshore Gulf of Mexico partner, from 12.5 percent to 20 percent and expanded its activities onshore. In June 1997, Taurus invested $16 million to acquire a 9 percent interest from Sonat Exploration Company in its joint venture with UMC and MB Exploration in the northern end of the Cotton Valley Pinnacle Reef play in the east Texas salt basin. The joint venture's first well failed to encounter a pinnacle reef. Taurus expects to participate in approximately three to six joint venture wells during fiscal 1998. Taurus also is the operating partner in a relatively small exploratory play in southwest Mississippi with DDD Energy Inc. of Houston and Griffin and Griffin Oil Company Inc. of Jackson, Miss. Taurus has a 50 percent working interest to casing point. Taurus achieved good results from the first well it drilled for the joint venture. Targeting the Tuscaloosa trend, this well tested at 2,000 Mcfd. In 1998 Taurus plans to participate in up to 15 wells targeting the Tuscaloosa and Frio trends and currently is securing the necessary leases. RISK MANAGEMENT: In implementing Energen's growth strategy, Taurus seeks to mitigate the risks inherent in the oil and gas business. In addition to its increasing use of in-house acquisition and exploration capabilities, Taurus continues to partner with proven industry operators having similar risk tolerances and earnings objectives. Taurus also spreads its exploratory risk, typically taking no more than a 25% interest in any one exploration prospect. Additionally, Taurus utilizes futures contracts traded on the New York Mercantile Exchange and over-the-counter swaps and basis hedges with major energy derivative product specialists as well as fixed-price contracts to mitigate commodity price risk. Taurus typically will hedge production for 18 to 36 months immediately after an acquisition; on an on-going basis, Taurus is prepared to hedge up to 80 percent of flowing production in any given fiscal year depending on the outlook for prices. For fiscal 1998, Taurus has entered into contracts and swaps for 36.3 Bcf of its 1998 flowing gas production at an average contract price (before basis differences) of $2.26 per Mcf and 453 MBbl of its oil production at an average contract price of $20.29 per barrel. ENVIRONMENTAL MATTERS: Taurus is subject to various environmental regulations. Management believes that Taurus is in compliance with currently applicable standards of the environmental agencies to which it is subject 7 9 and that potential environmental liabilities, if any, are minimal. Also, to the extent that Taurus has operating agreements with various joint venture partners, environmental costs, if any, would be shared proportionately. OTHER: For a discussion of risks inherent in the Company's businesses, see Management's Discussion and Analysis in the 1997 Annual Report to Shareholders (pages 27 and 28) which is attached herein as Part IV, Item 14, Exhibit 13. EMPLOYEES The Company has 1,469 employees; Alagasco employs 1,304; Taurus employs 153; and Energen's other subsidiaries employ 12. ITEM 2. PROPERTIES The corporate headquarters of Energen, Alagasco and Taurus are located in leased office space in Birmingham, Alabama. The properties of Alagasco consist primarily of its gas distribution system, which includes more than 8,950 miles of main, more than 9,800 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also has two liquefied natural gas facilities, eight division offices, nine payment centers, six district offices, nine service centers, and other related property and equipment, some of which are leased by Alagasco. For further description of Alagasco's properties, see discussion under Item I--Business. For a description of Taurus's oil and gas properties, see the discussion under Item 1--Business. Information concerning Taurus's production, reserves and development is included in Note 13, Oil and Gas Producing Activities (unaudited) to the Consolidated Financial Statements which is incorporated by reference from the 1997 Annual Report to Stockholders and included in Part IV, Item 14, Exhibit 13, herein. The proved reserve estimates are consistent with comparable reserve estimates filed by Taurus with any federal authority or agency. ITEM 3. LEGAL PROCEEDINGS Energen and its affiliate are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specific relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards bearing little or no relation to culpability or actual damages continue to rise making it increasingly difficult to predict litigation results. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of 1997. 8 10 EXECUTIVE OFFICERS OF THE REGISTRANTS ENERGEN CORPORATION
Name Age Position (1) Rex J. Lysinger 60 Chairman of the Board (2) Wm. Michael Warren, Jr. 50 President and Chief Executive Officer (3) Geoffrey C. Ketcham 46 Executive Vice President, Chief Financial Officer and Treasurer (4) Gary C. Youngblood 54 President and Chief Operating Officer of Alagasco (5) James T. McManus 39 President and Chief Operating Officer of Taurus (6) Dudley C. Reynolds 44 General Counsel and Secretary (7) Paula H. Rushing 44 Vice President--Finance of Alagasco (8) John A. Wallace 53 Senior Vice President--Methane of Taurus (9) J. David Woodruff, Jr. 41 Vice President--Legal and Assistant Secretary and Vice President--Corporate Development (10)
NOTES: (1) All executive officers of Energen have been employed by Energen or a subsidiary for the past five years. Officers serve at the pleasure of its Board of Directors. (2) Served as Vice President of Alagasco from July 1975 to January 1977, when he was elected President. Elected President of Energen upon its formation in 1978. Elected Chairman of the Board of Energen and its subsidiaries September 1982. Currently Chairman of the Board of Energen and all subsidiaries, has announced retirement effective January 1, 1998. Serves as a Director of Energen and each of its subsidiaries. (3) Served as Senior Vice President and General Counsel of Alagasco from September 1983 to October 1984, when he was elected President and Chief Operating Officer of that corporation. Elected Executive Vice President of Energen June 1987 and elected President and Chief Operating Officer of Energen April 1991. Elected President and Chief Operating Officer of all Energen subsidiaries January 1992. Elected Chief Executive Officer of Alagasco and Taurus effective October 1995. Elected Chief Executive Officer of Energen February 1997. Elected Chairman of the Board of Energen effective January 1, 1998. Serves as a Director of Energen and each of its subsidiaries. (4) Elected Controller of Alagasco November 1981, Vice President and Controller June 1984, Vice President--Finance and Planning of Alagasco June 1985 and Vice President--Planning of Energen August 1986. Elected Vice President--Finance, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries June 1987. Elected Senior Vice President--Finance, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries April 1989. Elected Executive Vice President, Chief Financial Officer and Treasurer of Energen and each of its subsidiaries April 1991. 9 11 (5) Served as District Manager--Birmingham District until June 1985, when he was elected Vice President--Birmingham Operations; Elected Senior Vice President--Administration of Alagasco April 1991. Elected Executive Vice President of Alagasco October 1993. Elected Chief Operating Officer of Alagasco effective October 1995. Elected President of Alagasco April 1997. (6) Served as Director of Corporate Accounting of Energen until November 1988, when he was elected Controller of Energen; Elected Controller of Alagasco May 1989. Elected Assistant Vice President--Corporate Development of Energen June 1990. Elected Vice President--Finance and Corporate Development of Energen and Vice President--Finance and Planning of Alagasco effective April 1991. Elected Executive Vice President and Chief Operating Officer of Taurus effective October 1995. Elected President of Taurus April 1997. (7) Served as Staff Attorney for Energen and its subsidiaries to November 1984, when he was named Senior Attorney. Elected Assistant Secretary in 1985 and Secretary effective September 1986. Elected Vice President--Legal and Secretary of Energen and each of its subsidiaries June 1987. Elected General Counsel and Secretary of Energen and each of its subsidiaries April 1991. (8) Served as Director--General Accounting of Alagasco until October 1995, when she was elected Controller of Alagasco. Elected Vice President--Finance of Alagasco November 1997. (9) Served as Manager, Methane Development of Taurus until August 1988, when he was elected Vice President Methane Operations of Taurus. Elected Vice President Methane Exploration and Production of Taurus November 1990. Elected Senior Vice President--Methane of Taurus February 1992. (10) Served as Staff Attorney for Alagasco from March 1986 to June 1987 when he was named Senior Attorney. Elected Assistant Vice President--Legal and Assistant Secretary of Energen and each of its subsidiaries November 1988. Elected Vice President--Legal and Assistant Secretary of Energen and each of its subsidiaries April 1991. Elected Vice President--Legal, and Assistant Secretary of Energen and each of its subsidiaries and Vice President--Corporate Development of Energen October 1995. 10 12 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The information regarding Energen's common stock and the frequency and amount of dividends paid during the past two years with respect to such stock is incorporated by reference from the 1997 Annual Report to Stockholders, page 28, and is included in Part IV, Item 14, Exhibit 13, herein. At December 11, 1997, there were approximately 8,790 holders of record of Energen's common stock. For restrictions on Energen's present and future ability to pay dividends, see Note 3 to the Consolidated Financial Statements which is incorporated by reference from the 1997 Annual Report to Stockholders and included in Part IV, Item 14, Exhibit 13, herein. At the date of this filing, Energen Corporation owns all the issued and outstanding common stock of Alabama Gas Corporation. ITEM 6. SELECTED FINANCIAL AND COMMON STOCK DATA The information regarding selected financial data is incorporated by reference from the 1997 Annual Report to Stockholders, pages 52-53, and is included in Part IV, Item 14, Exhibit 13, herein. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This information is incorporated by reference from the 1997 Annual Report to Stockholders, pages 21-28, and is included in Part IV, Item 14, Exhibit 13, herein. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by this item for Energen Corporation and subsidiaries is incorporated by reference from the 1997 Annual Report to Stockholders and is included in Part IV, Item 14, Exhibit 13, herein. The information required by this item for Alabama Gas Corporation is contained in Part IV, Item 14, herein. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 11 13 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding the executive officers of Energen is included in Part I. The other information required by Item 10 is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Stockholders to be held January 28, 1998. The proxy statement will be filed on or about December 22, 1997. ITEM 11. EXECUTIVE COMPENSATION The information regarding executive compensation is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Stockholders to be held January 28, 1998. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS The information regarding the security ownership of the beneficial owners of more than five percent of Energen's common stock is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Stockholders to be held January 28, 1998. B. SECURITY OWNERSHIP OF MANAGEMENT The information regarding the security ownership of management is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Stockholders to be held January 28, 1998. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information regarding certain relationships and related transactions is incorporated herein by reference from Energen's definitive proxy statement for the Annual Meeting of Stockholders to be held January 28, 1998. 12 14 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K A. DOCUMENTS FILED AS PART OF THIS REPORT (1) FINANCIAL STATEMENTS The financial statements listed in the accompanying Index to Financial Statements and Financial Statement Schedules are filed as part of this report and are included in Part IV, Item 14, Exhibit 13, herein. (2) FINANCIAL STATEMENT SCHEDULES The financial statement schedules listed in the accompanying Index to Financial Statements and Financial Statement Schedules are filed as part of this report. (3) EXHIBITS The exhibits listed on the accompanying Index to Exhibits are filed as part of this report. B. REPORTS ON FORM 8-K (1) Form 8-K dated July 9, 1997, reporting a property acquisition by Taurus Exploration, Inc., the Company's oil and gas exploration and production subsidiary (2) Form 8-K(A) dated August 11, 1997, reporting the commencement of a solicitation of consents to certain proposed amendments (i) to the Indenture dated as of January 1, 1992 among Energen and Boatmen's Trust Company, as trustee (The Trustee), pursuant to which Energen's 8% Debentures due February 1, 2007 were issued and (ii) to the Indenture dated as of March 1, 1993 among Energen and the Trustee, pursuant to which Energen's Series 1993 Notes were issued. 13 15 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized. ENERGEN CORPORATION (Registrant) ALABAMA GAS CORPORATION (Registrant) December 17, 1997 /s/Rex J. Lysinger - --------------------------- ---------------------------------- DATE Rex J. Lysinger Chairman of the Board of Directors 14 16 SIGNATURES Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrants and in the capacities and on the dates indicated: December 17, 1997 /s/Rex J. Lysinger - ------------------------- ---------------------------------------- DATE Rex J. Lysinger Chairman of the Board of Directors December 17, 1997 /s/Wm. Michael Warren, Jr. - ------------------------- ---------------------------------------- DATE Wm. Michael Warren, Jr. President of Energen and Chief Executive Officer and Director of Energen and Alagasco December 17, 1997 /s/Geoffrey C. Ketcham - ------------------------- ---------------------------------------- DATE Geoffrey C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer December 17, 1997 /s/Paula H. Rushing - ------------------------- ---------------------------------------- DATE Paula H. Rushing Vice President--Finance of Alagasco December 17, 1997 /s/J. Mason Davis, Jr. - ------------------------- ---------------------------------------- DATE J. Mason Davis, Jr. Director December 17, 1997 /s/James S. M. French - ------------------------- ---------------------------------------- DATE James S. M. French Director December 17, 1997 /s/Judy M. Merritt - ------------------------- ---------------------------------------- DATE Judy M. Merritt Director December 17, 1997 /s/Drayton Nabers, Jr. - ------------------------- ---------------------------------------- DATE Drayton Nabers, Jr. Director 15 17 ENERGEN CORPORATION ALABAMA GAS CORPORATION INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES ITEM 14(A)
Reference Page -------------- 1997 1997 Annual 10-K Report ---- ------ 1. Financial Statements ENERGEN CORPORATION Report of Independent Certified Public Accountants...................... 50 Consolidated statements of income for the years ended September 30, 1997, 1996 and 1995....................................... 29 Consolidated balance sheets as of September 30, 1997 and 1996........................................................... 30 Consolidated statements of shareholders' equity for the years ended September 30, 1997, 1996 and 1995................................. 32 Consolidated statements of cash flows for the years ended September 30, 1997, 1996 and 1995....................................... 33 Notes to consolidated financial statements.............................. 34 ALABAMA GAS CORPORATION Report of Independent Certified Public Accountants...................... 21 Statements of income for the years ended September 30, 1997, 1996 and 1995....................................... 22 Balance sheets as of September 30, 1997 and 1996........................ 23 Statements of shareholder's equity for the years ended September 30, 1997, 1996 and 1995....................................... 25 Statements of cash flows for the years ended September 30, 1997, 1996 and 1995....................................... 26 Notes to financial statements........................................... 27
16 18
Reference Page -------------- 1997 1997 Annual 10-K Report ---- ------ 2. Financial Statement Schedules ENERGEN CORPORATION Report of Independent Certified Public Accountants...................... 35 Schedule II Valuation and Qualifying Accountants.................... 36 ALABAMA GAS CORPORATION Schedule II Valuation and Qualifying Accounts....................... 37
Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the financial statements or notes thereto. 17 19 ENERGEN CORPORATION ALABAMA GAS CORPORATION INDEX TO EXHIBITS ITEM 14(A)(3)
Exhibit Number Description - ------ ----------- *3(a) Restated Certificate of Incorporation of Energen Corporation (formerly Alagasco, Inc.) which was filed as Exhibit 4(a) to Energen's Registration Statement on Form S-8 (Registration No. 33-14855). *3(b) Amendment to the Restated Certificate of Incorporation of Energen Corporation (formerly Alagasco, Inc.) adopted on July 18, 1985, which was filed as Exhibit 4(b) to Energen's Registration Statement on Form S-8 (Registration No. 33-14855). *3(c) Amendment to the Restated Certificate of Incorporation of Energen Corporation adopted on January 15, 1987, which was filed as Exhibit 4(c) to Energen's Registration Statement on Form S-8 (Registration No. 33-14855). *3(d) Amendment to the Restated Certificate of Incorporation of Energen Corporation adopted on January 25, 1989, which was filed as Exhibit 4(d) to Energen's Registration Statement on Form S-3 (Registration No. 33-70464). *3(e) Articles of Amendment to the Restated Certificate of Incorporation of Energen Corporation dated February 3, 1995, which was filed as Exhibit 3(e) to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1995, (file No. 1-7810). *3(f) Restated Conformed Certificate of Incorporation of Energen Corporation, as amended through February 3, 1995, which was filed as Exhibit 3(f) to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1995, (file No. 1-7810). *3(g) Certificate of Adoption of Resolutions designating Series A Junior Participating Preferred Stock (June 27, 1988) which was filed as Exhibit 4(e) to Energen's Registration Statement on Form S-2 (Registration No. 33-25435). *3(h) Bylaws of Energen Corporation, which were filed as Exhibit 4(e) to Energen's Registration Statement on Form S-8 (Registration No. 33-14855). *3(i) Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1995, (file No. 1-7810). *3(j) By-Laws of Alabama Gas Corporation, which was filed as Exhibit 4(k) to Alabama Gas' Registration Statement on Form S-3 (Registration No. 33-12841). *4(a) Rights Agreement, dated as of July 27, 1988, between Energen Corporation and AmSouth Bank, N.A., Rights Agent, which was filed as Exhibit 1 to Energen's Registration Statement on Form 8-A (File No. 1-7810). *4(b) Amendment of Rights Agreement, dated as of February 28, 1990, between Energen Corporation and AmSouth Bank, N.A., Rights Agent, which was filed as Exhibit 2 to Energen's Form 8 Amendment No. 2 to its Registration Statement on Form 8-A (File No. 1-7810).
18 20 *4(c) Indenture, dated as of January 1, 1992, between Energen Corporation and Boatmen's Trust Company, Trustee, which was filed as Exhibit 4 to Energen's Amendment No. 1 to Registration Statement on Form S-3 (Registration No. 33-44936). *4(d) Indenture, dated as of March 1, 1993, between Energen Corporation and Boatmen's Trust Company, Trustee, which was filed as Exhibit 4 to Energen's Registration Statement on Form S-3 (Registration No. 33-25435). *4(e) Form of Indenture between Energen Corporation and The Bank of New York, as Trustee, which was dated as of September 1, 1996, and which was filed as Exhibit 4(i) to the Registrant's Registration Statement on Form S-3 (Registration No. 333-11239). *4(f) Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia, National Association, Trustee, which was filed as Exhibit 4(k) to Alabama Gas's Registration Statement on Form S-3 (Registration No. 3370466). *10(a) Form of Service Agreement Under Rate Schedule CSS (No. S10710), between Southern Natural Gas Company and Alabama Gas Corporation as filed as Exhibit 10(a) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810). *10(b) Form of Service Agreement Under Rate Schedule FT-NN (No. 866941), between Southern Natural Gas Company and Alabama Gas Corporation as filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810). *10(c) Form of Executive Retirement Supplement Agreement between Energen Corporation and certain executive officers as filed as Exhibit 10(e) to Energen's Annual Report on Form 10-K for the year ended September 30, 1996 (File No. 1-7810). *10(d) Form of Severance Compensation Agreement between Energen Corporation and certain executive officers as filed as Exhibit 10(g) to Energen's Annual Report on Form 10-K for the year ended September 30, 1996 (File No. 1-7810). *10(e) Energen Corporation 1988 Stock Option Plan as filed as Exhibit 10(i) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File 1-7810). 10(f) Energen Corporation 1992 Long-Range Performance Share Plan, as amended April 25, 1997. *10(g) Energen Corporation 1997 Stock Incentive Plan, which was filed as Appendix A to Energen's Proxy Statement for its January 28, 1998, Annual Meeting (File No. 1-7810). *10(h) Energen Corporation 1997 Deferred Compensation Plan, which was filed as Appendix B to Energen's Proxy Statement for its January 28, 1998, Annual Meeting (File No. 1-7810). *10(i) Energen Corporation 1992 Directors Stock Plan, effective as of January 22, 1992, which was filed as Exhibit B to Energen's Proxy Statement for its January 22, 1992, Annual Meeting (File No. 1-7810). *10(j) Amendment to Energen Corporation 1992 Directors Stock Plan, which was filed as Appendix B to Energen's Proxy Statement for its January 24, 1996, Annual Meeting (File No. 1-7810). *10(k) Energen Corporation Director Fees Deferral Plan as filed as Exhibit 10(l) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993 (File No. 1-7810).
