-----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, EdNOFEr4VtAsSv/HfuGAW3KDeOAPwWKFbjIsxwfa9iP2ADoUAlSspCslT2ezyto1 dp57RBUtJDpts3KaRQBxVw== 0000950144-96-009293.txt : 19961224 0000950144-96-009293.hdr.sgml : 19961224 ACCESSION NUMBER: 0000950144-96-009293 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19960930 FILED AS OF DATE: 19961223 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: 1934 Act SEC FILE NUMBER: 001-07810 FILM NUMBER: 96685105 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: 63022000 STATE OF INCORPORATION: AL FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 033-70466 FILM NUMBER: 96685106 BUSINESS ADDRESS: STREET 1: 2101 SIXTH AVE NORTH CITY: BIRMINGHAM STATE: AL ZIP: 35203 BUSINESS PHONE: 2053268100 MAIL ADDRESS: STREET 1: 2101 SIXTH AVE NORTH CITY: BIRMINGHAM STATE: AL ZIP: 35203 10-K405 1 ENERGEN CORPORATION 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES AND EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 1996
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 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 November 13, 1996: Energen Corporation $295,327,463 Indicate number of shares outstanding of each of the registrant's classes of common stock as of November 13, 1996: Energen Corporation 11,250,570 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 21, 1996 (Part III, Item 10-13) - - Portions of Energen Corporation 1996 Annual Report to Stockholders are incorporated by reference into Part II, Items 5, 6, 7, and 8 of this report 2 ENERGEN CORPORATION 1996 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS
PAGE ---- PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . 9 PART II Item 5. Market for Registrant's Common Stock and Related Stockholder Matters . . . . . . . . . . 12 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . 12 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 PART III Item 10. Directors and Executive Officers of the Registrants . . . . . . . . . . . . . . . . . . 13 Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . 13 Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . 13 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . 14
2 3 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 diversified energy holding company engaged primarily in natural gas distribution and the exploration and production of natural gas and oil. 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 1800's. Alagasco became a public company in 1953. FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS The information required by this item is incorporated by reference from Note 12 Industry Segment Information to the Consolidated Financial Statements of the 1996 Annual Report to Stockholders, and is attached herein as Part IV, Item 14, Exhibit 13. NARRATIVE DESCRIPTION OF BUSINESS - - NATURAL GAS DISTRIBUTION GENERAL: Alagasco, Energen's principal subsidiary, is the largest natural gas distribution utility in the state of Alabama. Alagasco purchases natural gas through interstate and intrastate suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial, industrial 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 or other 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's service territory is located primarily in central and north Alabama and includes over 175 communities in 30 counties. Birmingham, the largest city in Alabama, and Montgomery, the state capital, are served by Alagasco. The counties in which Alagasco provides service have an aggregate area of more than 22,000 square miles and include the service territories of various municipal gas distribution systems. The aggregate population of the counties served by Alagasco is estimated to be 2.4 million. During 1996 Alagasco served an average of 418,486 residential customers, 34,028 small commercial and industrial customers, and 54 large commercial and industrial customers. The Alagasco distribution system includes approximately 8,800 miles of main, more than 9,600 miles of service lines, odorization and regulation facilities, and customer meters. Alagasco also operates two liquefied natural gas facilities which it uses to meet peak demands. APSC REGULATION: As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which, in 1983, established the Rate Stabilization and Equalization (RSE) rate-setting process. RSE was extended for the fourth time on October 7, 1996, 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. 3 4 Under RSE, 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, an $8.2 million annual increase in revenue became effective December 1, 1995, and a $1.3 million decrease in revenue became effective October 1, 1996. 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, 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. On October 7, 1996, the APSC issued an order providing for the refund to customers of approximately $17.1 million, including interest, of supplier refunds. The Order provides that refunds shall be returned to customers prior to January 31, 1997. These 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 will be used to fund the supplier refunds discussed above. On June 12, 1995, Alagasco received approval from the APSC to issue $50 million of debt, a portion of which was used to redeem all of Alagasco's 9 percent debentures and 11 percent First Mortgage Bonds. In connection with the early call of the redeemed debt, Alagasco paid an early call premium of approximately $1.3 million. Because the APSC authorized Alagasco to collect the early call premium through customer rates, a regulatory asset of $1.3 million was recorded at September 30, 1995, and the amounts were collected during fiscal 1996. 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 $2.7 million are being returned to ratepayers over approximately 14 years. At September 30, 1996 and 1995, regulatory liabilities of $5 million and $6 million, respectively, were included in the financial statements related to income taxes. FERC REGULATION: On March 15, 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 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. On April 11, 1996, the FERC issued its Order on Rehearing approving the Settlement with minor modifications. The Settlement, as approved by FERC, provides for the following: (1) the resolution of all cost of service and rate design issues in Southern's six pending rate cases and the establishment of reduced rates for the purpose of calculating rate case refunds; (2) the implementation of reduced settlement rates for supporting parties commencing March 1, 1995; (3) the resolution of all GSR and other transition cost issues resulting from FERC Order 636; (4) lower GSR cost recovery through the reduction and earlier payout of GSR costs; (5) a three-year moratorium on general rate increases; and (6) the resolution and disposition of all rate case 4 5 and GSR refunds for supporting parties. With respect to this last point, the Settlement provides that all rate case refunds will be used to offset a portion of Southern's remaining GSR liability. In addition, as a result of the recalculated GSR surcharges for the period January 1, 1994, to February 28, 1995, Southern refunded over-collected GSR costs. As a result of this FERC order, Alagasco received other refunds based on contracts with other suppliers whose prices were tied to Southern's rates. In total, $17.1 million will be refunded to customers prior to January 31, 1997, and includes amounts received from Southern, other suppliers and accrued interest. The Settlement, as approved by 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 $0.8 million to be paid through December 1997 and approximately $1.4 million in other transition costs to be paid through June 1998. Because these costs will be recovered in full from its customers, Alagasco recorded regulatory assets of $2.2 million and $5 million at September 30, 1996 and 1995, respectively. GAS SUPPLY: The Alagasco distribution system is connected to and has firm transportation contracts with two major interstate pipeline systems--Southern and Transcontinental Gas Pipe Line Corporation. Effective November 1, 1993, Alagasco's pre-Order 636 contract demand and firm transportation with Southern converted to 250,924 Mcf (thousand cubic feet) per day of No-Notice Firm Transportation service for a period of 15 years, 91,946 Mcf per day of Firm Transportation service for 15 years, and 50,000 Mcf per day of Firm Transportation for five years. Southern also unbundled its existing storage capacity. Alagasco's pro rata share of this storage is 12,426,687 Mcf. Alagasco has a maximum withdrawal rate from storage of 250,924 Mcf per day and a maximum injection rate into storage of 95,590 Mcf per day. The Transco firm transportation contract, which expires in 2001, provides for maximum daily firm transportation of up to 100,000 Mcf. Thus the Company has a peak day firm interstate pipeline transportation capacity of 492,870 Mcf per day. Alagasco has replaced the sales service formerly provided by Southern with purchases from various gas producers and marketers including affiliates of Southern and Transco and from certain intrastate producers including Basin Pipeline Corp., an Energen subsidiary. Alagasco has contracts in place to purchase up to a total of 286,776 Mcf per day of firm supply, of which 241,946 is supported by firm transportation on the Transco and Southern systems, 14,830 Mcf provides excess supply on the Southern system, and 30,000 Mcf is purchased at the city gate from intrastate suppliers. This volume, along with Alagasco's maximum withdrawal from storage of 250,924 Mcf per day and 200,000 Mcf per day of liquefied natural gas peak shaving capacity, gives Alagasco a peak day firm supply of 722,870 Mcf per day. 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 transportation customers. COMPETITION AND PRICING: The price of natural gas is a significant marketing factor in the territory served by Alagasco; propane, coal and fuel oil are readily available, and many major industrial customers have the capability to switch to alternate fuels. In the residential and small industrial and commercial markets, electricity is the principal competitor. 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 on the Alagasco system. Firm service is generally not subject to interruption and, therefore, is more expensive than interruptible service. Firm service is generally provided to residential and small commercial and industrial customers. Interruptible service is generally provided to large commercial and industrial customers which typically have the capacity to reduce consumption by adjusting their production schedules or by switching to alternate fuels during periods of interruption. Deliveries of sales and transportation gas totaled 111,422 MMcf (million cubic feet) in 1996. In 1994, capitalizing on federally mandated changes in the natural gas industry, Alagasco implemented the "P" Rate. This tariff allows the utility to, in effect, release available pipeline capacity thereby reducing pipeline