19 21 *10(l) Energen Corporation Annual Incentive Compensation Plan, Revised 5/90, as amended effective October 1, 1993, as filed as Exhibit 10(m) to Energen's Annual Report on Form 10-K for the year ended September 30, 1994 (File No. 1-7810). 13 Information incorporated by reference from pages 21-55 of the Energen Corporation 1997 Annual Report to Stockholders 21 Subsidiaries of Energen Corporation 23 Consent of Independent Certified Public Accountants (Energen Corporation) 27.1 Financial Data Schedule of Energen Corporation (for SEC purposes only) 27.2 Financial Data Schedule of Alabama Gas Corporation (for SEC purposes only)
*Incorporated by reference 20 22 REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS TO THE BOARD OF DIRECTORS OF ALABAMA GAS CORPORATION: We have audited the financial statements and the financial statement schedule of Alabama Gas Corporation listed in the index on pages 16 and 17 of this Form 10-K. These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Alabama Gas Corporation as of September 30, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 1997, in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. Coopers & Lybrand L.L.P. Birmingham, Alabama October 23, 1997 21 23 STATEMENTS OF INCOME ALABAMA GAS CORPORATION
=============================================================================== YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1997 1996 1995 =============================================================================== OPERATING REVENUES $362,984 $357,252 $295,967 - ------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas 177,837 181,400 133,556 Operations 85,119 81,585 78,139 Maintenance 11,092 10,956 9,727 Depreciation 23,486 21,269 19,370 Income taxes Current 11,223 8,699 8,392 Deferred, net (618) 835 177 Deferred investment tax credits, net (487) (487) (487) Taxes, other than income taxes 26,658 26,772 22,662 - ------------------------------------------------------------------------------- Total operating expenses 334,310 331,029 271,536 - ------------------------------------------------------------------------------- OPERATING INCOME 28,674 26,223 24,431 - ------------------------------------------------------------------------------- OTHER INCOME Allowance for funds used during construction 490 972 1,054 Other, net 215 (649) (112) - ------------------------------------------------------------------------------- Total other income 705 323 942 - ------------------------------------------------------------------------------- INTEREST CHARGES Interest on long-term debt 8,843 7,390 7,730 Other interest expense 1,966 2,195 1,922 - ------------------------------------------------------------------------------- Total interest charges 10,809 9,585 9,652 - ------------------------------------------------------------------------------- NET INCOME AVAILABLE FOR COMMON $ 18,570 $ 16,961 $ 15,721 - -------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these statements. 22 24 BALANCE SHEETS ALABAMA GAS CORPORATION
================================================================================ AS OF SEPTEMBER 30, (IN THOUSANDS) 1997 1996 ================================================================================ ASSETS PROPERTY, PLANT AND EQUIPMENT Utility plant $ 583,630 $ 544,643 Less accumulated depreciation 287,749 268,110 - -------------------------------------------------------------------------------- Utility plant, net 295,881 276,533 - -------------------------------------------------------------------------------- Other property, net 347 394 - -------------------------------------------------------------------------------- CURRENT ASSETS Cash 2,580 803 Accounts receivable Gas 36,098 26,999 Merchandise 2,001 1,730 Other 1,442 2,955 Affiliated companies -- 10,582 Allowance for doubtful accounts (3,156) (2,985) Inventories, at average cost Storage gas inventory 25,367 28,214 Materials and supplies 5,391 5,828 Liquefied natural gas in storage 3,630 2,417 Deferred gas costs 2,512 1,975 Deferred income taxes 5,675 6,344 Prepayments and other 6,696 4,561 - -------------------------------------------------------------------------------- Total current assets 88,236 89,423 - -------------------------------------------------------------------------------- DEFERRED CHARGES AND OTHER ASSETS 5,917 7,467 - -------------------------------------------------------------------------------- TOTAL ASSETS $ 390,381 $ 373,817 ================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 23 25 BALANCE SHEETS ALABAMA GAS CORPORATION
====================================================================================== AS OF SEPTEMBER 30, (IN THOUSANDS) 1997 1996 ====================================================================================== CAPITAL AND LIABILITIES CAPITALIZATION Common shareholder's equity Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares outstanding in 1997 and 1996 $ 20 $ 20 Premium on capital stock 31,682 31,682 Capital surplus 2,802 2,802 Retained earnings 106,894 95,044 - -------------------------------------------------------------------------------------- Total common shareholder's equity 141,398 129,548 Long-term debt 125,000 125,000 - -------------------------------------------------------------------------------------- Total capitalization 266,398 254,548 - -------------------------------------------------------------------------------------- CURRENT LIABILITIES Notes payable to banks 11,000 -- Accounts payable Trade 28,923 23,758 Affiliated companies 4,984 1,512 Accrued taxes 16,745 18,067 Customers' deposits 16,399 17,364 Supplier refunds due customers -- 16,668 Other amounts due customers 7,347 489 Accrued wages and benefits 3,879 4,459 Other 10,481 10,611 - -------------------------------------------------------------------------------------- Total current liabilities 99,758 92,928 - -------------------------------------------------------------------------------------- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 16,739 16,883 Accumulated deferred investment tax credits 3,130 3,617 Regulatory liability 3,651 5,038 Customer advances for construction and other 705 803 - -------------------------------------------------------------------------------------- Total deferred credits and other liabilities 24,225 26,341 - -------------------------------------------------------------------------------------- TOTAL CAPITAL AND LIABILITIES $ 390,381 $ 373,817 ======================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 24 26 STATEMENTS OF SHAREHOLDER'S EQUITY ALABAMA GAS CORPORATION
=================================================================================================================== (IN THOUSANDS, EXCEPT SHARE AMOUNTS) =================================================================================================================== COMMON STOCK ------------ NUMBER OF PAR PREMIUM ON CAPITAL RETAINED SHARES VALUE CAPITAL STOCK SURPLUS EARNINGS - ------------------------------------------------------------------------------------------------------------------- BALANCE AT SEPTEMBER 30, 1994 1,972,052 $ 20 $ 31,682 $ 2,802 $ 81,087 Net income 15,721 Cash dividends (9,170) - ------------------------------------------------------------------------------------------------------------------- BALANCE AT SEPTEMBER 30, 1995 1,972,052 20 31,682 2,802 87,638 Net income 16,961 Cash dividends (9,555) - ------------------------------------------------------------------------------------------------------------------- BALANCE AT SEPTEMBER 30, 1996 1,972,052 20 31,682 2,802 95,044 Net income 18,570 Cash dividends (6,720) - ------------------------------------------------------------------------------------------------------------------- BALANCE AT SEPTEMBER 30, 1997 1,972,052 $ 20 $ 31,682 $ 2,802 $ 106,894 ===================================================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 25 27 STATEMENTS OF CASH FLOWS ALABAMA GAS CORPORATION
=================================================================================================================== YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1997 1996 1995 =================================================================================================================== OPERATING ACTIVITIES Net Income $ 18,570 $ 16,961 $ 15,721 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 23,486 21,269 19,370 Deferred income taxes, net (618) 835 177 Deferred investment tax credits (487) (487) (487) Net change in: Accounts receivable (7,686) (5,539) (113) Inventories 2,071 (6,784) 3,725 Deferred gas costs (537) (549) 34 Accounts payable-- gas purchase 5,758 (1,614) 9,882 Accounts payable-- other trade (593) (788) (2,856) Other current assets and liabilities (15,012) 12,048 (3,057) Other, net 1,124 (1,019) 673 - ------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 26,076 34,333 43,069 - ------------------------------------------------------------------------------------------------------------------- INVESTING ACTIVITIES Additions to property, plant and equipment (43,724) (42,037) (41,560) Net advances (to) from parent company 14,054 (8,871) (199) Other, net 1,091 1,377 (15) - ------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (28,579) (49,531) (41,774) - ------------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES Payment of dividends on common stock (6,720) (9,555) (9,170) Reduction of long-term debt and preferred stock -- -- (37,214) Proceeds from medium-term notes -- 24,829 49,660 Net change in short-term debt 11,000 -- (4,000) - ------------------------------------------------------------------------------------------------------------------- Net cash provided by (used in) financing activities 4,280 15,274 (724) - ------------------------------------------------------------------------------------------------------------------- Net change in cash and cash equivalents 1,777 76 571 Cash and cash equivalents at beginning of period 803 727 156 - ------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 2,580 $ 803 $ 727 ===================================================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 26 28 NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - -------------------------------------------------------------------------------- Alabama Gas Corporation (Alagasco), a wholly-owned subsidiary of Energen Corporation (the Company), is the largest natural gas distribution utility in the State of Alabama, serving customers primarily in central and north Alabama. The following is a description of its significant accounting policies and practices. A. UTILITY PLANT AND DEPRECIATION: Property, plant and equipment is stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and, together with the cost of removal less salvage, is charged to the accumulated reserve for depreciation. Depreciation is provided on the straight-line method over the estimated useful lives of utility property at rates established by the Alabama Public Service Commission (APSC). Approved depreciation rates averaged approximately 4.4 percent in 1997 and 4.3 percent in 1996 and 1995. B. INVENTORIES: Inventories, which consist primarily of gas stored underground, are stated at average cost. C. OPERATING REVENUE AND GAS COSTS: In accordance with industry practice, Alagasco records natural gas distribution revenues on a monthly- and cycle-billing basis. The commodity cost of purchased gas applicable to gas delivered to customers but not yet billed under the cycle-billing method is deferred as a current asset. D. REGULATORY ACCOUNTING: Alagasco is subject to the provisions of Statement of Financial Accounting Standard (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. In general, SFAS No. 71 allows utilities to capitalize or defer certain costs or revenues, based upon orders received from regulatory authorities, to be recovered from or refunded to customers in future periods. E. INCOME TAXES: Alagasco files a consolidated income tax return with its parent. The consolidated income taxes are allocated to the appropriate subsidiaries using the separate return method. Deferred income taxes reflect the impact of temporary differences between the tax basis of assets and liabilities and their carrying amounts for financial reporting purposes and are measured in compliance with enacted tax laws. Investment tax credits have been deferred and are being amortized over the lives of the related assets. F. CASH EQUIVALENTS: Alagasco includes highly liquid marketable securities and debt instruments purchased with a maturity of three months or less in cash equivalents. G. ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. 2. REGULATORY MATTERS - -------------------------------------------------------------------------------- As an Alabama utility, Alagasco is subject to regulation by the APSC which, in 1983, established the Rate Stabilization and Equalization (RSE) rate-setting process. RSE was extended with modifications in 1985, 1987 and 1990. On October 7, 1996, RSE was extended, without change, for a five-year period through January 1, 2002. Under the terms of that extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. Under RSE as extended, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and fiscal year-to-date performance, whether Alagasco's return on equity for the fiscal year will be within the allowed range of 13.15 percent to 13.65 percent. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each fiscal year, effective December 1, and cannot exceed 27 29 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. If the change in O&M expense per customer falls within 1.25 percentage points above or below the Consumer Price Index For All Urban Customers (index range), no adjustment is required. If, however, 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. Under RSE as extended, a $1.3 million annual decrease in revenue became effective October 1, 1996, a $7.7 million annual increase became effective December 1, 1996, and a $1.5 million annual decrease became effective April 1, 1997. Alagasco calculates a temperature adjustment to customers' monthly bills to remove the effect of departures from normal temperature on Alagasco's earnings. The calculation is performed monthly, and the adjustments to customers bills are made in the same billing cycle the weather variation occurs. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply, including Gas Supply Realignment (GSR) surcharges imposed by Alagasco's suppliers resulting from changes in gas supply purchases related to the implementation of Federal Energy Regulatory Commission (FERC) Order 636. The APSC on October 7, 1996, issued an order providing for the refund to customers prior to January 31, 1997 of approximately $17 million of supplier refunds, including interest. The Company refunded these amounts to customers during January 1997. The refunds were collected from a variety of sources and most relate to the settlement of rate case and FERC Order 636 proceedings of Southern Natural Gas Company (Southern) as described herein. On September 9, 1996, the APSC approved Alagasco's application to issue $25 million of debt, a portion of which was used to fund these supplier refunds. In accordance with APSC-directed regulatory accounting procedures, Alagasco in 1989 began returning to customers excess utility deferred taxes which resulted from a reduction in the federal statutory tax rate from 46 percent to 34 percent using the average rate assumption method. This method provides for the return to ratepayers of excess deferred taxes over the lives of the related assets. In 1993 those excess taxes were reduced as a result of a federal tax rate increase from 34 percent to 35 percent. Remaining excess utility deferred taxes of $2.1 million are being returned to ratepayers over approximately 13 years. At September 30, 1997 and 1996, a regulatory liability related to income taxes of $3.7 million and $5 million, respectively, was included in the consolidated financial statements. The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized on a straight-line basis over approximately 23 years. At September 30, 1997 and 1996, the net acquisition adjustment was $16.4 million and $16.7 million, respectively. FERC REGULATION: In 1995 Southern filed a comprehensive settlement with the FERC in the form of a Stipulation and Agreement (the Settlement) to resolve all issues in Southern's six then-pending rate cases as well as to resolve all GSR and transition cost issues resulting from the implementation of FERC Order 636. Alagasco was a supporting party to the Settlement. The Settlement, as approved by the FERC, resolves all issues relating to GSR and other transition costs with respect to supporting parties. Alagasco estimates that it has a remaining GSR liability of approximately $0.1 million to be paid through December 1998 and approximately $0.7 million in other transition costs to be paid through June 1998. Because these costs will be recovered in full from its customers, Alagasco recorded a regulatory asset of $0.8 million and $2.2 million at September 30, 1997 and 1996, respectively. 3. LONG-TERM DEBT AND NOTES PAYABLE - -------------------------------------------------------------------------------- Long-term debt consists of the following: - --------------------------------------------------------------------------------
As of September 30, (in thousands) 1997 1996 - -------------------------------------------------------------------------------- Medium-term Notes, interest ranging from 5.4% to 7.97%, for notes redeemable December 1, 1998, to September 23, 2026 $ 125,000 $ 125,000 Less amounts due within one year -- -- - -------------------------------------------------------------------------------- Total $ 125,000 $ 125,000 - --------------------------------------------------------------------------------
28 30 The aggregate maturities of long-term debt for the next five years are as follows:
- -------------------------------------------------------------------------------- Years ending September 30, (in thousands) - -------------------------------------------------------------------------------- 1998 1999 2000 2001 2002 - -------------------------------------------------------------------------------- $ -- $ 5,350 $ -- $ 4,650 $ 5,000 - --------------------------------------------------------------------------------
Energen and Alagasco have short-term credit lines and other credit facilities of $203 million available to either entity for working capital needs. The following is a summary of information relating to notes payable to banks:
- ------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------- Alagasco outstanding $ 11,000 $ -- $ -- Other Energen outstanding 141,000 59,000 32,300 - ------------------------------------------------------------------------------------- Notes payable to banks 152,000 59,000 32,300 Available for borrowings 51,000 97,000 77,700 - ------------------------------------------------------------------------------------- Total $203,000 $156,000 $110,000 - ------------------------------------------------------------------------------------- Maximum amount outstanding at any month-end $ 41,000 $ 22,000 $ 5,000 Average daily amount outstanding $ 9,962 $ 6,672 $ 447 Weighted average interest rates based on: Average daily amount outstanding 5.83% 5.73% 5.69% Amount outstanding at year-end 5.99% -- -- - -------------------------------------------------------------------------------------
Total interest expense for Alagasco in 1997, 1996 and 1995 was $10,809,000, $9,585,000, and $9,652,000, respectively. 4. INCOME TAXES - -------------------------------------------------------------------------------- The components of income taxes consist of the following: - --------------------------------------------------------------------------------
For the years ended September 30, (in thousands) 1997 1996 1995 - -------------------------------------------------------------------------------- Taxes estimated to be payable currently: Federal $ 10,219 $7,924 $7,633 State 1,004 775 759 - -------------------------------------------------------------------------------- Total current 11,223 8,699 8,392 - -------------------------------------------------------------------------------- Taxes deferred: Federal (1,050) 274 (326) State (55) 74 16 - -------------------------------------------------------------------------------- Total deferred (1,105) 348 (310) - -------------------------------------------------------------------------------- Total income tax expense $ 10,118 $9,047 $8,082 - --------------------------------------------------------------------------------
29 31 Temporary differences and carry forwards which give rise to a significant portion of deferred tax assets and liabilities for 1997 and 1996 are as follows:
- ------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 - ------------------------------------------------------------------------------------------------------------------- Current Noncurrent Current Noncurrent --------------------------- ------------------------------ Deferred tax assets: Deferred investment tax credits $ -- $ 1,024 $ -- $ 1,205 Regulatory liabilities -- 1,356 -- 1,872 Unbilled revenue 1,699 -- 1,658 -- Insurance and accruals 2,854 -- 2,239 -- Inventories 520 -- 310 -- Accrued vacation -- -- 1,067 -- Allowance for uncollectible accounts 1,173 -- 1,268 -- Other, net 1,474 156 1,990 74 - ------------------------------------------------------------------------------------------------------------------- Subtotal 7,720 2,536 8,532 3,151 Valuation allowance -- -- -- -- - ------------------------------------------------------------------------------------------------------------------- Total deferred tax assets 7,720 2,536 8,532 3,151 - ------------------------------------------------------------------------------------------------------------------- Deferred tax liabilities: Depreciation and basis differences -- 18,349 -- 19,087 Gas supply adjustment 1,308 -- 500 -- Other, net 737 926 1,688 947 - ------------------------------------------------------------------------------------------------------------------- Total deferred tax liabilities 2,045 19,275 2,188 20,034 - ------------------------------------------------------------------------------------------------------------------- Net deferred tax assets (liabilities) $ 5,675 $ (16,739) $ 6,344 $ (16,883) - -------------------------------------------------------------------------------------------------------------------
No valuation allowance with respect to deferred taxes is deemed necessary as Alagasco anticipates generating adequate future taxable income to realize the benefits of all deferred tax assets on Alagasco's balance sheet. Total income tax expense differs from the amount which would be provided by applying the statutory federal income tax rate to earnings before taxes as illustrated below:
- ------------------------------------------------------------------------------------------------------------------- For the years ended September 30, (in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------- Income tax expense at statutory federal income tax rate $ 10,042 $ 9,103 $ 8,331 Increase (decrease) resulting from: Investment tax credits-deferred (487) (487) (487) State income taxes, net of federal income tax benefit 617 559 512 Other, net (54) (128) (274) - ------------------------------------------------------------------------------------------------------------------- Total income tax expense $ 10,118 $ 9,047 $ 8,082 - -------------------------------------------------------------------------------------------------------------------
There were no tax-related balances due to affiliates at September 30, 1997 or 1996. 5. EMPLOYEE BENEFIT PLANS - -------------------------------------------------------------------------------- All information presented concerning retirement income and other benefit plans includes other affiliates of Energen Corporation as well as Alagasco. The Company has two defined benefit non-contributory pension plans which cover a majority of the employees. Benefits are based on years of service and final earnings. The Company's policy is to use the projected unit credit actuarial method for funding and financial reporting purposes. The expense for the plan covering the majority of employees (Plan A) for the years ended September 30, 1997, 1996 and 1995 was $1,228,000, $412,000, and $1,158,000, respectively. The expense for the second plan covering employees under certain labor union agreements (Plan B) for 1997, 1996 and 1995 was $437,000, $197,000, and $339,000, respectively. 30 32 The funded status of the plans is as follows:
- ---------------------------------------------------------------------------------------------------------------------------- As of June 30, (in thousands) Plan A Plan B - ---------------------------------------------------------------------------------------------------------------------------- 1997 1996 1997 1996 ----------------------- ---------------------- Vested benefits $(57,617) $(56,828) $(14,610) $(14,210) Nonvested benefits (4,739) (4,323) (2,256) (2,336) - ---------------------------------------------------------------------------------------------------------------------------- Accumulated benefit obligation (62,356) (61,151) (16,866) (16,546) Effects of salary progression (11,402) (12,607) -- -- - ---------------------------------------------------------------------------------------------------------------------------- Projected benefit obligation (73,758) (73,758) (16,866) (16,546) Fair value of plan assets, primarily equity and fixed income securities 84,859 80,750 20,820 18,358 Unrecognized net gain (loss) (6,477) (337) (2,747) (433) Unrecognized prior service cost 29 35 998 1,205 Unrecognized net transition obligation (asset) (3,494) (4,303) 282 340 - ---------------------------------------------------------------------------------------------------------------------------- Accrued pension asset $ 1,159 $ 2,387 $ 2,487 $ 2,924 - ----------------------------------------------------------------------------------------------------------------------------
At September 30, 1996, for both plans the discount rate used to measure the projected benefit obligation was 7.75 percent, and the expected long-term rate of return on plan assets was 8.25 percent. The annual rate of salary increase for the salaried plan was 5.75 percent in both years. The components of net pension expense for 1997, 1996 and 1995 were:
- -------------------------------------------------------------------------------------------------------------------------- For the years ended September 30, (in thousands) Plan A Plan B - -------------------------------------------------------------------------------------------------------------------------- 1997 1996 1995 1997 1996 1995 ---------------------------------- ---------------------------------- Service Cost $ 2,227 $ 2,147 $ 2,052 $ 243 $ 255 $ 224 Interest cost on projected benefit obligation 5,524 4,617 4,728 1,238 1,166 1,095 Actual (return) on plan assets (12,629) (15,280) (8,787) (3,803) (2,971) (2,172) Net amortization and deferral 6,106 8,928 2,106 2,759 1,747 1,192 Loss due to special termination benefits -- -- 1,489 -- -- -- Settlement gain -- -- (430) -- -- -- - -------------------------------------------------------------------------------------------------------------------------- Net pension expense $ 1,228 $ 412 $ 1,158 $ 437 $ 197 $ 339 - --------------------------------------------------------------------------------------------------------------------------
In 1995 the Company recognized a loss for special termination benefits of $1,489,000 and a settlement gain of $430,000 pursuant to a voluntary early retirement option offered to all salaried, non-officer employees of at least 58 years of age with a minimum of 5 years service. Of the 55 eligible employees, 41 accepted. The Company has deferred compensation plan agreements with certain key executives providing for payments on retirement, termination, death or disability. Expense under these agreements for 1997, 1996 and 1995 was $399,000, $1,002,000, and $808,000, respectively. At June 30, 1997 and 1996, the accumulated post-retirement benefit obligation related to these agreements was $5,961,000 and $6,206,000, respectively, and the projected benefit obligation was $9,839,000 and $9,442,000, respectively. A prepaid post-retirement benefit asset of $499,000 was recorded at June 30, 1997, and an accrued post-retirement benefit liability of $464,000 was recorded at June 30, 1996. In addition to providing pension benefits, the Company provides certain post-retirement health care and life insurance benefits. Substantially all of the Company's employees may become eligible for such benefits if they reach normal retirement age while working for the Company. While the Company has not adopted a formal funding policy, all of its accrued post-retirement liability was funded at year-end. The expense for salaried employees for the years ended September 30, 1997, 1996, and 1995 was $2,221,000, $1,984,000, and $2,271,000, respectively. The expense for union employees was $4,204,000, $4,076,000, and $3,613,000 during 1997, 1996 and 1995, respectively. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability. 31 33 A reconciliation of the estimated status of the obligation is as follows:
- ----------------------------------------------------------------------------------------------------------------------------------- As of June 30, (in thousands) Salaried Employees Union Employees - ----------------------------------------------------------------------------------------------------------------------------------- 1997 1996 1997 1996 --------------------- ---------------------- Retirees $ (9,590) $(10,344) $(14,529) $(14,982) Active, fully-eligible (2,121) (1,574) (4,340) (4,011) Other active (8,309) (7,989) (14,151) (14,415) - ----------------------------------------------------------------------------------------------------------------------------------- Accumulated post-retirement benefit obligation (20,020) (19,907) (33,020) (33,408) Fair value of plan assets, primarily equity and fixed income securities 23,719 17,519 13,363 8,399 Unamortized amounts (4,686) 1,210 17,405 23,394 - ----------------------------------------------------------------------------------------------------------------------------------- Accrued post-retirement benefit liability $ (987) $ (1,178) $ (2,252) $ (1,615) - -----------------------------------------------------------------------------------------------------------------------------------
Net periodic post-retirement benefit cost for the years ended September 30, 1997, 1996, and 1995 included the following:
- ----------------------------------------------------------------------------------------------------------------------------------- For the years ended September 30, (in thousands) Salaried Employees Union Employees - ----------------------------------------------------------------------------------------------------------------------------------- 1997 1996 1995 1997 1996 1995 ----------------------------- ------------------------------ Service cost $ 979 $ 516 $ 512 $ 1,198 $ 876 $ 807 Interest cost on accumulated post-retirement benefit obligation 2,204 1,679 1,696 2,542 2,195 1,793 Amortization of transition obligation 723 723 723 1,285 1,285 1,285 Amortization of actuarial gains and losses (568) (277) -- -- -- -- Deferred asset (gain) loss 3,682 658 539 2,006 177 424 Actual (return) on plan assets (4,799) (1,315) (1,199) (2,827) (457) (696) - ----------------------------------------------------------------------------------------------------------------------------------- Net periodic post-retirement benefit expense $ 2,221 $ 1,984 $ 2,271 $ 4,204 $ 4,076 $ 3,613 - -----------------------------------------------------------------------------------------------------------------------------------
The weighted average discount rate used in determining the accumulated post-retirement benefit obligation was 7.75 percent in 1997 and 1996. The expected long-term rate of return on assets is 8.25 percent for both years, and the tax rate on investment income is assumed to be 40 percent. The weighted average health care cost trend rate used in determining the accumulated post-retirement benefit obligation was 8.25 percent and 8 percent in 1997 and 1996, respectively. That assumption has a significant effect on the amounts reported. For example, with respect to salaried employees, increasing the weighted average health care cost trend rate by 1 percent would increase the accumulated post-retirement benefit obligation by 2.4 percent and the net periodic post-retirement benefit cost by 2.2 percent. For union employees, increasing the weighted average health care cost trend rate by 1 percent would increase the accumulated post-retirement benefit obligation by 7.5 percent and the net periodic post-retirement benefit cost by 7.2 percent. For pay-related life insurance benefits, the salary scale averages 5.75 percent and 5 percent in 1997 and 1996, respectively. For both defined benefit plans and other post-retirement plans, certain financial assumptions are used in determining the Company's projected benefit obligation. These assumptions are examined periodically by the Company and any required changes are reflected in the subsequent determination of projected benefit obligations. The Company has a long-term disability plan covering most salaried employees. Expense for the years ended September 30, 1997, 1996, and 1995 was $163,000, $370,000, and $155,000, respectively. 6. CAPITAL STOCK - -------------------------------------------------------------------------------- Alagasco's authorized common stock consists of 3 million, $0.01 par value common shares. At September 30, 1997 and 1996, 1,972,052 shares were issued and outstanding. Alagasco is authorized to issue 120,000 shares of preferred stock par value $0.01 per share, in one or more series. There are no shares currently outstanding. 32 34 7. COMMITMENTS AND CONTINGENCIES - -------------------------------------------------------------------------------- CONTRACTS AND AGREEMENTS: Alagasco has various firm gas supply and firm gas transportation contracts which expire at various dates through the year 2008. These contracts typically contain minimum demand charge obligations on the part of Alagasco. ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former manufactured gas plant sites, of which it still owns four, and five manufactured gas distribution sites, of which it still owns one. A preliminary investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the results of operations or financial condition of Alagasco. LEGAL MATTERS: Alagasco is from time to time party to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the financial position of Alagasco. It should be noted, however, that Alagasco conducts business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards bearing little or no relation to culpability or actual damages continue to rise making it increasingly difficult to predict litigation results. Various legal proceedings arising in the normal course of business are currently in progress and Alagasco has accrued a provision for estimated costs. LEASE OBLIGATIONS: Total payments related to leases included as operating expense were $2,280,000, $2,146,000, and $2,201,000 in 1997, 1996 and 1995, respectively. Minimum future rental payments (in thousands) required after 1997 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
- ------------------------------------------------------------------------------- 1998 1999 2000 2001 2002 2003 and thereafter - ------------------------------------------------------------------------------- $2,329 $647 $305 $249 $71 $25 - -------------------------------------------------------------------------------
8. SUPPLEMENTAL CASH FLOW INFORMATION - -------------------------------------------------------------------------------- Supplemental information concerning cash flow activities is as follows:
- ------------------------------------------------------------------------------- For the years ended September 30, (in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------- Interest paid, net of amount capitalized $10,192 $9,216 $11,166 Income taxes paid $13,228 $5,932 $10,920 Noncash investing activities: Capitalized depreciation $ 168 $ 166 $ 166 Allowance for funds used during construction $ 490 $ 972 $ 1,054 Noncash financing activities (debt issuance costs) $ -- $ 171 $ 340 - -------------------------------------------------------------------------------
9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT - ------------------------------------------------------------------------------- FINANCIAL INSTRUMENTS: The fair value of cash and cash equivalents, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of fixed-rate long-term debt with a carrying value of $125,000,000, would be $126,886,000 at September 30, 1997. The fair value was based on the market value of debt with similar maturities and with interest rates currently trading in the marketplace. Alagasco has entered into an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $20 million. During 1997, 1996 and 1995, Alagasco sold $7,926,000, $8,831,000 and $8,454,000, respectively, of installment receivables. At September 30, 1997 and 1996, the balance of these installment receivables was $17,160,000 and 33 35 $16,964,000, respectively. Receivables sold under this agreement are considered financial instruments with off-balance sheet risk. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. CONCENTRATION OF CREDIT RISK: Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to more than 465,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, Alagasco believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure. 10. RECENT PRONOUNCEMENTS OF THE FASB - -------------------------------------------------------------------------------- In fiscal 1997, the Company adopted SFAS No. 123, Accounting for Stock-Based Compensation, which establishes a fair value-based method of accounting for employee stock options. The Statement allows companies to continue to follow the accounting treatment prescribed by APB Opinion 25 with proper disclosure. The Company has adopted the disclosure-only provisions of SFAS 123. In 1997, the Company adopted SFAS No. 125, Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities, which provides accounting and reporting standards for such transactions. The adoption did not have a material impact on the consolidated financial statements. In February 1997, the FASB issued SFAS No. 128, Earnings Per Share, which specifies computation, presentation, and disclosure requirements for EPS, and SFAS No. 129, Disclosures of Information about Capital Structure, which establishes standards for disclosing information about an entity's capital structure. The Company is required to adopt these Statements in its 1998 fiscal year. In June 1997, the FASB issued SFAS No. 130, Reporting Comprehensive Income, which requires the reporting and display of comprehensive income and its components in an entity's financial statements, and SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, which specifies revised guidelines for determining an entity's operating segments and the type and level of financial information to be required. The Company is required to adopt these Statements in fiscal year 1999. The impact of these pronouncements on the Company is currently being evaluated. 11. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) - -------------------------------------------------------------------------------- The following data summarize quarterly operating results. Alagasco's business is seasonal in character and strongly influenced by weather conditions.
- ------------------------------------------------------------------------------------------------------------------- Fiscal year 1997 quarters (in thousands) First Second Third Fourth - ------------------------------------------------------------------------------------------------------------------- Operating revenues $ 83,305 $160,152 $ 70,147 $ 49,380 Operating income (loss) $ 4,055 $ 22,963 $ 4,282 $ (2,626) Net income (loss) available for common $ 1,807 $ 20,163 $ 1,701 $ (5,101) - ------------------------------------------------------------------------------------------------------------------- Fiscal year 1996 quarters (in thousands) - ------------------------------------------------------------------------------------------------------------------- Operating revenues $ 73,185 $162,143 $ 77,225 $ 44,699 Operating income (loss) $ 4,124 $ 21,271 $ 3,638 $ (2,810) Net income (loss) available for common $ 1,986 $ 18,646 $ 1,380 $ (5,051) - -------------------------------------------------------------------------------------------------------------------
12. TRANSACTIONS WITH RELATED PARTIES - -------------------------------------------------------------------------------- Alagasco purchased natural gas from affiliates amounting to $5,165,000, $5,097,000, and $4,644,000, in 1997, 1996, and 1995, respectively. These amounts are included in gas purchased for resale. Alagasco had net payables to affiliates of $4,984,000 at September 30, 1997, and net receivables from affiliates of $9,070,000 at September 30, 1996. 34 36 REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS TO THE BOARD OF DIRECTORS OF ENERGEN CORPORATION: Our report on the consolidated financial statements of Energen Corporation and subsidiaries has been incorporated by reference in this Form 10-K from page 50 of the 1997 Annual Report to Stockholders of Energen Corporation and subsidiaries. In connection with our audits of such financial statements, we have also audited the related financial statement schedule listed in the index on page 16 and 17 of this Form 10-K. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects the information required to be included therein. Coopers & Lybrand L.L.P. Birmingham, Alabama October 23, 1997 35 37 SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS ENERGEN CORPORATION AND SUBSIDIARIES ================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1997 1996 1995 ================================================================================ ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at beginning of year $ 3,002 $ 2,533 $ 2,037 - -------------------------------------------------------------------------------- Additions: Charged to income 1,837 2,361 2,431 Recoveries and adjustments (186) (187) 67 - -------------------------------------------------------------------------------- 1,651 2,174 2,498 - -------------------------------------------------------------------------------- Less uncollectible accounts written off 1,468 1,705 2,002 - -------------------------------------------------------------------------------- BALANCE AT END OF YEAR $ 3,185 $ 3,002 $ 2,533 ================================================================================
36 38 SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS ALABAMA GAS CORPORATION ================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1997 1996 1995 ================================================================================ ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at beginning of year $ 2,985 $ 2,000 $ 2,000 - -------------------------------------------------------------------------------- Additions: Charged to income 1,575 2,349 1,935 Recoveries and adjustments (186) (187) 67 - -------------------------------------------------------------------------------- 1,389 2,162 2,002 - -------------------------------------------------------------------------------- Less uncollectible accounts written off 1,218 1,177 2,002 - -------------------------------------------------------------------------------- BALANCE AT END OF YEAR $ 3,156 $ 2,985 $ 2,000 ================================================================================
37 EX-10.F 2 ENERGEN LONG-RANGE PERFORMANCE SHARE PLAN 1 EXHIBIT 10(f) ENERGEN CORPORATION 1992 LONG-RANGE PERFORMANCE SHARE PLAN (AS AMENDED EFFECTIVE APRIL 25, 1997) 1. PURPOSE The purpose of the Energen Corporation 1992 Long-Range Performance Share Plan (the "Plan") is to further the long-term growth in profitability of the Corporation by offering long-term incentives in addition to current compensation to those key executives who will be largely responsible for such growth. 2. DEFINITIONS (a) "Award" means Performance Shares awarded to a Participant pursuant to the terms of the Plan. (b) "Award Period" means the 4-year period (Energen fiscal years) commencing with the first day of the fiscal year in which the applicable Award is granted, except as otherwise determined by the Committee at the time of grant and subject to the other provisions of this Plan. (c) "Board of Directors" means the Board of Directors of Energen. (d) "Cause" Termination of employment by the Corporation for "Cause" shall mean termination based on any of the following: (1) The willful and continued failure by a Participant to substantially perform such participant's duties with the Corporation (other than any such failure resulting from such participant's incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to the Participant specifically identifying the manner in which such Participant has not substantially performed such Participant's duties; (2) The engaging by a Participant in willful, reckless or grossly negligent misconduct which is demonstrably injurious to the Corporation monetarily or otherwise; or (3) The conviction of a Participant of a felony. (e) "Change in Control" means: 1 2 (1) The acquisition by any person, entity or "group", within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act (excluding for this purpose, any employee benefit plan of Energen or any of its Subsidiaries which acquires beneficial ownership of voting securities of Energen), of beneficial ownership (within the meaning of Rule 13d-3 under the Exchange Act) of 25% or more of either the then outstanding shares of Common Stock or the combined voting power of Energen's then outstanding voting securities, in one transaction or a series of transactions; (2) Individuals who, as of November 27, 1991, constitute the Board of Directors (the "Continuing Directors") cease for any reason to constitute at least a majority of the Board of Directors, provided that any person becoming a director of Energen subsequent to November 27, 1991, whose election, or nomination for election by Energen's stockholders, was approved by a vote of at least a majority of the Continuing Directors (other than an election or nomination of an individual whose initial assumption of office is in connection with an actual or threatened solicitation with respect to the election or removal of directors of Energen, as such terms are used in Rule 14a-11 of Regulation 14A under the Exchange Act) shall be, for purposes of the Plan, considered as though such person were a Continuing Director; (3) (i) The occurrence of a merger, consolidation or reorganization of Energen in which, as a consequence of the transaction, either the Continuing Directors do not constitute a majority of the directors of the continuing or surviving corporation or any person, entity or "group", within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act, controls 25% or more of the combined voting power of the continuing or surviving corporation; (ii) the occurrence of any sale, lease or other transfer, in one transaction or a series of transactions, of all or substantially all of the assets of Energen; or (iii) the adoption by Energen of a plan for its liquidation or dissolution. (f) "Chief Executive Officer" means the chief executive officer of Energen. (g) "Committee" means the Officers Review Committee of the Board of Directors or such other committee of two or more directors as may be determined by the Board of Directors, provided that in all events each member of the Committee shall be a "disinterested person" within the meaning of Rule 16b-3(c)(2) under the Exchange Act. (h) "Common Stock" means the Common Stock, par value $0.01 per share, of Energen as such stock may be reclassified, converted or exchanged by reorganization, merger or otherwise. (i) "Corporation" means Energen and its Subsidiaries. (j) "Employee" means any person (including any officer or director) employed by the Corporation on a full-time salaried basis. (k) "Energen" means Energen Corporation, an Alabama Corporation. (l) "Exchange Act" means the Securities Exchange Act of 1934. (m) "Fair Market Value" means the average of the daily closing prices for a share of stock for the 20 trading days ending on the fifth business day prior to the date of payment of Performance 2 3 Shares for an Award Period or an Interim Period, as the case may be, on the Composite Tape for the New York Stock Exchange -- Listed Stocks, or, if the stock is not listed on such Exchange, on the principal United States securities exchange registered under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), on which the stock is listed, or, if the stock is not listed on any such Exchange, the average of the daily closing bid quotations with respect to a share of the stock for such 20 trading days on the National Association of Securities Dealers, Inc., Automated Quotations System or any system then in use, or, if no such quotations are available, the fair market value of a share of stock as determined by a majority of the Board of Directors; provided, however that if a Change in Control shall have occurred, then such determination shall be made by a majority of the Continuing Directors. (n) "Interim Period" means a 1, 2 or 3 year period within an Award Period for which the Committee determines that there shall be Interim Periods. (o) "Officer" means any Employee of the Corporation who is an "officer" of the Corporation within the meaning of Rule 16a-l(f) under the Exchange Act as well as any Employee who has an officer title with the Corporation. (p) "Participant" means an Employee who is selected by the Committee to receive an Award under the Plan. (q) "Performance Share" means the equivalent of one share of Common Stock. (r) "Qualified Termination" means termination of a Participant's employment with the Corporation which is: (i) An involuntary termination by the Corporation other than for Cause; (ii) Expressly agreed in writing by the Participant and the Corporation to constitute a Qualified Termination for purposes of this Plan; (iii) A result of the death, Disability or Retirement of the Participant; (iv) A voluntary termination by the Participant for Good Reason. The term "Good Reason" means with respect to an Award and a Participant, the occurrence subsequent to the grant of such Award of (A) a reduction in the Participant's aggregate rate of monthly base pay from the Corporation or (B) the termination or materially adverse modification of the Energen Annual Incentive Compensation Plan without substitution of new short-term incentives providing comparable compensation opportunities for the Participant. (s) "Subsidiary" means any corporation, the majority of the outstanding voting stock of which is owned, directly or indirectly, by Energen. 3 4 3. ADMINISTRATION OF THE PLAN The Plan shall be administered by the Committee. No member of the Committee shall be eligible to participate in the Plan while serving as a member of the Committee. Subject to the provisions of the Plan, the Committee shall have the exclusive authority to select the Employees who are to participate in the Plan, to determine the Award to be made to each Employee selected to participate in the Plan, and to determine the conditions subject to which Awards will become payable under the Plan; provided, however, that, subject to the provisions of Section 5(a) hereof, the Committee may delegate to the Chief Executive Officer the authority to select and make Awards to certain Employees. The Committee shall have full power to administer and interpret the Plan and to adopt such rules and regulations consistent with the terms of the Plan as the Committee deems necessary or advisable in order to carry out the provisions of the Plan. Except as otherwise provided in the Plan, the Committee's interpretation and construction of the Plan and of any conditions applicable to Performance Share Awards shall be conclusive and binding on all persons, including the Corporation and all Participants. The Plan shall be unfunded. Benefits under the Plan shall be paid from the general assets of the Corporation. 4. PARTICIPATION Subject to the provisions of Section 5(a) hereof, Participants in the Plan shall be selected by the Committee or the Chief Executive Officer from those Employees of the Corporation, who, in the estimation of the Committee or the Chief Executive Officer, have an opportunity to influence the long-term profitability of the Corporation. 5. PERFORMANCE SHARE AWARDS (a) The Committee, or the Chief Executive Officer upon delegation of authority by the Committee, may from time to time select employees to receive Awards under the Plan. An Employee may be granted more than one Award under the Plan. In its discretion at the time of grant, the Committee may determine that an Interim Period or Interim Periods should be established for payment with respect to Awards. Whenever Interim Periods are established, the terms and conditions with respect to payment after the end of such Interim Period shall be those set by the Committee. The Committee shall make all Awards to Officers. The Committee may, in its discretion, authorize a total number of Performance Shares to be awarded to non-Officer Employees and delegate to the Chief Executive Officer the authority to select such Employees, to determine the number of Performance Shares to be awarded to such Employees and to establish Interim Periods with respect to Awards to such Employees. The Chief Executive Officer shall promptly make a written report to the Committee setting forth the name and positions of the Employees receiving such Awards and the number of Performance Shares awarded to each such employee. 4 5 (b) An Award shall not entitle a Participant to receive any dividends or dividend equivalents on Performance Shares; no Participant shall be entitled to exercise any voting or other rights of a stockholder with respect to any Award under the Plan; and no Participant shall have any interest in or rights to receive any shares of Common Stock prior to the time when the Committee determines the form of payment of Performance Shares pursuant to Section 6. (c) Payment of an Award to any Participant shall be made in accordance with Section 6 and shall be subject to such conditions for payment as the Committee may prescribe at the time the Award is made. (d) Each Award shall be made in writing and shall set forth the terms and conditions set by the Committee for payment of such Award. 6. PAYMENT OF PERFORMANCE SHARE AWARDS Each Participant granted an Award shall be entitled to payment on account thereof as of the close of the Award Period applicable to such Award, but only if the Committee has determined that the conditions for payment of the Award set by the Committee have been satisfied. Participants granted Awards with Interim Periods shall be entitled to partial payment on account thereof as of the close of the Interim Period, but only if the Committee has determined that the conditions for partial payment of the Award set by the Committee have been satisfied. Performance Shares paid to a Participant for an Interim Period need not be repaid to the Corporation, notwithstanding that, based on the conditions set for payment at the end of the Award Period, such Participant would not have been entitled to payment of any portion of such Award. Any Performance Shares paid to a Participant for the Interim Period during an Award Period shall be deducted from the Performance Shares to which such Participant is entitled at the end of the Award Period. At the time it determines whether the conditions for payment have been satisfied, the Committee, in its discretion, shall determine whether the Awards will be paid all in cash, or in some combination of cash and shares of Common Stock, except and provided that the Committee must pay in cash an amount equal to the federal, state and other taxes which the Corporation is required to withhold, and further provided that payment in shares of Common Stock shall be subject to the aggregate share limitation set forth in Section 11. The Corporation shall deduct from the cash portion of all Awards any federal, state and other taxes required by law to be withheld with respect to such Awards. Payment of Awards shall be made by the Corporation as promptly as possible after the determination by the Committee that payment has been earned and upon a date fixed by the Committee to permit calculation of Fair Market Value of the Common Stock. The portion of the Award paid in Common Stock shall be equal to the number of Performance Shares being paid in Common Stock, and the balance shall be an amount of cash equal to the Fair Market Value of the remaining Performance Shares to be paid. Notwithstanding the other provisions of this Plan, a Participant may elect pursuant to the Energen Corporation 1997 Deferred Compensation Plan to defer payment of an Award and upon such deferral shall have no further right with respect to such deferred Award other than as provided under said Deferred Compensation Plan. In the event of such an election, any Awards or portions of Awards 5 6 which become payable to the Participant and which are subject to such deferral election, may at the discretion of the Company be paid to the Trustee under such Deferred Compensation Plan in the form of Common Stock and/or cash as determined from time to time by the Company, which Common Stock shall be registered in the name of the Trustee or such other person as the Trustee may direct. Regardless of whether such deferred Common Stock or cash is delivered to the Trustee, such deferred Awards shall count against the maximum number of Performance Shares awardable under the Plan pursuant to Section 11. Furthermore any such shares of Common Stock delivered to the Trustee shall count against the maximum number of shares of Common Stock which may be issued under the Plan pursuant to Section 11. 7. TERMINATION OF EMPLOYMENT Except in the case of a Qualified Termination if, prior to the close of the Award Period with respect to an Award, a Participant's employment terminates, then any unpaid portion of such Participant's Award shall be forfeited. In the case of a Qualified Termination, the Participant shall remain entitled to payout of any outstanding Awards at the end of the applicable Award Period in accordance with the terms of this Plan including without limitation applicable performance conditions. 