transportation costs for its 275 transportation customers. The lower costs help prevent bypass. Also, because 5 6 revenue received from capacity release reduces core market gas costs, Alagasco's competitive position in the residential and small commercial markets is enhanced as well. Alagasco has a Competitive Fuel Clause (CFC) as part of its rate tariff which allows Alagasco to adjust large commercial and industrial prices on a case-by-case basis to compete with either alternate fuels or 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, benefits all customers by recovering a portion of the system's fixed cost. Alagasco also has a Transportation Tariff (the Tariff) which allows the Company to transport gas for customers rather than buying and reselling gas to them. The Tariff is based on Alagasco's gas sales profit margin so that Alagasco's net income is not affected whether it transports or sells gas. The Tariff also may be adjusted under the CFC. Of Alagasco's total large commercial and industrial customer deliveries during 1996, 99.95 percent (46,207 MMcf) was from transportation of customer-owned gas. GROWTH: Alagasco has supplemented traditional service area growth with acquisitions of municipally-owned gas distribution systems. Since 1985 Alagasco has acquired 22 such systems, three of which were acquired in fiscal 1996 initially adding over 1,800 customers. More than 43,000 customers have been added through initial system purchases and subsequent customer additions, as Alagasco has increased the relatively low saturation rates in the acquired areas through a variety of marketing efforts including offering natural gas service to propane customers already situated on the municipal system lines, extending the acquired municipal system into 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, and many are located in or near Alagasco's existing service territory. The Company is optimistic that additional acquisition opportunities will arise in the future. WEATHER: Alagasco's gas distribution business is highly seasonal since a material portion of Alagasco's total sales and delivery volumes is to customers whose use varies depending upon temperature, principally residential, small commercial and small industrial customers. 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, 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. OTHER: For a discussion of risks inherent in the Company's businesses see Management's Discussion and Analysis in the 1996 Annual Report to Shareholders, page 30, which is attached herein as Part IV, Item 14, exhibit 13. - - OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES Energen's oil and gas exploration and production activities are conducted by its subsidiary, Taurus Exploration, Inc. (Taurus) and involve the acquisition, development, exploration and production of natural gas and oil from conventional and nonconventional reservoirs in the continental United States. Taurus's remaining recoverable reserves at the end of fiscal 1996 totaled 250,867 million cubic feet equivalents (MMcfe) and are located primarily in Alabama, Louisiana, Texas and the Gulf of Mexico. As Energen's dominant growth vehicle, Taurus is continuing its strategic focus on acquiring conventional oil and gas producing properties with development potential and supplementing returns with relatively low-risk Gulf of Mexico exploration and related development. Beginning with the 1996 fiscal year, Energen embarked on an aggressive, five- year diversified growth strategy which calls for the Company to invest through Taurus $400 million 6 7 in producing property acquisitions and related development and $100 million in exploration and related development. In implementing Energen's growth strategy, Taurus works with a variety of experienced industry partners in its acquisition and exploration activities. Taurus also is working to increase its internal generation of acquisition opportunities. To help minimize risk, Taurus takes small working interest positions in numerous exploratory prospects rather than a large position in a few. Taurus also utilizes the natural gas and oil futures markets as well as fixed-price contracts as defensive mechanisms to mitigate the impact of commodity price volatility on targeted returns of reserve acquisitions and to manage overall price volatility on other production. The first year of implementation of Energen's diversified growth strategy resulted in Taurus investing $108 million for the acquisition of eight producing properties with development potential and participating in 12 successful exploratory and development wells in the Gulf of Mexico. Net reserve additions totaled 171,801 MMcfe, production increased 60 percent to 16,118 MMcfe, and the average sales price per MMcfe was $1.97. Taurus also serves as the operator of extensive Black Warrior Basin coalbed methane properties for its own interests and those of its partners, and also provides third-party operations. Since making the transition away from the development of new coalbed methane projects in the early 1990s, Taurus has continued to operate coalbed methane wells as a profitable business activity but looks to the acquisition, exploration and development of oil and gas reserves for long-term growth. PROPERTY ACQUISITIONS AND DEVELOPMENT: Taurus's largest property acquisition in fiscal 1996 was the $61 million purchase of 105 Bcf of coalbed methane reserves in Alabama from Burlington Resources Inc. Part of Burlington's accelerated divesture program, these