8. CONSULTING, NON-COMPETE AND CONFIDENTIALITY A Participant's entitlement, if any, to payout of Awards subsequent to termination of employment shall continue so long as the Participant is in compliance with the following requirements. Failure to comply shall result in forfeiture of all then outstanding Awards. (a) Consulting Services. For a period of three years following the termination of the Participant's employment with the Corporation ("Date of Termination"), Participant will fully assist and cooperate with Corporation and its representatives (including outside auditors, counsel and consultants) with respect to any matters with which the Participant was involved during the course of employment with Corporation, including being available upon reasonable notice for interviews, consultation, and litigation preparation. Except as otherwise agreed by Participant, Participant's obligation under this Section 8(a) shall not exceed 80 hours during the first year and 20 hours during each of the following two years. Such services shall be provided upon request of the Corporation but scheduled to accommodate Participant's reasonable scheduling requirements. Participant shall receive no additional fee for such services but shall be reimbursed all reasonable out-of-pocket expenses. (b) Non-Compete. For a period of twelve months following the Date of Termination, the Participant shall not Compete, (as defined below) or assist others in Competing with the Corporation. For purposes of this Agreement, "Compete" means (i) solicit in competition with Alabama 6 7 Gas Corporation ("Alagasco") any person or entity which was a customer of Alagasco at the Date of Termination; (ii) offer to acquire any local gas distribution system in the State of Alabama; or (iii) offer to acquire any coalbed methane interest in the State of Alabama. Employment by, or an investment of less than one percent of equity capital in, a person or entity which Competes with the Corporation does not constitute Competition by Participant so long as Participant does not directly participate in, assist or advise with respect to such Competition. (c) Confidentiality. Participant agrees that at all times following the Date of Termination, Participant will not, without the prior written consent of Energen, disclose to any person, firm or corporation any confidential information of Corporation which is now known to Participant or which hereafter may become known to Participant as a result of Participant's employment or association with Corporation, unless such disclosure is required under the terms of a valid and effective subpoena or order issued by a court or governmental body; provided, however, that the foregoing shall not apply to confidential information which becomes publicly disseminated by means other than a breach of this Agreement. 9. Deleted 10. Deleted 11. LIMITATION ON AWARDS The maximum number of Performance Shares which may be awarded under the Plan shall not exceed an aggregate of 500,000 (except as adjusted in accordance with Section 17) and no more than an aggregate of 350,000 shares of Common Stock (similarly adjusted in accordance with Section 17 shall be issued in payment of Performance Share Awards, the remainder being payable in cash. Any Performance Shares awarded under the Plan which are not payable upon expiration or termination of the applicable Award Period, for whatever reason, shall thereupon become available again for award under the Plan. 12. TERM OF THE PLAN The Plan shall be effective October 1, 1991, subject to the approval of the Plan by the stockholders of Energen at the Annual Meeting of Stockholders to be held January 22, 1992. Awards may be granted under the Plan by the Committee prior but subject to such stockholder approval. The Board of Directors may terminate the Plan at any time. If not sooner terminated, the Plan terminates on the date on which all of the Performance Shares subject to award under the Plan have been paid, but no 7 8 grant of Awards may be made after September 30, 2001. No such termination shall adversely affect any right or obligation with respect to an Award theretofore made. 13. CANCELLATION OF PERFORMANCE SHARES With the written consent of a Participant holding Performance Shares granted to such Participant under the Plan, the Committee may cancel such Performance Shares. In the event of any such cancellation, all rights of the former holder of such cancelled Performance Shares in respect of such cancelled Performance Shares under the Plan or otherwise shall terminate. 14. NO ASSIGNMENT OF INTEREST The interest of any person in the Plan shall not be assignable, either by voluntary assignment or by operation of law, and any assignment of such interest, whether voluntary or by operation of law, shall render the Award void. Amounts payable under the Plan shall be transferable only by will or by the laws of descent and distribution. 15. EMPLOYMENT RIGHTS An Award made under the Plan shall not confer any right on the Participant to continue in the employ of the Corporation or limit in any way the right of the Corporation to terminate such Participant's employment at any time. 16. EXPENSES The expenses of administering the Plan shall be borne by the Corporation. 17. DILUTION AND OTHER ADJUSTMENTS If Energen shall at any time issue any shares of Common Stock (i) in subdivision of outstanding shares of Common Stock, by reclassification or otherwise, or (ii) for a stock dividend, the number of Performance Shares which previously have been awarded to Participants and which may be awarded under the Plan shall be increased proportionately; and in like manner, in case of any combination of shares of Common Stock, by reclassification or otherwise, the number of Performance Shares which previously have been awarded to Participants and which may be awarded under the Plan shall be reduced proportionately. If Energen shall at any time declare and pay an extraordinary dividend in cash or property (other than a stock dividend with respect to the Common Stock referred to in clause (ii), above), the number of Performance Shares which previously have been awarded to Participants shall be increased in such manner as the Committee shall determine 8 9 to be fair under the circumstances of such extraordinary dividend; provided, however, that if a Change in Control shall have occurred, such determination shall be made by a majority of the Continuing Directors. 18. CHANGE IN CONTROL The other provisions of the Plan notwithstanding, (i) the Committee is authorized to specify such procedures as it may deem appropriate in connection with a Change in Control of Energen, including without limitation acceleration of payment of part or all of outstanding Awards, the establishment and funding of a trust to be held for the payment of Awards following such Change in Control, and the modification of performance conditions applicable to outstanding Awards and (ii) all Award payments made subsequent to a Change in Control shall be paid in cash. 19. AMENDMENT OF THE PLAN The Board of Directors may amend or suspend the Plan at any time. No such amendment or suspension shall adversely affect any right or obligation with respect to an Award theretofore made, including, without limitation, the right to receive payment of Awards in accordance with Section 18 and procedures adopted thereunder (subject, however, to the right of the Committee to amend or suspend such Section 18 procedures prior to the occurrence of a Change in Control). As adopted November 27, 1991 by the Energen Corporation Board of Directors with approval January 22, 1992 by the shareholders and subsequently (i) amended September 25, 1996 by the Board, with approval January 26, 1997 by the shareholders, and (ii) amended April 25, 1997 by the Board. 9 EX-13 3 MANAGEMENTS DISCUSSION AND ANALYSIS 1 EXHIBIT 13 MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION RESULTS OF OPERATIONS CONSOLIDATED NET INCOME Energen Corporation's net income for the 1997 fiscal year totaled $29 million, or $2.31 per share, a significant increase from 1996 earnings of $21.5 million, or $1.95 per share. Continued financial and operating strength at Energen's utility, Alabama Gas Corporation (Alagasco), combined with the results of Energen's diversified growth strategy at Taurus Exploration Inc. (Taurus), Energen's oil and gas subsidiary, to produce an 18.5 percent increase in earnings per share. For 1995, Energen reported earnings of $19.3 million, or $1.77 per share. 1997 VS 1996: Alagasco's earnings were $18.6 million, a 9.5 percent increase over prior-year earnings of $17 million, and represented record earnings for a seventh consecutive year. This increase in net income reflects Alagasco's ability to earn within its allowed range of return on an increased level of equity representing investment in its utility plant. Alagasco achieved a return on equity (ROE) of 13.5 percent. Taurus earned $10 million in 1997, more than doubling prior year earnings of $4.5 million. The main reasons for the significant increase were a 130 percent increase in oil and gas production volumes to 37 billion cubic feet equivalent (Bcfe) and a $3.8 million increase in nonconventional fuels tax credits primarily resulting from production from coalbed methane property acquisitions in 1996 and 1997. Partially offsetting these gains were increased production-related expenses, increased interest expense, and a $1.3 million after-tax write down of certain offshore oil and gas properties in anticipation of their sale. 1996 VS 1995: Alagasco's 1996 net income of $17 million increased 8 percent over 1995 net income of $15.7 million primarily due to the utility earning within its allowed range of return on an increased level of equity representing investment in its utility plant. Fiscal 1995 earnings included a one-time after-tax charge of $503,000 resulting from a voluntary early retirement program. Taurus's net income increased $1 million to $4.5 million in 1996 on the strength of increased oil and gas production, higher commodity sales prices and gains on the sale of reserves; negatively influencing Taurus's earnings were increases in production-related expenses, primarily depreciation, depletion and amortization (DD&A), as well as increased interest and exploration expenses. OPERATING INCOME Consolidated operating income in 1997, 1996, and 1995 totaled $52 million, $38.8 million, and $32 million, respectively. Operating income grew significantly in 1997, reflecting another successful year under Energen's diversified growth strategy. Taurus again showed significant improvement over the prior year, and growth in Alagasco's operating income was consistent with its increased level of equity upon which it is allowed to earn a return. Operating income in 1996 also benefited from the implementation of Energen's growth strategy at Taurus along with the recognition of a gain on the sale of reserves. ALAGASCO: Alagasco generates revenues through the sale and transportation of natural gas. Shifts between transportation and sales gas can cause variations in natural gas revenues since the transportation rate does not contain an amount representing the cost of gas. Alagasco's rate structure allows similar margins on transported and sales gas; therefore, operating income is not adversely affected. Weather also can cause variations in revenues, but operating margins remain unaffected due to a real-time temperature adjustment which allows Alagasco to adjust customer bills monthly to reflect changes in usage due to departures from normal weather. Alagasco's gross natural gas sales revenues totaled $329.9 million, $326.8 million, and $265.5 million, in 1997, 1996, and 1995, respectively. In the current year, sales revenues remained relatively stable as higher commodity cost of gas, which is passed through to customers in rates, was largely offset by the impact of warmer weather on throughput. In 1996 significantly colder weather and higher commodity gas costs combined to generate substantially higher revenues than in the previous year; margins associated with the colder 21 2 weather were removed via the real-time temperature adjustment to customer bills. Residential sales volumes decreased 19 percent in the current year primarily due to weather in Alagasco's service territory that was 12 percent warmer than normal and 22 percent warmer than that of the prior year. Sales and transportation volumes to commercial and industrial customers totaled 78.2 Bcf in 1997 and 76.5 Bcf in 1996. While small commercial and industrial customers, more sensitive to weather, experienced volume decreases similar to residential customers, Alagasco increased throughput to several large transportation customers. In 1996, Alagasco's coldest winter in 18 years significantly increased residential and small commercial and industrial volumes. Cost of gas remained relatively stable in 1997 as higher commodity gas cost was offset by a weather-related decrease in purchased volumes. In the prior year, colder weather had the opposite impact on purchased volumes and, coupled with higher commodity cost, caused a 36 percent increase in cost of gas.
- ------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (dollars in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------- Gross natural gas sales revenues..................................... $ 329,904 $ 326,844 $ 265,477 Cost of natural gas.................................................. (177,837) (181,400) (133,556) Revenue taxes........................................................ (19,676) (20,055) (16,051) - ------------------------------------------------------------------------------------------------------------------------ Net natural gas sales margin......................................... 132,391 125,389 115,870 Net natural gas transportation margin............................... 33,080 30,408 30,490 - ------------------------------------------------------------------------------------------------------------------------ Net natural gas sales and transportation margin..................... $ 165,471 $ 155,797 $ 146,360 - ------------------------------------------------------------------------------------------------------------------------ Natural gas sales volumes (MMcf) Residential....................................................... 28,357 34,963 27,489 Commercial and industrial-small................................... 12,554 15,002 12,288 Commercial and industrial-large................................... -- -- 29 - ------------------------------------------------------------------------------------------------------------------------ Total natural gas sales volumes...................................... 40,911 49,965 39,806 Natural gas transportation volumes (MMcf)............................ 65,622 61,458 61,640 - ------------------------------------------------------------------------------------------------------------------------ Total deliveries (MMcf).............................................. 106,533 111,423 101,446 - ------------------------------------------------------------------------------------------------------------------------
Operations and maintenance (O&M) expense at the utility increased 4 percent in 1997 primarily due to higher labor and related costs and increased marketing expense; partially offsetting these amounts was a decrease in bad debt expense created when the utility increased its provision for doubtful accounts in the prior year to reflect increased exposure from higher commodity gas costs in accounts receivable. In 1996, distribution expense, which includes labor and maintenance costs, was higher due to colder-than-normal weather. In addition, while marketing and bad debt expenses were higher, they were offset by the inclusion in 1995 of a one-time charge for an early retirement option. In both 1997 and 1996, the increase in O&M on a per customer basis fell within the inflation-based cap established by the Alabama Public Service Commission (APSC) as part of the utility's rate-setting mechanism. 22 3 Consistent with growth in the utility's depreciable base, depreciation expense rose 10 percent in both 1997 and 1996. 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. As discussed more fully in Note 2 to the Consolidated Financial Statements, Alagasco is subject to regulation by the APSC. On October 7, 1996, the APSC issued an order to extend the Company's rate-setting mechanism through January 1, 2002. Under the terms of that extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. TAURUS: During 1997, Taurus continued its aggressive growth strategy by acquiring producing oil and gas properties with varying degrees of development potential. In the second quarter of 1997, Taurus acquired approximately 319 Bcfe of oil and gas reserves in the San Juan Basin for $77 million and plans to spend an additional $8 million over the next several years to substantially develop these long-lived reserves. In the third quarter, Taurus spent $8.3 million to purchase approximately 10.2 Bcfe of proved reserves in southwest Mississippi from Griffin and Griffin Oil Company. Approximately 85 percent of the estimated proved reserves are gas and almost 60 percent are developed and producing. Taurus plans to spend an additional $1.2 million to develop the remaining 4.5 Bcfe of behind-pipe and proved undeveloped reserves. In several smaller transactions, Taurus acquired 4.8 Bcfe of predominantly natural gas reserves in Texas and Louisiana for $5.2 million. Approximately 40 percent of the proved reserves are developed and producing, and the Company expects to spend an additional $3.2 million to fully develop the remaining behind-pipe and proved undeveloped reserves. Also in the third quarter, Taurus invested $16 million for a 9 percent interest in a joint venture with Sonat Exploration and United Meridian Corporation for future exploration of the Cotton Valley Pinnacle Reef trend. In August, the Company purchased Amoco Corporation's Black Warrior Basin coalbed methane properties for $72 million; these properties included over 260 producing wells and estimated net proved reserves of 107 Bcf. Substantially all of the reserves are classified as proved producing. In addition, Taurus spent $9.3 million in July 1997 to purchase approximately 10.4 Bcfe of domestic oil and natural gas reserves located in Texas and the Rocky Mountains from United Meridian Corporation. Largely as a result of these acquisitions, revenues from oil and gas production activities continued to grow significantly. Total production volumes rose 130 percent to 37 Bcfe. Natural gas production, including coalbed methane, increased 138 percent to 29.3 Bcf. Oil volumes increased 22 percent to 775 MBbl. Taurus also acquired high BTU-content natural gas reserves in the San Juan Basin which yielded 502 MBbl in natural gas liquids by year-end. Taurus also benefited from higher realized oil and gas prices during 1997. Gas sales prices rose 4 percent to $2.05 per Mcf and oil sales prices increased 11 percent to $18.08 per barrel. Natural gas liquids sold for $11.45 per barrel. During 1996, revenues from oil and gas production activities also grew notably. Total production volumes were 16.1 Bcfe, increasing 60 percent from the prior year. Gas prices were $1.97 per Mcf, higher by 15 percent, and oil prices were $16.25 per barrel, up 8 percent. Coalbed methane operating fees are calculated as a percentage of net proceeds on certain properties, as defined by the related operating agreements, and vary with changes in natural gas prices, production volumes, and operating expenses. Revenues from operating fees were $4.4 million, $3.8 million and $3.4 million in 1997, 1996 and 1995, respectively. The annual increases resulted primarily from higher natural gas prices. Taurus may, in the ordinary course of business, be involved in the sale of both developed and 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 Taurus's technical staff. In 1997 and 1996, Taurus recorded gains of $1 million and $3.9 million, respectively, on the sale of various properties. The largest of several property sales occurred in September 1996 when Taurus recorded a $3.2 million gain. 23 4
- ------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (dollars in thousands, except unit price) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------- Revenues Natural gas production............................................ $ 60,228 $ 24,262 $ 14,748 Oil production.................................................... 19,753 10,313 3,765 Operating fees.................................................... 4,385 3,846 3,374 Other............................................................. 880 3,769 726 - ------------------------------------------------------------------------------------------------------------------------- Total Revenues....................................................... $ 85,246 $ 42,190 $ 22,613 - ------------------------------------------------------------------------------------------------------------------------- Production volumes Natural gas (MMcf)................................................ 29,318 12,308 8,597 Oil (MBbl)........................................................ 775 635 250 Natural gas liquids (MBbl)........................................ 502 -- -- - ------------------------------------------------------------------------------------------------------------------------- Average unit sales price Natural gas (per Mcf)............................................. $ 2.05 $ 1.97 $ 1.72 Oil (per Bbl)..................................................... $ 18.08 $ 16.25 $ 15.07 Natural gas liquids (Bbl)......................................... $ 11.45 -- -- - -------------------------------------------------------------------------------------------------------------------------
Operations expense increased $12.4 million and $4.3 million in 1997 and 1996, respectively, primarily due to significant growth in production and in acquisition activity at Taurus. Lease operating expense rose by $10.5 million in 1997 and $3.4 million in 1996, mainly due to acquisitions. In addition, exploration expense increased $1.2 million and $2.5 million in 1997 and 1996, respectively, as a result of Taurus's increased exploratory efforts. DD&A expense rose $16.5 million in 1997 largely due to significantly higher production (37 Bcf in 1997 compared to 16.1 Bcf in 1996). The increase was partially offset by a decrease in the average depletion rate to $0.90 per Mcf due to the significant addition of long-lived assets. Also during 1997, the Company adopted Statement of Financial Accounting Standard (SFAS) 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of (see Note 10). Under SFAS 121, Taurus recorded additional DD&A expense of $2.1 million to write down the value of certain oil and gas properties that are held for sale. The properties have 9.7 Bcf of proved undeveloped reserves. During 1996, DD&A expense increased $9.6 million also largely due to increased production (10.1 Bcf in 1995). In addition, the average depletion rate of $1.15 per Mcf increased from $0.88 per Mcf in 1995 as a result of reserve revisions and property write-downs. Taurus's expense for taxes other than income primarily reflects production-related taxes. For 1997, 1996, and 1995, Taurus recorded $6.3 million, $1.9 million and $0.8 million, respectively, in severance taxes. NON-OPERATING ITEMS CONSOLIDATED: Fiscal 1997 interest expense increased $9 million primarily due to the financing of Taurus's acquisitions under its growth strategy with both short-term and long-term debt. The average daily outstanding balance under short-term credit facilities was $88 million compared to $38 million in the prior year. Also influencing the current year was interest for a full year on $40 million in Energen medium-term notes (MTNs) issued in the fourth quarter of 1996 and, to a lesser extent, the issuance of an additional $85 million of MTNs in July 1997. In addition, Alagasco issued $25 million in MTNs in the fourth quarter of 1996 to repay short-term debt used to fund customer refunds, gas storage inventory replacement and facilities upgrade and acquisition. Interest expense increased $2.2 million in 1996 also due primarily to Taurus's growth strategy. The average daily outstanding balance under short-term credit facilities was significantly higher than in 1995 and interest was recorded for a full year on $50 million of MTNs issued in mid-1995. Also contributing to increased interest expense was the fourth quarter 1996 issuance of MTNs at both Energen and Alagasco. 24 5 The fluctuation in other income over the three-year period is primarily due to the inclusion in 1996 of the early-call premium associated with the redemption of debt at Alagasco in 1995. The Company's effective tax rates in 1997, 1996, and 1995 were lower than statutory federal tax rates primarily due to the recognition of nonconventional fuels tax credits and the amortization of investment tax credits. The Company's effective tax rates are expected to remain lower than statutory federal rates through December 31, 2002, as tax credits generated each year are expected to be fully recognized in the financial statements. Income tax expense decreased in 1997 from 1996 primarily due to the recognition of an additional $3.8 million of nonconventional fuels tax credits. An increase in income tax expense in 1996 resulted primarily from increased pre-tax income. Like many companies, Energen is in the process of evaluating its computer software to determine whether modifications will be required for it to function properly in the year 2000. Costs associated with evaluation and testing are being expensed as incurred. The Company has not yet fully determined the total cost of the project but does not anticipate any material impact on the consolidated financial statements. FINANCIAL POSITION AND LIQUIDITY The Company's net cash from operating activities totaled $66.8 million, $46.7 million, and $60.9 million in 1997, 1996 and 1995, respectively. In the current year, operating cash flow benefited from increased net income caused by significantly higher oil and gas production volumes and higher realized oil and gas prices. Offsetting these amounts was the $17 million payout in January 1997 of supplier refunds to customers. Other working capital items, which are generally the result of timing of payments, combined to create the remaining increase. Operating activities contributed $60.9 million in 1995. Colder weather in 1996 had an impact through its effect on gas supply costs as reflected in increased accounts receivable and payable and in Alagasco's need to utilize and replenish its storage gas inventory. The receipt of amounts from suppliers to be refunded to customers positively affected cash flows in 1996. During 1997, the Company invested a total of $279.8 million primarily in the acquisition of oil and gas properties. In the current year, Taurus invested $239.7 million in total capital expenditures--$193.7 million for property acquisitions including $16 million to obtain a small working interest in an exploratory joint venture, $36.4 million for development, and $13.3 million for exploration ($5.1 million of which was charged to income). Current-year reserve additions totaled 464 Bcfe. Utility expenditures for the year totaled $43.3 million and represented primarily normal system distribution expansion. Cash used in investing activities was $152.1 million in 1996 and $67.6 million in 1995. The increase in 1996 was also largely due to the implementation of Energen's growth strategy. Taurus invested $108 million in proved property acquisitions with development potential, adding 178 Bcfe of proved developed and undeveloped oil and gas reserves. Prior-year acquisitions include the $61 million purchase of 105 Bcf of coalbed methane reserves in Alabama. The 1995 acquisitions totaled $16.9 million and added 26.8 Bcfe to proved reserves. Taurus sold its working interest in reserves associated with the PMC acquisition venture in 1996 resulting in cash proceeds of $13.1 million. Financing activities provided a source of $307.2 million in 1997. The Company issued $85 million of MTNs redeemable July 15, 2002, to July 28, 2027, with interest rates ranging from 6.6 percent to 7.6 percent. In addition, Energen issued 1,725,000 shares of common stock in January generating net proceeds of $49.1 million, and 1,200,000 shares in September generating net proceeds of $41.1 million. The proceeds from the debt and equity offerings were used to repay short-term debt incurred mainly to finance Taurus's acquisition and development strategy. In addition, the Company utilized $45 million in short-term credit facilities primarily for Taurus's capital expenditures. For shares tax planning purposes, the Company borrowed $98.6 million to invest in short-term federal obligations. The Treasuries matured in early October and the proceeds were used to repay the debt. The cash provided by financing activities totaled $80 million in 1996. The Company issued $40 million of MTNs and utilized an additional $26.7 million in short-term credit facilities to finance Taurus's acquisition strategy in the prior year. Also included were the proceeds from the issuance of $25 million in Alagasco MTNs used for customer refunds, gas storage inventory replacement, and facilities upgrade and acquisition. Cash provided by financing activities in 1995 was $15.9 million and included the issuance of $50 million in Alagasco MTNs used to refinance other long-term debt. 25 6 CAPITAL EXPENDITURES NATURAL GAS DISTRIBUTION: During the last three fiscal years, Alagasco has invested $129.2 million for capital projects: $105.5 million was spent on normal expansion replacements and support of its distribution system; $8.2 million was used in connection with the development of a new customer information system which was completed in April 1996; $5.6 million was used to improve gas availability; $7.3 million was used to purchase four municipal gas systems; and $2.7 million was used in connection with the development of a new payroll/human resource information system.
- ------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------- Capital expenditures for: Renewals, replacements, system expansion and other................ $ 39,779 $ 35,064 $ 30,611 Additions to improve gas availability............................. 758 1,799 3,024 Municipal gas system acquisitions................................. 3 3,305 3,972 Payroll/human resource information system......................... 2,737 -- -- Customer information system....................................... -- 3,007 5,173 - ------------------------------------------------------------------------------------------------------------------------- Total............................................................. $ 43,277 $ 43,175 $ 42,780 - -------------------------------------------------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION: Taurus has spent $403.8 million for capital projects over the last three fiscal years, $11.3 million of which was charged to income as exploration expense. Expenditures for property acquisitions were $321.7 million, exploratory expenditures totaled $26.9 million, and $52.5 million was spent in development activities.
- ------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------- Capital and exploration expenditures for: Property acquisitions............................................. $ 193,729 $ 110,008 $ 17,939 Exploration....................................................... 13,277 9,855 3,794 Development....................................................... 36,375 10,040 6,044 Other............................................................. 1,406 583 716 - ------------------------------------------------------------------------------------------------------------------------- Total......................................................... 244,787 130,486 28,493 Less exploration expenditures charged to income...................... 5,069 4,169 2,064 - ------------------------------------------------------------------------------------------------------------------------- Net capital expenditures............................................. $ 239,718 $ 126,317 $ 26,429 - -------------------------------------------------------------------------------------------------------------------------
FUTURE CAPITAL RESOURCES AND LIQUIDITY The Company will continue to implement its diversified growth strategy over the next three years. That strategy calls for Taurus to invest $500 million to $650 million to acquire and develop producing properties and to participate in exploration and related development during the three-year period. In fiscal year 1998, Taurus plans to spend approximately $165 million, including $100 million for property acquisitions. It should be noted that Taurus's continued ability to invest in property acquisitions will be influenced significantly by industry trends as the producing property acquisition market has historically been cyclical. From time to time, Taurus also may be engaged in negotiations to sell, trade or otherwise dispose of previously acquired property. To finance Taurus's investment program, the Company will continue to utilize its available short-term credit facilities to supplement internally generated cash flow, with long-term debt and equity providing permanent financing. During 1997, Energen has increased its available short-term credit facilities to $203 million to accommodate the Taurus strategy. 26 7 Utility capital expenditures for normal distribution system renewal and expansion and support facilities could approximate $60 million in fiscal 1998. Alagasco also will maintain an investment in storage working gas which is expected to average approximately $24 million in 1998. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. OUTLOOK NATURAL GAS DISTRIBUTION: The October 1996 extension of the utility's rate-setting mechanism until January 1, 2002, gives Alagasco the opportunity to continue earning an allowed return on equity within a range of 13.15 percent to 13.65 percent through fiscal 2002. Over this period, Alagasco's earnings should grow 3 percent to 5 percent annually as the service territory requires the investment of additional utility plant. The utility continues to rely on rate flexibility to effectively prevent bypass of our distribution system. Even though the utility enjoys a market saturation rate much higher than the national average, customer growth in the service territory is limited. Alagasco will continue to focus on the acquisition of municipal gas systems to supplement normal growth. EXPLORATION AND PRODUCTION: During fiscal year 1998, Taurus plans to spend approximately $165 million, including $100 million for property acquisitions. Amounts invested could vary depending on the available opportunities. Production is expected to increase almost 50 percent to 55 Bcfe, and proved reserves could reach 750 Bcfe by year end. Production from existing properties should generate 52 Bcfe of oil and gas during the year, with an additional 3 Bcfe from as yet unidentified acquisitions. As Taurus begins fiscal 1998, 83 percent of its estimated gas production and 39 percent of its estimated oil production is hedged or under contract at average prices of $2.26 per Mcf and $20.29 per barrel, respectively. As acquisitions are made, Taurus will use futures, swaps and/or fixed-price contracts to lock in commodity prices for up to 36 months in order to protect targeted returns. A significant part of Taurus's earnings in fiscal 1998 will be the more than $14 million of tax credits expected to be generated by the Company's coalbed methane production. Taurus plans to spend $500 million to $650 million in the acquisition and development of producing properties and in exploration and related development over the next three years. With this level of spending, Taurus's production levels could reach 85 Bcfe to 95 Bcfe by the end of fiscal year 2000, with proved reserves of up to 1 trillion cubic feet equivalent. FORWARD-LOOKING STATEMENTS AND RISK: Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company and its subsidiaries, are forward-looking statements that are dependent on certain events, risks and uncertainties that may be outside their control which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, future business decisions, and other uncertainties, all of which are difficult to predict. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. In the event Taurus is unable to invest fully its planned acquisition expenditures, future operating revenues and proved reserves could be negatively affected. The drilling of exploratory wells can involve significant risks including those related to timing, success rates and cost overruns. These risks can be affected by lease and rig availability, complex geology and other factors. Results of operations and cash flows also could be affected by future oil and gas prices. Although Taurus makes use of futures, swaps and fixed-price contracts to mitigate risk, fluctuations in oil and gas prices may affect the Company's financial position and results of operations. RECENT PRONOUNCEMENTS OF THE FASB In fiscal 1997, the Company adopted SFAS No. 123, Accounting for Stock-Based Compensation, which establishes a fair value-based method of accounting for employee stock options. The Statement allows companies to continue to follow the accounting treatment prescribed by APB Opinion 25 with proper disclosure. The Company has adopted the disclosure-only provisions of SFAS 123 (see Note 6). 27 8 In 1997, the Company adopted SFAS No. 125, Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities, which provides accounting and reporting standards for such transactions. The adoption did not have a material impact on the consolidated financial statements. In February 1997, the FASB issued SFAS No. 128, Earnings Per Share, which specifies computation, presentation, and disclosure requirements for EPS, and SFAS No. 129, Disclosures of Information about Capital Structure, which establishes standards for disclosing information about an entity's capital structure. The Company is required to adopt these statements in its 1998 fiscal year. In June 1997, the FASB issued SFAS No. 130, Reporting Comprehensive Income, which requires the reporting and display of comprehensive income and its components in an entity's financial statements, and SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, which specifies revised guidelines for determining an entity's operating segments and the type and level of financial information to be required. The Company is required to adopt these statements in fiscal year 1999. QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
- ------------------------------------------------------------------------------------------------------------------- Quarter ended (in dollars) High Low Close Dividends Paid - ------------------------------------------------------------------------------------------------------------------- December 31, 1995.................................... 25 1/8 21 3/8 24 1/8 .29 March 31, 1996....................................... 25 3/8 21 3/4 21 7/8 .29 June 30, 1996........................................ 24 1/4 21 7/8 22 1/8 .29 September 30, 1996................................... 25 22 24 .30 - ------------------------------------------------------------------------------------------------------------------- December 31, 1996.................................... 31 1/4 23 3/4 30 1/4 .30 March 31, 1997....................................... 31 3/8 29 29 7/8 .30 June 30, 1997........................................ 35 1/8 29 1/8 33 11/16 .30 September 30, 1997................................... 37 3/4 33 1/4 35 9/16 .31 - -------------------------------------------------------------------------------------------------------------------
28 9 CONSOLIDATED STATEMENTS OF INCOME
Energen Corporation - ------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands, except share data) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Natural gas distribution............................................. $ 362,984 $ 357,252 $ 295,967 Oil and gas production activities.................................... 85,246 42,190 22,613 - ----------------------------------------------------------------------------------------------------------------------- Total operating revenues.......................................... 448,230 399,442 318,580 - ----------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas.......................................................... 175,514 178,810 130,220 Operations........................................................... 116,886 100,822 93,293 Maintenance.......................................................... 11,112 11,078 9,849 Depreciation, depletion and amortization............................. 59,688 41,118 29,556 Taxes, other than income taxes....................................... 33,044 28,817 23,629 - ----------------------------------------------------------------------------------------------------------------------- Total operating expenses.......................................... 396,244 360,645 286,547 - ----------------------------------------------------------------------------------------------------------------------- OPERATING INCOME..................................................... 51,986 38,797 32,033 - ----------------------------------------------------------------------------------------------------------------------- OTHER INCOME (EXPENSE) Interest expense, net of amounts capitalized......................... (22,906) (13,920) (11,693) Other, net........................................................... 3,014 1,712 2,649 - ----------------------------------------------------------------------------------------------------------------------- Total other income (expense)...................................... (19,892) (12,208) (9,044) - ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES........................................... 32,094 26,589 22,989 Income taxes......................................................... 3,097 5,048 3,681 - ----------------------------------------------------------------------------------------------------------------------- NET INCOME........................................................... $ 28,997 $ 21,541 $ 19,308 - ----------------------------------------------------------------------------------------------------------------------- EARNINGS PER AVERAGE COMMON SHARE.................................... $ 2.31 $ 1.95 $ 1.77 - ----------------------------------------------------------------------------------------------------------------------- AVERAGE COMMON SHARES OUTSTANDING.................................... 12,563,096 11,023,434 10,906,315 - -----------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 29 10 CONSOLIDATED BALANCE SHEETS
Energen Corporation - -------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 - -------------------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS Cash and cash equivalents............................................ $ 105,402 $ 11,301 Accounts receivable, net of allowance for doubtful accounts of $3,185 in 1997 and $3,002 in 1996................................. 70,676 48,126 Inventories, at average cost Storage gas inventory............................................. 25,367 28,214 Materials and supplies............................................ 7,281 7,704 Liquified natural gas in storage.................................. 3,630 2,417 Deferred income taxes................................................ 7,438 7,995 Prepayments and other................................................ 22,371 8,949 - ------------------------------------------------------------------------------------------------------------ Total current assets............................................ 242,165 114,706 - ------------------------------------------------------------------------------------------------------------ PROPERTY, PLANT AND EQUIPMENT Oil and gas properties, successful efforts method.................... 454,210 224,469 Less accumulated depreciation, depletion and amortization 87,554 60,152 - ------------------------------------------------------------------------------------------------------------ Oil and gas properties, net.......................................... 366,656 164,317 - ------------------------------------------------------------------------------------------------------------ Utility plant........................................................ 583,630 544,643 Less accumulated depreciation........................................ 287,749 268,110 - ------------------------------------------------------------------------------------------------------------ Utility plant, net................................................ 295,881 276,533 - ------------------------------------------------------------------------------------------------------------ Other property, net.................................................. 4,466 4,066 - ------------------------------------------------------------------------------------------------------------ Total property, plant and equipment, net............................. 667,003 444,916 - ------------------------------------------------------------------------------------------------------------ OTHER ASSETS Deferred income taxes................................................ 1,144 (972) Deferred charges and other........................................... 9,485 10,760 - ------------------------------------------------------------------------------------------------------------ Total other assets................................................ 10,629 9,788 - ------------------------------------------------------------------------------------------------------------ TOTAL ASSETS......................................................... $ 919,797 $ 569,410 - ------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 30 11
- ------------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 - ------------------------------------------------------------------------------------------------------------------------- CAPITAL AND LIABILITIES CURRENT LIABILITIES Long-term debt due within one year................................... $ 1,855 $ 1,805 Notes payable to banks............................................... 202,000 59,000 Accounts payable..................................................... 49,196 32,659 Accrued taxes........................................................ 18,300 17,567 Customers deposits................................................... 16,399 17,364 Amounts due customers................................................ 7,347 17,157 Accrued wages and benefits........................................... 13,719 11,584 Other................................................................ 21,935 18,049 - ------------------------------------------------------------------------------------------------------------------------- Total current liabilities......................................... 330,751 175,185 - ------------------------------------------------------------------------------------------------------------------------- DEFERRED CREDITS AND OTHER LIABILITIES Other................................................................ 8,301 10,275 - ------------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities...................... 8,301 10,275 - ------------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES........................................ -- -- - ------------------------------------------------------------------------------------------------------------------------- CAPITALIZATION Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized -- -- Common shareholders equity Common stock, $0.01 par value; 30,000,000 shares authorized, 14,398,109 shares outstanding in 1997 and 11,162,634 shares outstanding in 1996.................................... 144 112 Premium on capital stock........................................ 185,841 86,833 Capital surplus................................................. 2,802 2,802 Retained earnings............................................... 112,356 98,658 - ------------------------------------------------------------------------------------------------------------------------- Total common shareholders equity.................................. 301,143 188,405 Long-term debt....................................................... 279,602 195,545 - ------------------------------------------------------------------------------------------------------------------------- Total capitalization.............................................. 580,745 383,950 - ------------------------------------------------------------------------------------------------------------------------- TOTAL CAPITAL AND LIABILITIES........................................ $ 919,797 $ 569,410 - -------------------------------------------------------------------------------------------------------------------------
31 12 CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
Energen Corporation - ----------------------------------------------------------------------------------------------------------------------------- (In thousands, except share amounts) - ----------------------------------------------------------------------------------------------------------------------------- Common Stock Treasury Stock Number of Par Premium on Capital Retained Number of Shares Value Capital Stock Surplus Earnings Shares Cost - ----------------------------------------------------------------------------------------------------------------------------- BALANCE AT SEPTEMBER 30, 1994 10,917,904 $ 109 $ 81,073 $ 2,802 $ 83,042 -- $ -- Net income 19,308 Purchase of treasury shares (128,900) (2,721) Shares issued for: Dividend reinvestment plan 14 19,035 394 Employee benefit plans 3,829 156 98,238 2,077 Cash dividends - $1.13 per share (12,330) - --------------------------------------------------------------------------------------------------------------------------- BALANCE AT SEPTEMBER 30, 1995 10,921,733 109 81,243 2,802 90,020 (11,627) (250) Net income 21,541 Purchase of treasury shares (86,900) (1,985) Shares issued for: Dividend reinvestment plan 80,529 1 1,827 66,552 1,511 Employee benefit plans 160,372 2 3,763 31,975 724 Cash dividends - $1.17 per share (12,903) - --------------------------------------------------------------------------------------------------------------------------- BALANCE AT SEPTEMBER 30, 1996 11,162,634 112 86,833 2,802 98,658 -- -- Net income 28,997 Shares issued for: Stock Offerings 2,925,000 29 89,867 Dividend reinvestment plan 120,802 1 3,611 Employee benefit plans 189,673 2 5,530 Cash dividends - $1.21 per share (15,299) - ---------------------------------------------------------------------------------------------------------------------------- BALANCE AT SEPTEMBER 30, 1997 14,398,109 $ 144 $ 185,841 $ 2,802 $ 112,356 -- $ -- - ----------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 32 13 CONSOLIDATED STATEMENTS OF CASH FLOWS
Energen Corporation - ------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net income........................................................... $ 28,997 $ 21,541 $ 19,308 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization.......................... 59,688 41,118 29,556 Deferred income taxes, net........................................ (2,646) (672) (2,082) Deferred investment tax credits, net.............................. (487) (487) (487) Gain on sale of assets............................................ (1,081) (3,954) -- Net change in: Accounts receivable............................................. (22,550) (17,313) 3,332 Inventories..................................................... 2,057 (6,809) 3,775 Deferred gas cost............................................... (537) (549) 34 Accounts payable gas purchases................................... 5,758 (1,614) 9,882 Accounts payable trade........................................... 10,779 2,031 (5,120) Amounts due customers........................................... (9,810) 13,942 2,483 Other current assets and liabilities............................ (6,996) (2,272) (3,290) Other, net........................................................ 3,610 1,722 3,478 - ------------------------------------------------------------------------------------------------------------------------ Net cash provided by operating activities....................... 66,782 46,684 60,869 - ------------------------------------------------------------------------------------------------------------------------ INVESTING ACTIVITIES Additions to property, plant and equipment........................... (283,274) (168,414) (68,940) Proceeds from sale of assets......................................... 1,871 13,134 -- Payments on notes receivable......................................... 527 1,557 816 Other, net........................................................... 1,030 1,627 501 - ------------------------------------------------------------------------------------------------------------------------ Net cash used in investing activities........................... (279,846) (152,096) (67,623) - ------------------------------------------------------------------------------------------------------------------------ FINANCING ACTIVITIES Payment of dividends on common stock................................. (15,299) (12,903) (12,330) Issuance of common stock............................................. 95,357 4,645 84 Purchase of treasury stock........................................... -- (1,985) (2,721) Reduction of long-term debt.......................................... (943) (1,025) (45,070) Proceeds from issuance of long-term debt............................. 84,416 64,586 49,660 Note payable issued to purchase U.S. Treasury securities............. 98,636 -- -- Net change in short-term debt........................................ 44,998 26,700 26,300 - ------------------------------------------------------------------------------------------------------------------------ Net cash provided by financing activities....................... 307,165 80,018 15,923 - ------------------------------------------------------------------------------------------------------------------------ Net change in cash and cash equivalents.............................. 94,101 (25,394) 9,169 Cash and cash equivalents at beginning of period..................... 11,301 36,695 27,526 - ------------------------------------------------------------------------------------------------------------------------ Cash and cash equivalents at end of period........................... $ 105,402 $ 11,301 $ 36,695 - ------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 33 14 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Energen Corporation 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Energen Corporation (the Company) is a diversified energy holding company engaged primarily in the purchase, distribution, and sale of natural gas, principally in central and north Alabama (natural gas distribution), and in the exploration, production, acquisition and development of oil and gas in the continental United States (oil and gas exploration and production). The following is a description of the Company's significant accounting policies and practices. A.PRINCIPLES OF CONSOLIDATION The accompanying financial statements include the accounts of the Company and its subsidiaries, principally Alabama Gas Corporation (Alagasco) and Taurus Exploration Inc. (Taurus), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years financial statements to the current-year presentation. B.NATURAL GAS DISTRIBUTION UTILITY PLANT AND DEPRECIATION: Property, plant and equipment is stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and, together with the cost of removal less salvage, is charged to the accumulated reserve for depreciation. Depreciation is provided on the straight-line method over the estimated useful lives of utility property at rates established by the Alabama Public Service Commission (APSC). Approved depreciation rates averaged approximately 4.4 percent in 1997 and 4.3 percent in 1996 and 1995. INVENTORIES: Inventories, which consist primarily of gas stored underground, are stated at average cost. OPERATING REVENUE AND GAS COSTS: In accordance with industry practice, Alagasco records natural gas distribution revenues on a monthly- and cycle-billing basis. The commodity cost of purchased gas applicable to gas delivered to customers but not yet billed under the cycle-billing method is deferred as a current asset. REGULATORY ACCOUNTING: Alagasco is subject to the provisions of Statement of Financial Accounting Standard (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. In general, SFAS No. 71 allows utilities to capitalize or defer certain costs or revenues, based upon orders received from regulatory authorities, to be recovered from or refunded to customers in future periods. C.OIL AND GAS EXPLORATION AND PRODUCTION PROPERTY AND RELATED DEPLETION: Taurus follows the successful efforts method of accounting for costs incurred in the exploration and development of oil and gas reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. All development costs are capitalized. Depreciation, depletion and amortization is determined on a field-by-field basis using the unit-of-production method based on proved reserves. A provision for anticipated abandonment and restoration costs at the end of a property's useful life is made through depreciation expense. OPERATING REVENUE: Taurus utilizes the sales method of accounting to recognize oil and gas production revenue. Under the sales method, revenue is recognized for the Company's total takes of oil and gas production, and overproduction liabilities are established only when it is estimated that a property's overproduced volumes exceed the net share of remaining reserves for such property. The Company has no significant production imbalances at September 30, 1997. Gains and losses on the sale of property in the ordinary course of business are classified as operating revenue. DERIVATIVE COMMODITY INSTRUMENTS: Taurus periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil and gas production. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange and over-the-counter swaps and basis hedges with major energy derivative product specialists. These transactions are accounted for under the hedge method of accounting. Under this method, any unrealized gains and losses are recorded as a current receivable/payable and a deferred gain/loss. Realized gains and losses are deferred until the revenues from the related hedged volumes are recognized in the income statement. These realized deferred gains and losses are reflected in current liabilities or current assets, respectively. Cash flows from derivative instruments are recognized as 34 15 incurred through changes in working capital. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. To apply the hedge method of accounting, management must demonstrate that a high correlation exists between the value of the derivative commodity instrument and the value of the item hedged. Management uses the historic relationships between the derivative instruments and the sales prices of the hedged volumes to ensure that a high level of correlation exists. D.INCOME TAXES The Company's deferred income taxes reflect the impact of temporary differences between the tax basis of assets and liabilities and their carrying amounts for financial reporting purposes. E.CASH EQUIVALENTS The Company includes highly liquid marketable securities and debt instruments purchased with a maturity of three months or less in cash equivalents. F.ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net revenues therefrom (see Note 13). 2. REGULATORY MATTERS As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which, in 1983, established the Rate Stabilization and Equalization (RSE) rate-setting process. RSE was extended with modifications in 1985, 1987 and 1990. On October 7, 1996, RSE was extended, without change, for a five-year period through January 1, 2002. Under the terms of that extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. Under RSE as extended, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and fiscal year-to-date performance, whether Alagasco's return on equity for the fiscal year will be within the allowed range of 13.15 percent to 13.65 percent. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each fiscal 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. If the change in O&M expense per customer falls within 1.25 percentage points above or below the Consumer Price Index For All Urban Customers (index range), no adjustment is required. If, however, 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. Under RSE as extended, a $1.3 million annual decrease in revenue became effective October 1, 1996, a $7.7 million annual increase became effective December 1, 1996, and a $1.5 million annual decrease became effective April 1, 1997. Alagasco calculates a temperature adjustment to customers' monthly bills to remove the effect of departures from normal temperature on Alagasco's earnings. The calculation is performed monthly, and the adjustments to customers bills are made in the same billing cycle the weather variation occurs. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply, including Gas Supply Realignment (GSR) surcharges imposed by Alagasco's suppliers resulting from changes in gas supply purchases related to the implementation of Federal Energy Regulatory Commission (FERC) Order 636. The APSC on October 7, 1996, issued an order providing for the refund to customers prior to January 31, 1997 of approximately $17 million of supplier refunds, including interest. The Company refunded these amounts to customers during January 1997. The refunds were collected from a variety of sources and most relate to the settlement of rate case and FERC Order 636 proceedings of Southern Natural Gas Company (Southern) as described herein. In accordance with APSC-directed regulatory accounting procedures, Alagasco in 1989 began returning to customers excess utility deferred taxes which resulted from a reduction in the federal statutory tax rate from 46 percent to 34 percent using the average rate assumption method. This method provides for the return to ratepayers of excess deferred taxes over the lives of the related assets. In 1993 those excess taxes were reduced as a result of a federal tax rate increase from 34 percent to 35 percent. Remaining excess utility deferred taxes of $2.1 million are being returned to ratepayers over approximately 13 years. At September 30, 1997 and 1996, a regulatory liability related to income taxes of $3.7 million and $5 million, respectively, was included in the consolidated financial statements. 35 16 The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized on a straight-line basis over approximately 23 years. At September 30, 1997 and 1996, the net acquisition adjustment was $16.4 million and $16.7 million, respectively. FERC REGULATION: In 1995 Southern filed a comprehensive settlement with the FERC in the form of a Stipulation and Agreement (the Settlement) to resolve all issues in Southern's six then-pending rate cases as well as to resolve all GSR and transition cost issues resulting from the implementation of FERC Order 636. Alagasco was a supporting party to the Settlement. The Settlement, as approved by the FERC, resolves all issues relating to GSR and other transition costs with respect to supporting parties. Alagasco estimates that it has a remaining GSR liability of approximately $0.1 million to be paid through December 1998 and approximately $0.7 million in other transition costs to be paid through June 1998. Because these costs will be recovered in full from its customers, Alagasco recorded a regulatory asset of $0.8 million and $2.2 million at September 30, 1997 and 1996, respectively. 3. LONG-TERM DEBT AND NOTES PAYABLE