Black Warrior Basin wells cover 19,000 gross acres adjacent to existing coalbed methane interests of Taurus's in west central Alabama. Substantially all of these long-lived coalbed methane reserves are proved producing and complemented well Taurus's other reserve acquisitions which featured a greater amount of behind-pipe and proved undeveloped reserves. Production from 43 of the more than 100 wells qualifies for the nonconventional fuels tax credit, which presently is valued at $1 per Mcf of production and increases annually with inflation. Through its partnership with Sonat Exploration Company, a subsidiary of Birmingham-based Sonat Inc., Taurus invested $28 million in four conventional property acquisitions during fiscal 1996. Three of the properties are located in Louisiana and the other is located in the Gulf of Mexico, offshore Louisiana and Texas. Taurus's working interest in these projects ranges from one-third to 40 percent. Taurus estimates its development costs related to these acquisitions will total approximately $20 million over the next three to four years. Taurus joined Sonat Exploration's ongoing reserve acquisition efforts in the summer of 1995 through a three-and-a-half year agreement and plans to invest $25 million to $50 million annually with Sonat in calendar years 1996, 1997 and 1998. Related development drilling may require additional investment on the part of Taurus over the ensuing five years of approximately 50 cents for each acquisition dollar. In September 1996, Taurus purchased a 75 percent working interest in the Odem Field in south Texas from Bargo Energy Company and Moran Resources Company and acquired estimated proved reserves of 21 Bcfe for $15 million. Taurus's share of future development costs could approximate $4 million. Early in fiscal 1996, Taurus made a small acquisition through its joint venture with PMC Reserve Acquisition Company and subsequently purchased the interest of another participant in PMC's acquisition program. In September 1996, PMC sold its oil and gas properties; Taurus elected to sell its related interests of 11 Bcfe and realized a $3.2 million gain on its investment. As part of our ongoing business activities, Taurus may be involved, from time to time, in the sale of developed and undeveloped properties as a source of revenue as a result of, but not limited to, disposing of marginal assets and accepting offers where the buyer gives greater value to a property than Taurus's technical staff. 7 8 EXPLORATION AND DEVELOPMENT: Taurus invested $18 million in offshore exploration and related development during 1996. Through existing partnership arrangements with United Meridian Corporation (UMC) and King Ranch Oil & Gas, Taurus participated in 12 successful exploratory and development wells, adding 5 Bcf of natural gas to its proved reserves. Taurus utilizes several avenues to ensure a continuing flow of high quality exploratory prospects, including its participation in UMC's offshore exploratory program, a multi-year 3-D seismic joint venture with King Ranch and Holley Petroleum, Inc., covering 200 offshore Texas blocks, and other offshore lease sales with various industry partners. While primarily focusing on Gulf of Mexico exploration, Taurus did acquire in fiscal 1996 a 25 percent working interest in Sonat Exploration's exploratory efforts in the North Crowley field in Louisiana. This field also contains producing properties and was one of the four acquisitions made through Taurus's joint agreement with Sonat Exploration. The field contains 8,000 gross undeveloped acres. COALBED METHANE OPERATIONS: Taurus's nonconventional gas strategy is to focus on operating the large projects in which it has a working interest and operating for others. Taurus is the operator of approximately 1,140 coalbed methane wells, including wells in a project owned by TECO Coalbed Methane, Inc., one of Taurus's joint venture partners in other coalbed methane projects. Under the terms of the TECO agreement, Taurus provides technical, administrative and operating services for a fee and receives additional compensation based on the project's profitability. Most of the gas produced from the coalbed methane wells in which Taurus has an interest is being sold under long-term contracts which provide markets for 100 percent of the wells' production capacity. 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 and that potential environmental liabilities, if any, are minimal. Also, to the extent Taurus has operating agreements with various joint venture partners, environmental costs, is 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 1996 Annual Report to Shareholders, page 30, which is attached herein as Part IV, Item 14, exhibit 13. 8 9 - - INTRASTATE GAS GATHERING AND TRANSMISSION Energen operates an intrastate gas pipeline and gathering system through its subsidiary, Basin Pipeline Corp. (Basin). Basin's pipeline and gathering facilities primarily serve certain Taurus coalbed methane properties. EMPLOYEES The Company has 1,437 employees; Alagasco employs 1,296; Taurus employs 129; 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 8,800 miles of main, more than 9,600 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 12, Oil and Gas Producing Activities (unaudited) to the Consolidated Financial Statements which is incorporated by reference from the 1996 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, Alagasco and their affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specific relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and Alagasco. It should be noted, however, that Energen, Alagasco and their 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 1996. 9 10 EXECUTIVE OFFICERS OF THE REGISTRANTS ENERGEN CORPORATION