Long-term debt consists of the following: - ------------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 - ------------------------------------------------------------------------------------------------------------------------- Energen Corporation: Medium-term Notes, interest ranging from 6.6% to 8.09%, for notes redeemable September 20, 2001, to July 28, 2027................. $ 125,000 $ 40,000 8% Debentures, due up to $1,000,000 annually to February 1, 2007 18,704 18,714 Series 1993 Notes, interest ranging from 5.6% to 7.25%, due annually in payments ranging from $855,000 to $1,584,000 from March 1, 1998, to March 1, 2008................................................ 12,753 13,636 Alabama Gas Corporation: Medium-term Notes, interest ranging from 5.4% to 7.97%, for notes redeemable December 1, 1998, to September 23, 2026................ 125,000 125,000 - ------------------------------------------------------------------------------------------------------------------------- Total................................................................ 281,457 197,350 Less amounts due within one year..................................... 1,855 1,805 - ------------------------------------------------------------------------------------------------------------------------- Total............................................................. $ 279,602 $ 195,545 - -------------------------------------------------------------------------------------------------------------------------
The aggregate maturities of long-term debt for the next five years are as follows:
- ------------------------------------------------------------------------------------------------------------------- Years ending September 30, (in thousands) - ------------------------------------------------------------------------------------------------------------------------- 1998 1999 2000 2001 2002 - ------------------------------------------------------------------------------------------------------------------------- $ 1,855 $ 7,209 $ 1,955 $ 18,648 $ 17,077 - -------------------------------------------------------------------------------------------------------------------------
The Company is subject to various restrictions on the payment of dividends. Under its 8 percent debentures, the most restrictive provision states that dividends or other distributions with respect to common stock may not be made unless the Company maintains a minimum consolidated tangible net worth of $80 million; at September 30, 1997, Energen had a tangible net worth of $300.9 million. Energen and Alagasco have short-term credit lines and other credit facilities of $203 million available to either entity for working capital needs. At September 30, 1997, the Company borrowed $50 million under separate agreement to purchase U.S. Treasury securities for Alabama shares tax planning purposes. The securities were pledged as collateral on the debt. In total, at year-end, the Company had $98.6 million of borrowings to purchase Treasury securities. The securities matured in early October and the proceeds were used to repay such borrowings. The following is a summary of information relating to notes payable to banks: 36 17
- ---------------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------- Amount outstanding................................... $ 152,000 $ 59,000 $ 32,300 Amount outstanding under separate agreement.......... 50,000 -- -- - --------------------------------------------------------------------------------------------------------------------------- Notes payable to banks............................... $ 202,000 $ 59,000 $ 32,300 Available for borrowings............................. 51,000 97,000 77,700 - --------------------------------------------------------------------------------------------------------------------------- Total............................................. $ 253,000 $ 156,000 $ 110,000 - --------------------------------------------------------------------------------------------------------------------------- Maximum amount outstanding at any month-end $ 202,000 $ 95,000 $ 32,300 Average daily amount outstanding..................... $ 87,648 $ 37,960 $ 917 Weighted average interest rates based on: Average daily amount outstanding.................. 5.87% 5.68% 5.76% Amount outstanding at year-end.................... 5.96% 5.62% 5.96% - ---------------------------------------------------------------------------------------------------------------------------
Total interest expense for Energen in 1997, 1996 and 1995 was $22,906,000, $13,920,000, and $11,693,000, respectively. 4. INCOME TAXES The components of income taxes consist of the following:
- ---------------------------------------------------------------------------------------------------------------------------- For the years ended September 30, (in thousands) 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------------------- Taxes estimated to be payable currently: Federal........................................... $ 4,976 $ 5,218 $ 5,377 State............................................. 1,254 989 873 - --------------------------------------------------------------------------------------------------------------------------- Total current................................... 6,230 6,207 6,250 - --------------------------------------------------------------------------------------------------------------------------- Taxes deferred: Federal........................................... (3,123) (1,221) (2,580) State............................................. (10) 62 11 - --------------------------------------------------------------------------------------------------------------------------- Total deferred.................................... (3,133) (1,159) (2,569) - --------------------------------------------------------------------------------------------------------------------------- Total income tax expense............................. $ 3,097 $ 5,048 $ 3,681 - ---------------------------------------------------------------------------------------------------------------------------
Temporary differences and carryforwards which give rise to a significant portion of deferred tax assets and liabilities for 1997 and 1996 are as follows:
- ---------------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 - ---------------------------------------------------------------------------------------------------------------------------- Current Noncurrent Current Noncurrent ------- ---------- ------- ---------- Deferred tax assets: Regulatory liabilities............................ $ -- $ 1,356 $ -- $ 1,872 Minimum tax credit................................ -- 20,541 -- 16,379 Insurance and accruals............................ 2,410 -- 2,487 -- Unbilled revenue.................................. 1,699 -- 1,658 -- Other, net........................................ 5,559 1,570 5,812 1,952 - --------------------------------------------------------------------------------------------------------------------------- Subtotal....................................... 9,668 23,467 9,957 20,203 Valuation allowance............................ -- -- -- -- - --------------------------------------------------------------------------------------------------------------------------- Total deferred tax assets.................... 9,668 23,467 9,957 20,203 - --------------------------------------------------------------------------------------------------------------------------- Deferred tax liabilities: Depreciation and basis differences................ -- 20,893 -- 20,187 Gas supply adjustment............................. 1,308 -- 500 -- Other, net........................................ 922 1,430 1,462 988 - --------------------------------------------------------------------------------------------------------------------------- Total deferred tax liabilities............... 2,230 22,323 1,962 21,175 - --------------------------------------------------------------------------------------------------------------------------- Net deferred tax assets (liabilities)................ $ 7,438 $ 1,144 $ 7,995 $ (972) - ---------------------------------------------------------------------------------------------------------------------------
No valuation allowance with respect to deferred taxes is deemed necessary as the Company anticipates generating adequate future taxable income to realize the benefits of all deferred tax assets on the consolidated balance sheet. As of September 30, 1997, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $20.5 million. 37 18 Total income tax expense differs from the amount which would be provided by applying the statutory federal income tax rate to earnings before taxes as illustrated below:
- ----------------------------------------------------------------------------------------------------------------------------- For the years ended September 30, (in thousands) 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------------------------- Income tax expense at statutory federal income tax rate $ 11,233 $ 9,306 $ 8,046 Increase (decrease) resulting from: Nonconventional fuels credits..................... (8,058) (4,221) (4,122) Deferred investment tax credits .................. (487) (487) (487) State income taxes, net of federal income tax benefit 813 681 625 Other, net........................................ (404) (231) (381) - ------------------------------------------------------------------------------------------------------------ --------------- Total income tax expense....................... $ 3,097 $ 5,048 $ 3,681 - ----------------------------------------------------------------------------------------------------------------------------
5. EMPLOYEE BENEFIT PLANS The Company has two defined benefit non-contributory pension plans which cover a majority of the employees. Benefits are based on years of service and final earnings. The Company's policy is to use the "projected unit credit" actuarial method for funding and financial reporting purposes. The expense for the plan covering the majority of employees (Plan A) for the years ended September 30, 1997, 1996 and 1995 was $1,228,000, $412,000, and $1,158,000, respectively. The expense for the second plan covering employees under certain labor union agreements (Plan B) for 1997, 1996 and 1995 was $437,000, $197,000, and $339,000, respectively. The funded status of the plans is as follows:
- ----------------------------------------------------------------------------------------------------------------------------- As of June 30, (in thousands) Plan A Plan B - ----------------------------------------------------------------------------------------------------------------------------- 1997 1996 1997 1996 ---- ---- ---- ---- Vested benefits...................................... $ (57,617) $ (56,828) $ (14,610) $ (14,210) Nonvested benefits................................... (4,739) (4,323) (2,256) (2,336) - --------------------------------------------------------------------------------------------------------------------------- Accumulated benefit obligation....................... (62,356) (61,151) (16,866) (16,546) Effects of salary progression........................ (11,402) (12,607) -- -- - --------------------------------------------------------------------------------------------------------------------------- Projected benefit obligation......................... (73,758) (73,758) (16,866) (16,546) Fair value of plan assets, primarily equity and fixed income securities........................... 84,859 80,750 20,820 18,358 Unrecognized net (gain) loss......................... (6,477) (337) (2,747) (433) Unrecognized prior service cost...................... 29 35 998 1,205 Unrecognized net transition obligation (asset)....... (3,494) (4,303) 282 340 - --------------------------------------------------------------------------------------------------------------------------- Accrued pension asset................................ $ 1,159 $ 2,387 $ 2,487 $ 2,924 - ---------------------------------------------------------------------------------------------------------------------------
At September 30, 1997 and 1996, for both plans the discount rate used to measure the projected benefit obligation was 7.75 percent, and the expected long-term rate of return on plan assets was 8.25 percent. The annual rate of salary increase for the salaried plan was 5.75 percent in both years. 38 19 The components of net pension expense for 1997, 1996 and 1995 were:
- ----------------------------------------------------------------------------------------------------------------------------- For the years ended September 30, (in thousands) Plan A Plan B - ----------------------------------------------------------------------------------------------------------------------------- 1997 1996 1995 1997 1996 1995 ---- ---- ---- ---- ---- ---- Service cost $ 2,227 $ 2,147 $ 2,052 $ 243 $ 255 $ 224 Interest cost on projected benefit obligation 5,524 4,617 4,728 1,238 1,166 1,095 Actual (return) on plan assets (12,629) (15,280) (8,787) (3,803) (2,971) (2,172) Net amortization and deferral 6,106 8,928 2,106 2,759 1,747 1,192 Loss due to special termination benefits -- -- 1,489 -- -- -- Settlement gain -- -- (430) -- -- -- - --------------------------------------------------------------------------------------------------------------------------- Net pension expense $ 1,228 $ 412 $ 1,158 $ 437 $ 197 $ 339 - ---------------------------------------------------------------------------------------------------------------------------
In 1995 the Company recognized a loss for special termination benefits of $1,489,000 and a settlement gain of $430,000 pursuant to a voluntary early retirement option offered to all salaried, non-officer employees of at least 58 years of age with a minimum of 5 years service. Of the 55 eligible employees, 41 accepted. The Company has deferred compensation plan agreements with certain key executives providing for payments on retirement, termination, death or disability. Expense under these agreements for 1997, 1996 and 1995 was $399,000, $1,002,000, and $808,000, respectively. At June 30, 1997 and 1996, the accumulated post-retirement benefit obligation related to these agreements was $5,961,000 and $6,206,000, respectively, and the projected benefit obligation was $9,839,000 and $9,442,000, respectively. A prepaid post-retirement benefit asset of $499,000 was recorded at June 30, 1997, and an accrued post-retirement benefit liability of $464,000 was recorded at June 30, 1996. In addition to providing pension benefits, the Company provides certain post-retirement health care and life insurance benefits. Substantially all of the Company's employees may become eligible for such benefits if they reach normal retirement age while working for the Company. While the Company has not adopted a formal funding policy, all of its accrued post-retirement liability was funded at year-end. The expense for salaried employees for the years ended September 30, 1997, 1996, and 1995 was $2,221,000, $1,984,000, and $2,271,000, respectively. The expense for union employees was $4,204,000, $4,076,000, and $3,613,000 during 1997, 1996 and 1995, respectively. The "projected unit credit" actuarial method was used to determine the normal cost and actuarial liability. A reconciliation of the estimated status of the obligation is as follows:
- ----------------------------------------------------------------------------------------------------------------------------- As of June 30, (in thousands) Salaried Employees Union Employees - ----------------------------------------------------------------------------------------------------------------------------- 1997 1996 1997 1996 ---- ---- ---- ---- Retirees............................................. $ (9,590) $ (10,344) $ (14,529) $ (14,982) Active, fully eligible............................... (2,121) (1,574) (4,340) (4,011) Other active......................................... (8,309) (7,989) (14,151) (14,415) - ------------------------------------------------------------------------------------------ --------------------------------- Accumulated post-retirement benefit obligation....... (20,020) (19,907) (33,020) (33,408) Fair value of plan assets, primarily equity and fixed income securities........................... 23,719 17,519 13,363 8,399 Unamortized amounts.................................. (4,686) 1,210 17,405 23,394 - ---------------------------------------------------------------------------------------------------------------------------- Accrued post-retirement benefit liability............ $ (987) $ (1,178) $ (2,252) $ (1,615) - ----------------------------------------------------------------------------------------------------------------------------
39 20 Net periodic post-retirement benefit expense for the years ended September 30, 1997, 1996, and 1995 included the following:
- ----------------------------------------------------------------------------------------------------------------------------- For the years ended September 30, (in thousands) Salaried Employees Union Employees - ----------------------------------------------------------------------------------------------------------------------------- 1997 1996 1995 1997 1996 1995 ---- ---- ---- ---- ---- ---- Service cost $ 979 $ 516 $ 512 $ 1,198 $ 876 $ 807 Interest cost on accumulated post-retirement benefit obligation 2,204 1,679 1,696 2,542 2,195 1,793 Amortization of transition obligation 723 723 723 1,285 1,285 1,285 Amortization of actuarial gains and losses (568) (277) -- -- -- -- Deferred asset (gain) loss 3,682 658 539 2,006 177 424 Actual (return) on plan assets (4,799) (1,315) (1,199) (2,827) (457) (696) - --------------------------------------------------------------------------------------------------------------------------- Net periodic post-retirement benefit expense $ 2,221 $ 1,984 $ 2,271 $ 4,204 $ 4,076 $ 3,613 - ---------------------------------------------------------------------------------------------------------------------------
The weighted average discount rate used in determining the accumulated post-retirement benefit obligation was 7.75 percent in 1997 and 1996. The expected long-term rate of return on assets is 8.25 percent for both years, and the tax rate on investment income is assumed to be 40 percent. The weighted average health care cost trend rate used in determining the accumulated post-retirement benefit obligation was 8.25 percent and 8 percent in 1997 and 1996, respectively. That assumption has a significant effect on the amounts reported. For example, with respect to salaried employees, increasing the weighted average health care cost trend rate by 1 percent would increase the accumulated post-retirement benefit obligation by 2.4 percent and the net periodic post-retirement benefit cost by 2.2 percent. For union employees, increasing the weighted average health care cost trend rate by 1 percent would increase the accumulated post-retirement benefit obligation by 7.5 percent and the net periodic post-retirement benefit cost by 7.2 percent. For pay-related life insurance benefits, the salary scale averages 5.75 percent and 5 percent in 1997 and 1996, respectively. For both defined benefit plans and other post-retirement plans, certain financial assumptions are used in determining the Company's projected benefit obligation. These assumptions are examined periodically by the Company and any required changes are reflected in the subsequent determination of projected benefit obligations. The Company has a long-term disability plan covering most salaried employees. Expense for the years ended September 30, 1997, 1996, and 1995 was $163,000, $370,000, and $155,000, respectively. 6. COMMON STOCK PLANS A majority of Company employees are eligible to participate in the Energen Employee Savings Plan (ESP) by investing a portion of their compensation in the Plan, with the Company matching a part of the employee investment by contributing Company common stock (new issue or treasury shares) or funds for the purchase of Company common stock. The ESP also contains employee stock ownership plan provisions. At September 30, 1997, 198,227 common shares were reserved for issuance under the ESP. Expense associated with Company contributions to the ESP was $3,083,000, $2,902,000, and $2,944,000 for 1997, 1996 and 1995, respectively. In 1992 the Company adopted the Energen Corporation 1992 Long-Range Performance Plan which provides for the award of up to 500,000 performance units, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined performance criteria at the end of a four-year award period. Under the Plan, a portion of the performance units is payable with Company common stock; accordingly, 350,000 shares have been reserved for issuance. Under the Plan, 60,330, 62,630, and 56,430 performance units were awarded in 1997, 1996 and 1995, respectively, leaving 188,395 performance units available for award at September 30, 1997. The Company recorded expense of $2,632,200, $1,223,000, and $1,628,000 for 1997,1996, and 1995, respectively, under the Plan. In 1996, the Company amended its Dividend Reinvestment and Common Stock Purchase Plan to include a direct stock purchase feature which allows purchases by non-shareholders. Accordingly, 750,000 shares were added to the Plan. As of September 30, 1997, 710,106 common shares were reserved under this Plan. 40 21 The Energen Corporation 1988 Stock Option Plan provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plan provide for purchase of the Company's common stock at not less than the fair market value on the date the option is granted. Under the Plan, 270,000 shares of the Company's common stock have been reserved for issuance. Options were granted in 1996 and 1995 with dividend equivalents. All outstanding options are non-qualified and expire 10 years from the date of grant. Transactions under the Plan are summarized as follows:
- --------------------------------------------------------------------------------------------------------- As of September 30, 1997 1996 1995 - --------------------------------------------------------------------------------------------------------- Outstanding at beginning of year ($16.75 - $22.125) 162,056 152,056 141,556 Granted (at $20.125 - $30)........................... 53,000 10,000 10,500 Exercised (at $18.375)............................... (3,500) -- -- - ------------------------------------------------------------------------------------------------------- Outstanding at year-end.............................. 211,556 162,056 152,056 - ------------------------------------------------------------------------------------------------------- Exercisable at year-end.............................. 211,556 162,056 152,056 - ------------------------------------------------------------------------------------------------------- Remaining reserved for issuance at year-end.......... 40,348 93,348 103,348 - -------------------------------------------------------------------------------------------------------
The Company has adopted the disclosure-only provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Accordingly, no compensation expense has been recognized for its nonqualified stock options. Had compensation cost for those options been determined in accordance with SFAS No. 123, the Company's net income and earnings per share would have been $28.9 million, or $2.30 per share, in 1997 and $21.5 million, or $1.95 per share, in 1996. In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan to enable the Company to pay part of the compensation of its non-employee directors in shares of the Company's common stock. Under the Plan, 3,062, 4,322, and 3,829 shares were issued in 1997, 1996 and 1995, respectively, leaving 82,210 shares reserved for issuance at September 30, 1997. The Company has adopted a Shareholder Rights Plan intended to protect shareholders from coercive or unfair takeover tactics. Under certain circumstances, shareholders have the right to acquire the Company's Series A Junior Participating Preferred Stock (or, in certain cases, securities of an acquiring person) at a significant discount. Terms and conditions are set forth in a Rights Agreement (dated July 27, 1988, and amended February 28, 1990) between the Company and its Rights Agent. Under the plan, two-thirds of a right is associated with each outstanding share of Common Stock. Rights outstanding under the Shareholder Rights Plan at September 30, 1997 and 1996, were convertible into 95,987 and 74,418 shares, respectively, of Series A Junior Participating Preferred Stock (1/100 share of preferred stock for each full right) subject to adjustment upon occurrence of certain take-over related events. No rights were exercised or exercisable at either period. The price at which the rights would be exercised is $80 per right, subject to adjustment upon occurrence of certain take-over related events. In general, absent certain takeover- related events as described in the Plan, the rights may be redeemed prior to the July 27, 1998, expiration for $0.02 per right. 7. COMMITMENTS AND CONTINGENCIES CONTRACTS AND AGREEMENTS: The Company has various firm gas supply and firm gas transportation contracts which expire at various dates through the year 2008. These contracts typically contain minimum demand charge obligations on the part of the Company. During 1996, Taurus entered into a sales contract providing for variable and fixed prices with a fixed price of $2.02 per Mcf for certain of its 1998 production. Taurus's net production of approximately 4 Bcf is subject to the fixed price. Taurus has an agreement with Sonat Exploration Company under which it has the option to acquire an interest in any properties purchased by that company under its reserve acquisition program. No significant Sonat joint venture acquisitions were made in fiscal 1997. The agreement will expire at the end of calendar year 1998. ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight former manufactured gas plant sites, of which it still owns four, and five manufactured gas distribution sites, of which it still owns one. A preliminary investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the results of operations or financial condition of Alagasco. Taurus is subject to various environmental regulations. Management believes that Taurus is in compliance with the currently applicable standards of the environmental agencies to which it is subject and that potential environmental liabilities, if any, are minimal. Also, to the extent Taurus has operating agreements with various joint venture partners, environmental costs, if any, would be shared proportionately. LEGAL MATTERS: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation 41 22 are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards bearing little or no relation to culpability or actual damages continue to rise making it increasingly difficult to predict litigation results. Various legal proceedings arising in the normal course of business are currently in progress and the Company has accrued a provision for estimated costs. LEASE OBLIGATIONS: Total payments related to leases included as operating expense were $3,987,000, $3,050,000, and $3,035,000 in 1997, 1996 and 1995, respectively. Minimum future rental payments (in thousands) required after 1997 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
- ----------------------------------------------------------------------------------------------------------------------------- 1998 1999 2000 2001 2002 2003 and thereafter - ----------------------------------------------------------------------------------------------------------------------------- $ 3,531 $ 1,567 $ 1,117 $ 672 $ 94 $ 25 - -----------------------------------------------------------------------------------------------------------------------------
8. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental information concerning cash flow activities is as follows:
- -------------------------------------------------------------------------------------------------------------- For the years ended September 30, (in thousands) 1997 1996 1995 - -------------------------------------------------------------------------------------------------------------- Interest paid........................................ $ 18,385 $ 13,261 $ 13,994 Income taxes paid.................................... $ 6,308 $ 5,486 $ 6,234 Noncash investing activities Capitalized depreciation.......................... $ 168 $ 166 $ 166 Allowance for funds used during construction...... $ 490 $ 972 $ 1,054 Noncash financing activities (debt issuance costs) $ 585 $ 414 $ 340 - --------------------------------------------------------------------------------------------------------------
9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT FINANCIAL INSTRUMENTS: The fair value of cash and cash equivalents, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of fixed-rate long-term debt, including the current portion, with a carrying value of $281,457,000, would be $287,121,000 at September 30, 1997. The fair value was based on the market value of debt with similar maturities and with interest rates currently trading in the marketplace. The Company has entered into an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $20 million. During 1997, 1996 and 1995 , the Company sold $7,926,000, $8,831,000 and $8,454,000 , respectively, of installment receivables. At September 30, 1997 and 1996, the balance of these installment receivables was $17,160,000 and $16,964,000, respectively. Receivables sold under this agreement are considered financial instruments with off-balance sheet risk. The Company's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. PRICE RISK: Taurus periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil and gas production. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange and over-the-counter swaps and basis hedges with major energy derivative product specialists. These transactions are accounted for under the hedge method of accounting. Under this method, any unrealized gains and losses are recorded as a current receivable/payable and a deferred gain/loss. Realized gains and losses are deferred until the revenues from the related hedged volumes are recognized in the income statement. These realized deferred gains and losses are reflected in current liabilities or current assets, respectively. Cash flows from derivative instruments are recognized as incurred through changes in working capital. At September 30, 1997, the Company had deferred losses on the balance sheet of $12.9 million. At September 30, 1997, Taurus has entered into contracts and swaps for 36.3 Bcf of its 1998 flowing gas production at an average contract price of $2.26 per Mcf and 453 MBbl of its oil production at an average contract price of $20.29 per barrel. The program has been extended into fiscal year 1999 with contracts and swaps in place for 5.7 Bcf of flowing gas production primarily in the spring and summer months at an average contract price of $2.16 per Mcf. Realized prices are anticipated to be lower than hedged prices due to basis difference and other factors. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. To apply the hedge method of accounting, management must demonstrate that a high correlation exists between the value of the derivative commodity instrument and the value of the item hedged. Management uses the historic relationships between 42 23 the derivative instruments and the sales prices of the hedged volumes to ensure that a high level of correlation exists. CONCENTRATION OF CREDIT RISK: Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to more than 465,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure. Revenues and related accounts receivable from exploration and production operations are generated primarily from the sale of produced natural gas and oil. This industry concentration has the potential to impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry, or other conditions. The Company is not aware of any significant credit risks which have not been recognized in the provision for doubtful accounts. 10. ACCOUNTING FOR LONG-LIVED ASSETS During fiscal year 1997, the Company adopted SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. The Statement requires that an impairment loss be recognized when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flow of the asset. The Statement also provides that all long-lived assets to be disposed of be reported at the lower of the carrying amount or fair value. Accordingly, during the fourth quarter of 1997, the Company recorded a pre-tax write down of $2.1 million on certain oil and gas properties that are being held for sale. The properties have 9.7 Bcf of proved undeveloped reserves. The expense was recorded as additional depreciation, depletion and amortization. 11. RECENT PRONOUNCEMENTS OF THE FASB In fiscal 1997, the Company adopted SFAS No. 123, Accounting for Stock-Based Compensation, which establishes a fair value-based method of accounting for employee stock options. The Statement allows companies to continue to follow the accounting treatment prescribed by APB Opinion 25 with proper disclosure. The Company has adopted the disclosure-only provisions of SFAS 123 (see Note 6). In 1997, the Company adopted SFAS No. 125, Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities, which provides accounting and reporting standards for such transactions. The adoption did not have a material impact on the consolidated financial statements. In February 1997, the FASB issued SFAS No. 128, Earnings Per Share, which specifies computation, presentation, and disclosure requirements for EPS, and SFAS No. 129, Disclosures of Information about Capital Structure, which establishes standards for disclosing information about an entity's capital structure. The Company is required to adopt these Statements in its 1998 fiscal year. In June 1997, the FASB issued SFAS No. 130, Reporting Comprehensive Income, which requires the reporting and display of comprehensive income and its components in an entity's financial statements, and SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, which specifies revised guidelines for determining an entity's operating segments and the type and level of financial information to be required. The Company is required to adopt these Statements in fiscal year 1999. The impact of these pronouncements on the Company is currently being evaluated. 43 24 12. SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited) The following data summarize quarterly operating results. The Company's business is seasonal in character and strongly influenced by weather conditions.
- ----------------------------------------------------------------------------------------------------------------------------- 1997 Fiscal Quarters (In thousands, except per share amounts) First Second Third Fourth - ----------------------------------------------------------------------------------------------------------------------------- Operating revenues................................... $ 97,002 $ 182,942 $ 90,879 $ 77,407 Operating income (loss).............................. $ 7,955 $ 41,598 $ 8,244 $ (5,811) Net income (loss).................................... $ 3,177 $ 30,531 $ 3,007 $ (7,718) Earnings (loss) per average common share............. $ 0.28 $ 2.41 $ 0.23 $ (0.58) - --------------------------------------------------------------------------------------------------------------------------- 1996 Fiscal Quarters First Second Third Fourth - ----------------------------------------------------------------------------------------------------------------------------- Operating revenues................................... $ 78,823 $ 170,987 $ 87,130 $ 62,502 Operating income (loss).............................. $ 4,773 $ 33,643 $ 4,011 $ (3,630) Net income (loss).................................... $ 2,278 $ 23,430 $ 1,071 $ (5,238) Earnings (loss) per average common share............. $ 0.21 $ 2.13 $ 0.10 $ (0.47) - ---------------------------------------------------------------------------------------------------------------------------
13. OIL AND GAS PRODUCING ACTIVITIES (Unaudited) The following schedules detail historical financial data of the Company's oil and gas producing activities. Certain terms appearing in the schedules are prescribed by the Securities and Exchange Commission (SEC) and are briefly described as follows: LEASE ACQUISITION COSTS are costs incurred to lease or otherwise acquire a property. EXPLORATION EXPENSES are primarily costs associated with drilling unsuccessful exploratory wells in undeveloped properties, exploratory geological and geophysical activities, and costs of impaired leaseholds. DEVELOPMENT COSTS include costs necessary to gain access to, prepare and equip development wells in areas of proved reserves. PRODUCTION (LIFTING) COSTS include costs incurred to operate and maintain wells. GROSS REVENUES are reported after deduction of royalty interest payments. GROSS WELL OR ACRE is a well or acre in which a working interest is owned. NET WELL OR ACRE is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. DRY WELL is an exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. PRODUCTIVE WELL is an exploratory or a development well that is not a dry well. CAPITALIZED COSTS
- ------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------- Proved............................................... $ 432,095 $ 222,428 $ 115,720 Unproved............................................. 22,115 2,041 1,619 - ------------------------------------------------------------------------------------------------------------- Total capitalized costs........................... 454,210 224,469 117,339 Accumulated depreciation, depletion and amortization 87,554 60,152 51,170 - ------------------------------------------------------------------------------------------------------------- Capitalized costs, net............................... $ 366,656 $ 164,317 $ 66,169 - -------------------------------------------------------------------------------------------------------------
44 25 COSTS INCURRED The following table sets forth costs incurred in property acquisition and exploration and development activities and includes both capitalized costs and costs charged to expense during the year:
- ----------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 1995 - ----------------------------------------------------------------------------------------------- Property acquisition: Proved............................................ $ 171,701 $ 108,315 $ 16,950 Unproved.......................................... 22,028 1,693 989 Exploration.......................................... 14,847 11,124 4,666 Development.......................................... 36,375 10,040 6,044 - ----------------------------------------------------------------------------------------------- Total costs incurred................................. $ 244,951 $ 131,172 $ 28,649 - -----------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS The following table sets forth results of the Company's oil and gas producing activities:
- ------------------------------------------------------------------------------------------------ Years ended September 30, (in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------ Gross revenues....................................... $ 84,366 $ 38,421 $ 22,656 Production (lifting) costs........................... 25,486 10,573 5,995 Exploration expense.................................. 6,636 5,439 2,933 Depreciation, depletion and amortization*............ 35,393 18,583 8,847 Income tax benefit................................... (2,299) (3,004) (2,410) - ------------------------------------------------------------------------------------------------ Results of operations from producing activities...... $ 19,150 $ 6,830 $ 7,291 - ------------------------------------------------------------------------------------------------
* Includes a write down in 1997 of $2.1 million under SFAS 121 (see Note 10) AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE
- ---------------------------------------------------------------------------------------------- Years ended September 30, 1997 1996 1995 - ---------------------------------------------------------------------------------------------- Average sales price: Gas (per Mcf)..................................... $ 2.05 $ 1.97 $ 1.72 Oil (per barrel).................................. $ 18.08 $ 16.25 $ 15.07 Natural gas liquids (per barrel).................. $ 11.45 $ -- $ -- Average production (lifting) cost (per Mcf equivalent) $ 0.69 $ 0.66 $ 0.59 Average depreciation rate (per Mcf equivalent)....... $ 0.90 $ 1.15 $ 0.88 - --------------------------------------------------------------------------------------------
DRILLING ACTIVITY The following table sets forth the total number of net productive and dry exploratory and development wells drilled:
- ----------------------------------------------------------------------------------------- Years ended September 30, 1997 1996 1995 - ----------------------------------------------------------------------------------------- Exploratory: Productive........................................ 1.6 1.1 0.9 Dry............................................... 1.2 1.5 1.0 - ----------------------------------------------------------------------------------------- Total............................................. 2.8 2.6 1.9 - ----------------------------------------------------------------------------------------- Development: Productive........................................ 17.7 2.4 1.0 Dry............................................... 0.7 -- 0.1 - ----------------------------------------------------------------------------------------- Total............................................. 18.4 2.4 1.1 - -----------------------------------------------------------------------------------------
As of September 30, 1997, the Company was participating in the drilling of 7 gross wells, with the Company's interest equivalent to 1.3 wells. 45 26 PRODUCTIVE WELLS AND ACREAGE The following table sets forth the total gross and net productive gas and oil wells as of September 30, 1997, and developed and undeveloped acreage as of the latest practicable date prior to year-end:
- ------------------------------------------------------------------------------------- Gross Net - ------------------------------------------------------------------------------------- Gas Wells............................................ 3,376 1,575 Oil Wells............................................ 1,589 199 - ------------------------------------------------------------------------------------- Developed Acreage.................................... 946,850 559,566 Undeveloped Acreage.................................. 354,110 34,013 - -------------------------------------------------------------------------------------
All wells and acreage are located in the United States, onshore and offshore, with the majority of the net undeveloped acreage located in the Gulf Coast region. OIL AND GAS PRODUCING ACTIVITIES The calculation of proved reserves are made pursuant to rules prescribed by the SEC. Such rules, in part, require that only proved categories of reserves be disclosed and that reserves and associated values be calculated using current prices and costs. Changes to current prices and costs might have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is learned. Accordingly, the amount of actual future production may vary significantly from the amount of reserves disclosed. See Note 9 for pricing information regarding the hedging activities of the Company. Prior to 1997, natural gas liquid quantities were insignificant and were included in oil quantities. The proved reserves are located in the United States, both onshore and offshore, and are as follows:
- ----------------------------------------------------------------------------------------------------------------------------- Years ended September 30, 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------------------------- Gas Oil NGL Gas Oil Gas Oil MMcf MBbl MBbl MMcf MBbl MMcf MBbl ---- ---- ---- ---- ---- ---- ---- Proved reserves at beginning of year 212,977 6,315 -- 71,267 3,986 60,057 1,485 Revisions of previous estimates (2,910) (110) -- 502 369 (1,462) 142 Purchase of minerals in place 352,373 3,650 12,880 155,647 3,805 11,919 2,472 Discoveries and other additions 11,946 83 -- 5,113 49 9,350 137 Production (29,318) (775) (502) (12,308) (635) (8,597) (250) Sales of minerals in place (785) (35) -- (7,244) (1,259) -- -- - -------------------------------------------------------------------------------------------------------------------------- Proved reserves at end of year 544,283 9,128 12,378 212,977 6,315 71,267 3,986 - -------------------------------------------------------------------------------------------------------------------------- Proved developed reserves at end of year 511,864 8,140 12,378 175,124 5,012 50,657 3,380 - --------------------------------------------------------------------------------------------------------------------------
During the year, Taurus invested $172 million in property acquisitions and added 452 Bcfe of proved reserves. Additional development expenditures are required. Also, Taurus sold approximately 1 Bcfe and recorded a pre-tax gain of $1 million. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company's crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
- ----------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------------------------- Future gross revenues................................ $ 1,553,333 $ 502,607 $ 156,367 Future production costs.............................. 571,732 216,755 63,311 Future development costs............................. 74,396 40,665 19,029 - --------------------------------------------------------------------------------------------------------------------------- Future net cash flows before income taxes............ 907,205 245,187 74,027 Future income tax expense (benefit) including tax credits 162,172 3,707 (10,533) - --------------------------------------------------------------------------------------------------------------------------- Future net cash flows after income taxes............. 745,033 241,480 84,560 Discount at 10% per annum............................ 305,679 70,641 21,001 - --------------------------------------------------------------------------------------------------------------------------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves.............. $ 439,354 $ 170,839 $ 63,559 - ---------------------------------------------------------------------------------------------------------------------------
The following are the principal sources of changes in the standardized measure of discounted future net cash flows: 46 27
- ----------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (in thousands) 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------------------------- Balance at beginning of year......................... $ 170,839 $ 63,559 $ 51,654 - ----------------------------------------------------------------------------------------------------------------------------- Revisions to reserves proved in prior years: Net changes in prices, production costs and future development costs................................. 44,913 15,051 (1,984) Net changes due to revisions in quantity estimates (7,378) 552 (2,474) Development costs incurred, previously estimated 16,743 6,713 3,207 Accretion of discount............................. 17,084 6,356 5,166 Other............................................. (1,599) 1,215 (37) - ---------------------------------------------------------------------------------------------------------------------------- Total Revisions...................................... 69,763 29,887 3,878 New field discoveries and extensions, net of future production and development costs.................. 8,947 4,705 6,021 Sales of oil and gas produced, net of production costs (53,848) (24,002) (12,518) Purchases of minerals in place....................... 259,918 94,728 13,894 Sales of minerals in place........................... (625) (10,597) -- Net change in income taxes........................... (15,640) 12,559 630 - ---------------------------------------------------------------------------------------------------------------------------- Net change in standardized measure of discounted future net cash flows.................................... 268,515 107,280 11,905 - ---------------------------------------------------------------------------------------------------------------------------- Balance at end of year............................... $ 439,354 $ 170,839 $ 63,559 - ----------------------------------------------------------------------------------------------------------------------------
COALBED METHANE ACTIVITIES Taurus is actively engaged in the production of pipeline-quality natural gas from coal (coalbed methane). The results of coalbed methane activities have been included in the oil and gas disclosures shown previously. Because of the significance of coalbed methane to Taurus, certain data are separately disclosed below.
- ----------------------------------------------------------------------------------------------------------------------------- Years ended September 30, 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------------------------- Proved reserves at beginning of year (MMcf).......... 130,387 25,004 26,712 Revisions of previous estimates...................... 1,959 4,231 1,842 Purchases of minerals in place....................... 107,228 105,762 -- Discoveries and other additions...................... -- -- 159 Production........................................... (9,251) (4,610) (3,709) - -------------------------------------------------------------------------------------------------------------------------- Proved reserves at end of year....................... 230,323 130,387 25,004 - -------------------------------------------------------------------------------------------------------------------------- Estimated proved reserves qualifying for tax credits (MMcf) 55,776 30,142 15,837 - -------------------------------------------------------------------------------------------------------------------------- Net capitalized costs (in thousands)................. $ 145,686 $ 77,708 $ 19,370 - -------------------------------------------------------------------------------------------------------------------------- Gross wells in which Taurus has working and/or revenue interest 863 825 634 - -------------------------------------------------------------------------------------------------------------------------- Net productive wells................................. 548.4 279.1 154.4 - --------------------------------------------------------------------------------------------------------------------------
Production of coalbed methane from wells drilled prior to January 1, 1993, qualifies through December 31, 2002, for federal income tax credits under Section 29 of the Internal Revenue Code of 1986, as amended. The tax credit currently approximates $1.05 per Mcf of qualifying production. Accordingly, a significant portion of the value of proved coalbed methane reserves is associated with this tax credit. 47 28 14. SUPPLEMENTAL FULL COST ACCOUNTING INFORMATION (UNAUDITED) There are two methods of financial accounting for oil and gas exploration and production activities-successful efforts and full cost. As described in Note 1, the Company uses the successful efforts method which is preferred by the Financial Accounting Standards Board and is the more conservative method for companies engaging in exploration activities. However, the full cost method continues to be used by many companies with exploration activities including a number of the Company's peers. In response to requests from the investment community, the Company is providing the following supplemental proforma full cost information to facilitate making comparisons between the Company and its full cost peers. The supplemental information is not audited and includes certain assumptions, described in the following paragraphs, which should be read in conjunction with the information contained in the table below. Under the full cost method of accounting, all costs directly incurred in the acquisition, exploration, and development of oil and gas properties are capitalized. Such capitalized costs are amortized on a unit-of-production method based on total proved reserves. The unamortized costs (net of related deferred income taxes) are subject to a ceiling test in which the excess, if any, of the amount of the cost center over the value of the ceiling is charged against income. The cost center ceiling s defined as 1) the present value (10% discount rate) of estimated future net revenues from proved reserves with such net revenues based on current prices and current costs, plus 2) the cost of properties not currently being amortized, minus 3) the income tax effects related to the difference between items 1 and 2 and the tax basis of the related assets. Because of the ceiling test, full cost entities are not subject to the impairment test provisions of SFAS 121 (see Note 10). The SEC has an informal interpretation that the full cost ceiling test is to be applied quarterly. Information required to perform such tests as of the end of the interim periods was unavailable. In the proforma full cost disclosure below, therefore, the full cost ceiling test was applied on an annual basis. The Company's oil and gas properties include large amounts of coalbed methane reserves, a significant portion of the value of which are derived from nonconventional fuels tax credits (see Note 13). Under SFAS 109, Accounting for Income Taxes, the full amount of historical tax credits and other tax benefits has been recognized in the financial statements as it is "more likely than not" that such benefits will reduce future income taxes. Even though the Company expects that future tax benefits will continue as assets under the "more likely than not" criteria of SFAS 109, the full cost ceiling test, which was developed prior to the issuance of SFAS 109, limits the utilization of future tax benefits. Therefore, the full cost method would have required write downs pursuant to the ceiling test rules in some years that otherwise would have been avoided if the ceiling test rules were consistent with the financial statement treatment of such tax benefits. Accordingly, the Company is responding to the requests of certain users of the financial statements by also disclosing supplemental information referred to as Modified Full Cost to reflect the proforma inclusion of the value of tax benefits in the full cost ceiling test. This presentation will provide comparable results to full cost peers while also giving value to tax attributes of coalbed methane consistent with the treatment such attributes receive in the basic financial statements prepared under generally accepted accounting principles. In the following proforma Modified Full Cost disclosure, the ceiling test was applied on an annual basis, as described above, and tax credits were discounted using a 10% discount rate on an as-produced basis.