Name Age Position (1) ---- --- ------------ Rex J. Lysinger 59 Chairman of the Board and Chief Executive Officer (2) Wm. Michael Warren, Jr. 49 President and Chief Operating Officer (3) Geoffrey C. Ketcham 45 Executive Vice President, Chief Financial Officer and Treasurer (4) Dudley C. Reynolds 43 General Counsel and Secretary (5) Gary C. Youngblood 53 Executive Vice President and Chief Operating Officer of Alagasco (6) James T. McManus 38 Executive Vice President and Chief Operating Officer of Taurus (7) John A. Wallace 52 Senior Vice President--Methane of Taurus (8) J. David Woodruff, Jr. 40 Vice President--Legal and Assistant Secretary and Vice President--Corporate Development (9)
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 and Chief Executive Officer of Energen. 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. 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. 10 11 (5) 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. (6) 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. (7) 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. (8) 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. (9) 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. 11 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 1996 Annual Report to Stockholders, page 30, and is included in Part IV, Item 14, Exhibit 13, herein. At October 28, 1996, there were approximately 7,700 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 1996 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 DATA The information regarding selected financial data is incorporated by reference from the 1996 Annual Report to Stockholders, pages 54-55, 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 1996 Annual Report to Stockholders, pages 23-30, 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 1996 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 12 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 22, 1997. The proxy statement will be filed on or about December 21, 1996. 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 22, 1997. 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 22, 1997. 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 22, 1997. 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 22, 1997. 13 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 August 10, 1996, 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 10, 1996, reporting certain supplementary financial information related to the above purchase 14 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 16, 1996 /s/Rex J. Lysinger - ------------------------- ---------------------------------------------- DATE Rex J. Lysinger Chairman of the Board of Directors of Energen and all subsidiaries, Chief Executive Officer of Energen 15 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 16, 1996 /s/Rex J. Lysinger - -------------------------- -------------------------------------------------------------- DATE Rex J. Lysinger Chairman of the Board of Directors of Energen and all subsidiaries, Chief Executive Officer of Energen December 16, 1996 /s/Wm. Michael Warren, Jr. - ---------------------------- -------------------------------------------------------------- DATE Wm. Michael Warren, Jr. President and Director of Energen and all subsidiaries, Chief Executive Officer of Alagasco and Chief Operating Officer of Energen December 16, 1996 /s/Geoffrey C. Ketcham - ---------------------------- -------------------------------------------------------------- DATE Geoffrey C. Ketcham Executive Vice President, Chief Financial Officer and Treasurer December 16, 1996 /s/Paula H. Rushing - ---------------------------- -------------------------------------------------------------- DATE Paula H. Rushing Controller of Alagasco December 16, 1996 /s/Stephen D. Ban - ---------------------------- -------------------------------------------------------------- DATE Stephen D. Ban Director December 16, 1996 /s/James S. M. French - ---------------------------- -------------------------------------------------------------- DATE James S. M. French Director December 16, 1996 /s/Wallace L. Luthy - ---------------------------- -------------------------------------------------------------- DATE Wallace L. Luthy Director December 16, 1996 /s/Judy M. Merritt - ---------------------------- -------------------------------------------------------------- DATE Judy M. Merritt Director
16 17 ENERGEN CORPORATION ALABAMA GAS CORPORATION INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES ITEM 14(A)
Reference Page -------------- 1996 1996 Annual 10-K Report ---- ------ 1. Energen Corporation ------------------- A. Financial Statements Report of Independent Certified Public Accountants . . . . . . . . . 52 Consolidated statements of income for the years ended September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 31 Consolidated balance sheets as of September 30, 1996 and 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Consolidated statements of shareholders' equity for the years ended September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . 34 Consolidated statements of cash flows for the years ended September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 35 Notes to consolidated financial statements . . . . . . . . . . . . . 36 B. Financial Statement Schedule Report of Independent Certified Public Accountants . . . . . . . . . 37 Schedule II Valuation and Qualifying Accountants . . . . . . . . 38 2. Alabama Gas Corporation ----------------------- A. Financial Statements Report of Independent Certified Public Accountants . . . . . . . . . 22 Statements of income for the years ended September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 23 Balance sheets as of September 30, 1996 and 1995 . . . . . . . . . . 24