- --------------------------------------------------------------------------------------------------------------------------------- (in thousands, except share data) 1997 1996 1995 - --------------------------------------------------------------------------------------------------------------------------------- Full Modified Full Modified Full Modified Successful Cost Full Cost Successful Cost Full Cost Successful Cost Full Cost Efforts (proforma) (proforma) Efforts (proforma) (proforma) Efforts (proforma) (proforma) - --------------------------------------------------------------------------------------------------------------------------------- Income Statement: Net income $ 28,997 $ 42,531 $ 41,217 $ 21,541 $ 17,909 $ 25,971 $ 19,308 $ 14,554 $ 14,460 Earnings per share 2.31 3.39 3.28 1.95 1.62 2.36 1.77 1.33 1.33 Depreciation, depletion and amortization 57,628 42,142 44,164 41,118 34,230 35,787 29,556 27,724 30,211 Impairment under SFAS 121 2,060 -- -- -- -- -- -- -- -- Full cost write down -- -- -- -- 13,961 -- -- 12,079 9,736 Balance Sheet: Oil and gas properties, net 366,656 352,532 388,710 164,317 129,169 167,370 66,169 36,644 62,441 Shareholders equity 301,143 314,677 313,363 188,405 184,773 192,835 173,924 169,170 169,076 - ---------------------------------------------------------------------------------------------------------------------------------
48 29 15. INDUSTRY SEGMENT INFORMATION The Company is principally engaged in the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution) and the exploration, production, acquisition and development of oil and gas in the continental United States (oil and gas exploration and production). Certain reclassifications have been made to conform the prior year to the current year presentation.
- ----------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------- Operating revenues Natural gas distribution.......................... $ 362,984 $ 357,252 $ 295,967 Oil and gas exploration and production............ 85,246 42,190 22,613 - ----------------------------------------------------------------------------------------------------------- Total........................................... $ 448,230 $ 399,442 $ 318,580 - ----------------------------------------------------------------------------------------------------------- Operating income (loss) Natural gas distribution.......................... $ 38,792 $ 35,270 $ 32,513 Oil and gas exploration and production............ 14,704 4,779 719 Eliminations and corporate expenses............... (1,510) (1,252) (1,199) - ----------------------------------------------------------------------------------------------------------- Total........................................... $ 51,986 $ 38,797 $ 32,033 - ----------------------------------------------------------------------------------------------------------- Depreciation, depletion and amortization expense Natural gas distribution.......................... $ 23,486 $ 21,269 $ 19,370 Oil and gas exploration and production............ 36,202 19,849 10,186 - ----------------------------------------------------------------------------------------------------------- Total........................................... $ 59,688 $ 41,118 $ 29,556 - ----------------------------------------------------------------------------------------------------------- Capital expenditures Natural gas distribution.......................... $ 43,277 $ 43,175 $ 42,780 Oil and gas exploration and production............ 239,718 126,317 27,352 Other............................................. 15 60 28 - ----------------------------------------------------------------------------------------------------------- Total........................................... $ 283,010 $ 169,552 $ 70,160 - ----------------------------------------------------------------------------------------------------------- Identifiable assets Natural gas distribution.......................... $ 390,381 $ 373,817 $ 335,267 Oil and gas exploration and production............ 440,158 217,700 132,720 Eliminations and other............................ 89,258 (22,107) (8,903) - ----------------------------------------------------------------------------------------------------------- Total............................................. $ 919,797 $ 569,410 $ 459,084 - ----------------------------------------------------------------------------------------------------------- Property, plant and equipment, net Natural gas distribution.......................... $ 296,228 $ 276,927 $ 256,638 Oil and gas exploration and production............ 370,677 167,859 70,518 Other............................................. 98 130 108 - ----------------------------------------------------------------------------------------------------------- Total............................................. $ 667,003 $ 444,916 $ 327,264 - -----------------------------------------------------------------------------------------------------------
49 30 MANAGEMENTS RESPONSIBILITY FOR FINANCIAL REPORTING The accompanying consolidated financial statements and related notes of Energen Corporation were prepared by management, which has the primary responsibility for the integrity of the financial information therein. The statements were prepared in conformity with generally accepted accounting principles appropriate in the circumstances and include amounts which are based necessarily on managements best estimates and judgments. Financial information presented elsewhere in this report is consistent with the information in the financial statements. Management maintains a comprehensive system of internal accounting controls and relies on the system to discharge its responsibility for the integrity of the financial statements. This system provides reasonable assurance that corporate assets are safeguarded and that transactions are recorded in such a manner as to permit the preparation of reliable financial information. Reasonable assurance recognizes that the cost of a system of internal accounting controls should not exceed the related benefits. This system of internal accounting controls is augmented by written policies and procedures, internal auditing, and the careful selection and training of qualified personnel. As of September 30, 1997, management was aware of no material weaknesses in Energen's system of internal accounting controls. The consolidated financial statements have been audited by the Company's independent certified public accountants, whose opinion is expressed elsewhere on this page. Their audit was conducted in accordance with generally accepted auditing standards; and, in connection therewith, they obtained an understanding of the Company's system of internal accounting controls and conducted such tests and related procedures as they deemed necessary to arrive at an opinion on the fairness of presentation of the consolidated financial statements. The functioning of the accounting system and related internal accounting controls is under the general oversight of the Audit Committee of the Board of Directors, which is comprised of four outside Directors. The Audit Committee meets regularly with the independent public accountants and representatives of management to discuss matters regarding internal accounting controls, auditing and financial reporting. Geoffrey C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS To the Shareholders of Energen: We have audited the accompanying consolidated balance sheets of Energen Corporation and Subsidiaries as of September 30, 1997 and 1996, and the related consolidated statements of income, shareholders equity and cash flows for each of the three years in the period ended September 30, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energen Corporation and Subsidiaries as of September 30, 1997 and 1996, and the consolidated results of their operations and cash flows for each of the three years in the period ended September 30, 1997, in conformity with generally accepted accounting principles. Coopers & Lybrand L.L.P. Birmingham, Alabama October 23, 1997 50 31 SELECTED FINANCIAL AND COMMON STOCK DATA
Energen Corporation - ----------------------------------------------------------------------------------------------------------------------------- Years ended September 30, (dollars in thousands, except per share amounts) 1997 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------------- INCOME STATEMENT Operating revenues................................... $ 448,230 $ 399,442 $ 318,580 $ 374,503 Income before cumulative effect of change in accounting principle........................... $ 28,997 $ 21,541 $ 19,308 $ 23,751 Net income........................................... $ 28,997 $ 21,541 $ 19,308 $ 23,751 Earnings per share before cumulative effect.......... $ 2.31 $ 1.95 $ 1.77 $ 2.19 Earnings per average common share.................... $ 2.31 $ 1.95 $ 1.77 $ 2.19 - ----------------------------------------------------------------------------------------------------------------------------- BALANCE SHEET Capitalization at year-end: Common shareholders equity........................ $ 301,143 $ 188,405 $ 173,924 $ 167,026 Preferred stock................................... -- -- -- -- Long-term debt.................................... 279,602 195,545 131,600 118,302 - ----------------------------------------------------------------------------------------------------------------------------- Total capitalization.............................. $ 580,745 $ 383,950 $ 305,524 $ 285,328 - ----------------------------------------------------------------------------------------------------------------------------- Total assets......................................... $ 919,797 $ 569,410 $ 459,084 $ 411,314 - ----------------------------------------------------------------------------------------------------------------------------- Property, plant and equipment, net................... $ 667,003 $ 444,916 $ 327,264 $ 287,182 - ----------------------------------------------------------------------------------------------------------------------------- COMMON STOCK DATA Annual dividend rate at year-end..................... $ 1.24 $ 1.20 $ 1.16 $ 1.12 Cash dividends paid per common share................. $ 1.21 $ 1.17 $ 1.13 $ 1.09 Book value per common share.......................... $ 20.92 $ 16.88 $ 15.94 $ 15.30 Market-to-book ratio at year-end (%)................. 170 142 136 147 Yield at year-end (%)................................ 3.5 5.0 5.3 5.0 Return on average common equity (%).................. 11.9 11.6 11.0 14.6 Price-to-earnings ratio at year-end.................. 15.40 12.3 12.3 10.3 Shares outstanding at year-end (000)................. 14,398 11,163 10,910 10,918 Price Range: High.............................................. $ 37 3/4 $ 25 3/8 $ 23 1/2 $ 26 5/8 Low............................................... $ 23 3/4 $ 21 3/8 $ 19 3/4 $ 19 1/4 Close............................................. $ 35 9/16 $ 24 $ 21 3/4 $ 22 1/2 - -----------------------------------------------------------------------------------------------------------------------------
Note: All information prior to 1989 has been adjusted for the effects of a three-for-two common stock split. All information prior to 1990 includes the effects of discontinued operations. 32
- ------------------------------------------------------------------------------------------------------------- 1993 1992 1991 1990 1989 1988 1987 - ------------------------------------------------------------------------------------------------------------- $355,878 $331,065 $324,902 $324,022 $308,604 $353,135 $ 332,590 $ 18,081 $ 15,687 $ 14,112 $ 11,267 $ 6,422 $ 11,667 $ 8,950 $ 18,081 $ 16,628 $ 14,112 $ 11,267 $ 6,422 $ 11,667 $ 8,950 $ 1.77 $ 1.54 $ 1.42 $ 1.15 $ .69 $ 1.53 $ 1.38 $ 1.77 $ 1.64 $ 1.42 $ 1.15 $ .69 $ 1.53 $ 1.38 - ------------------------------------------------------------------------------------------------------------- $140,313 $129,858 $121,995 $113,316 $107,950 $ 86,256 $ 63,687 1,800 1,800 1,800 2,450 2,450 2,850 85,852 90,609 77,677 82,835 86,188 53,203 54,589 - ------------------------------------------------------------------------------------------------------------- $226,165 $222,267 $201,472 $197,951 $196,588 $141,909 $ 121,126 - ------------------------------------------------------------------------------------------------------------- $370,685 $342,119 $337,516 $326,350 $294,614 $260,560 $ 237,445 - ------------------------------------------------------------------------------------------------------------- $273,097 $254,630 $273,539 $250,983 $238,329 $206,230 $ 191,099 - ------------------------------------------------------------------------------------------------------------- $ 1.08 $ 1.04 $ 1.00 $ .94 $ .88 $ .827 $ .76 $ 1.05 $ 1.01 $ .955 $ .895 $ .843 $ .777 $ .73 $ 13.60 $ 12.75 $ 12.07 $ 11.48 $ 11.13 $ 10.80 $ 9.73 182 142 150 157 190 147 163 4.4 5.7 5.5 5.2 4.2 5.2 4.8 13.0 13.0 11.6 10.0 6.0 15.6 14.7 14.0 11.1 12.8 15.7 30.6 10.4 11.5 10,320 10,183 10,104 9,872 9,695 7,989 6,544 $ 26 3/4 $ 18 7/8 $ 20 $ 21 1/2 $ 24 3/8 $ 16 1/4 $ 16 1/2 $ 17 5/8 $ 15 $ 16 $ 16 $ 15 3/8 $ 11 3/8 $ 12 1/2 $ 24 3/4 $ 18 1/8 $ 18 1/8 $ 18 $ 21 1/8 $ 15 3/8 $ 15 7/8 - -------------------------------------------------------------------------------------------------------------
33 SELECTED BUSINESS SEGMENT DATA
Energen Corporation - ----------------------------------------------------------------------------------------------------------------------------- Years ended September 30, ( dollars in thousands) 1997 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------------- NATURAL GAS DISTRIBUTION Operating revenues Residential....................................... $ 237,022 $ 236,583 $ 194,089 $ 229,019 Commercial and industrialsmall.................... 87,477 87,912 68,409 84,443 Commercial and industriallarge.................... -- -- 290 790 Transportation.................................... 33,080 30,408 30,490 29,321 Other............................................. 5,405 2,349 2,687 1,064 - ----------------------------------------------------------------------------------------------------------------------------- Total........................................... $ 362,984 $ 357,252 $ 295,965 $ 344,637 - ----------------------------------------------------------------------------------------------------------------------------- Gas delivery volumes Residential....................................... 28,357 34,963 27,489 31,254 Commercial and industrialsmall.................... 12,554 15,002 12,289 13,536 Commercial and industriallarge.................... -- -- 29 106 Transportation.................................... 65,622 61,458 61,640 52,635 - ----------------------------------------------------------------------------------------------------------------------------- Total........................................... 106,533 111,423 101,447 97,531 - ----------------------------------------------------------------------------------------------------------------------------- Average number of customers Residential....................................... 422,878 418,486 410,515 402,531 Commercial and industrialsmall.................... 34,430 34,028 33,115 32,563 Commercial and industriallarge.................... 55 54 48 43 - ----------------------------------------------------------------------------------------------------------------------------- Total........................................... 457,363 452,568 443,678 435,137 - ----------------------------------------------------------------------------------------------------------------------------- Other data Depreciation & amortization....................... $ 23,486 $ 21,269 $ 19,368 $ 17,941 Capital expenditures.............................. $ 43,277 $ 43,175 $ 42,780 $ 38,473 Operating income.................................. $ 38,792 $ 35,270 $ 32,513 $ 30,017 - ----------------------------------------------------------------------------------------------------------------------------- OIL AND GAS EXPLORATION & PRODUCTION Operating revenues Natural gas....................................... $ 60,228 $ 24,262 $ 14,748 $ 17,292 Oil............................................... 19,753 10,313 3,765 2,725 Other............................................. 5,265 7,615 4,100 3,546 - ----------------------------------------------------------------------------------------------------------------------------- Total............................................. $ 85,246 $ 42,190 $ 22,613 $ 23,563 - ----------------------------------------------------------------------------------------------------------------------------- Production volumes Natural gas (Mcf)................................. 29,318 12,308 8,597 9,169 Oil (MBbl)........................................ 775 635 250 191 Natural gas liquids (MBbl)........................ 502 -- -- -- - ----------------------------------------------------------------------------------------------------------------------------- Proved reserves Natural gas (MMcf)................................ 544,283 212,977 71,267 60,057 Oil (MMBbl)....................................... 9,128 6,315 3,986 1,485 Natural gas liquids (MMBbl)....................... 12,378 -- -- -- - -----------------------------------------------------------------------------------------------------------------------------
34
- ----------------------------------------------------------------------------------------------------------------------------- 1993 1992 1991 1990 1989 1988 1987 - ----------------------------------------------------------------------------------------------------------------------------- $ 216,587 $ 198,676 $ 195,250 $ 188,168 $ 170,302 $ 190,836 $ 181,007 83,069 78,799 84,260 85,588 85,477 104,420 93,242 1,223 6,501 8,916 13,596 25,000 37,923 24,982 27,382 25,089 22,890 22,734 19,574 15,158 17,871 2,299 1,661 (2,188) 873 731 689 679 - --------------------------------------------------------------------------------------------------------------------------- $ 330,560 $ 310,726 $ 309,128 $ 310,959 $ 301,084 $ 349,026 $ 317,781 - --------------------------------------------------------------------------------------------------------------------------- 30,957 29,119 26,262 28,653 27,210 28,636 27,365 13,853 13,860 14,837 16,581 17,946 21,806 18,482 282 2,654 3,411 4,786 9,494 13,026 8,902 49,346 46,235 41,447 39,117 34,447 28,730 26,895 - --------------------------------------------------------------------------------------------------------------------------- 94,438 91,868 85,957 89,137 89,097 92,198 81,644 - --------------------------------------------------------------------------------------------------------------------------- 395,057 387,871 382,747 379,362 365,572 358,872 350,712 32,269 31,732 31,432 31,565 30,492 29,717 29,007 46 41 39 42 42 37 34 - --------------------------------------------------------------------------------------------------------------------------- 427,372 419,644 414,218 410,969 396,106 388,626 379,753 - --------------------------------------------------------------------------------------------------------------------------- $ 17,206 $ 17,154 $ 17,126 $ 16,131 $ 14,657 $ 13,642 $ 12,135 $ 22,107 $ 20,228 $ 19,565 $ 19,565 $ 39,156 $ 25,614 $ 30,833 $ 26,381 $ 25,915 $ 25,209 $ 21,080 $ 18,548 $ 19,666 $ 16,838 - --------------------------------------------------------------------------------------------------------------------------- $ 11,449 $ 10,364 $ 9,889 $ 11,121 $ 11,735 $ 11,344 $ 7,274 3,484 2,559 1,839 1,411 1,468 1,458 1,948 2,753 (44) (3,203) (5,927) (8,286) (8,693) (3,413) - --------------------------------------------------------------------------------------------------------------------------- $ 17,686 $ 12,879 $ 8,525 $ 6,605 $ 4,917 $ 4,109 $ 5,809 - --------------------------------------------------------------------------------------------------------------------------- 6,245 6,415 5,927 4,954 4,964 4,976 3,207 204 145 88 80 95 94 128 -- -- -- -- -- -- -- - --------------------------------------------------------------------------------------------------------------------------- 67,298 51,329 73,279 57,532 29,860 14,803 16,497 1,289 338 402 330 264 292 323 -- -- -- -- -- -- -- - ---------------------------------------------------------------------------------------------------------------------------
EX-21 4 SUBSIDIARIES OF ENERGEN CORPORATION 1 EXHIBIT 21 SUBSIDIARIES OF ENERGEN CORPORATION Alabama Gas Corporation Taurus Exploration, Inc. Taurus Exploration U.S.A., Inc. Basin Pipeline Corp. American Heat Tech, Inc. EGN Services, Inc. Midtown NGV, Inc. EX-23 5 CONSENT OF INDEPENDENT CPAS 1 EXHIBIT 23 CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Energen Corporation on Forms S-8 and S-3 (File No. 2-89855), Form S-3 (File No. 333-00395), Form S-3 (File No. 333-11239) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No. 33-48504, and File No. 33-48505) of our report, dated October 23, 1997, on our audits of the consolidated financial statements of Energen Corporation as of September 30, 1997 and 1996, and for the years ended September 30, 1997, 1996, and 1995, which report is incorporated by reference in this Annual Report on Form 10-K. Coopers & Lybrand L.L.P. Birmingham, Alabama December 17, 1997 EX-27.1 6 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FORM 10K FOR SEPTEMBER 30, 1997, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000277595 ENERGEN CORPORATION 1,000 YEAR SEP-30-1997 OCT-01-1996 SEP-30-1997 PER-BOOK 295,881 371,122 242,165 9,485 0 919,797 144 188,643 112,356 301,143 0 0 279,602 202,000 0 0 1,855 0 0 0 135,197 919,797 448,230 3,097 396,244 399,341 48,889 3,014 51,903 22,906 28,997 0 28,997 15,299 14,250 66,782 2.31 2.31
EX-27.2 7 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FORM 10K FOR SEPTEMBER 1997, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000003146 ALABAMA GAS CORPORATION 1,000 YEAR SEP-30-1997 OCT-01-1996 SEP-30-1997 PER-BOOK 295,881 347 88,236 5,917 0 390,381 20 34,484 106,894 141,398 0 0 125,000 0 0 0 0 0 0 0 123,983 390,381 362,984 10,118 324,192 334,310 28,674 701 29,375 10,809 18,570 0 18,570 6,720 8,765 26,076 0 0 EARNINGS PER SHARE IS CALCULATED FOR ENERGEN CORPORATION (PARENT COMPANY OF ALABAMA GAS CORPORATION) AND IS NOT CALCULATED FOR ALABAMA GAS CORPORATION SEPARATELY AS AMOUNT WOULD NOT BE MEANINGFUL.
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