17 18
Reference Page -------------- 1996 1996 Annual 10-K Report ---- ------ Statements of shareholder's equity for the years ended September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 26 Statements of cash flows for the years ended September 30, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . 27 Notes to financial statements . . . . . . . . . . . . . . . . . . . 28 B. Financial Statement Schedule Schedule II Valuation and Qualifying Accounts . . . . . . . . . 39
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. 18 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). 19 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. *10(b) Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation as filed as Exhibit 10(b) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993. *10(c) 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. *10(d) Form of Service Agreement Under Rate Schedule FT (No. 866940) between Southern Natural Gas Company and Alabama Gas Corporation as filed as Exhibit 10(d) to Energen's Annual Report on Form 10-K for the year ended September 30, 1993. 10(e) Form of Executive Retirement Supplement Agreement between Energen Corporation and certain executive officers. *10(f) Restricted Stock Incentive Plan of Energen Corporation, which was filed as Exhibit 4 to Post Effective Amendment No. 2 to Energen Corporation's Registration Statement on Forms S-8 and S-3 (Registration No. 2-89855). 10(g) Form of Severance Compensation Agreement between Energen Corporation and certain executive officers. *10(h) 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. *10(i) Energen Corporation 1992 Long-Range Performance Share Plan, dated as of October 1, 1991, which was filed as Exhibit A to the Registrant's Proxy Statement for its January 22, 1992, Annual Meeting (File No. 1-7810). *10(j) Amendment to Energen Corporation 1992 Long-Range Performance Share Plan, which was filed as Appendix B to the Registrant's Proxy Statement for its January 22, 1997, Annual Meeting (File No. 1-7810). 20 21 *10(k) 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(l) 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(m) 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. *10(n) 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. 13 Information incorporated by reference from pages 23-57 of the Energen Corporation 1996 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 21 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 17 and 18 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 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, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 1996, 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, 1996 22 23 STATEMENTS OF INCOME ALABAMA GAS CORPORATION
=========================================================================================================== YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 =========================================================================================================== OPERATING REVENUES $ 357,252 $ 295,967 $ 344,637 - ----------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas 181,400 133,556 188,592 Operations 81,585 78,139 72,639 Maintenance 10,956 9,727 9,147 Depreciation 21,269 19,370 17,941 Income taxes Current 8,699 8,392 10,623 Deferred, net 835 177 (2,418) Deferred investment tax credits, net (487) (487) (487) Taxes, other than income taxes 26,772 22,662 26,301 - ----------------------------------------------------------------------------------------------------------- Total operating expenses 331,029 271,536 322,338 - ----------------------------------------------------------------------------------------------------------- OPERATING INCOME 26,223 24,431 22,299 - ----------------------------------------------------------------------------------------------------------- OTHER INCOME Allowance for funds used during construction 972 1,054 465 Other, net (649) (112) 452 - ----------------------------------------------------------------------------------------------------------- Total other income 323 942 917 - ----------------------------------------------------------------------------------------------------------- INTEREST CHARGES Interest on long-term debt 7,390 7,730 6,475 Other interest expense 2,195 1,922 1,845 - ----------------------------------------------------------------------------------------------------------- Total interest charges 9,585 9,652 8,320 - ----------------------------------------------------------------------------------------------------------- NET INCOME AVAILABLE FOR COMMON $ 16,961 $ 15,721 $ 14,896 ===========================================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 23 24 BALANCE SHEETS ALABAMA GAS CORPORATION
=========================================================================================================== YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 =========================================================================================================== ASSETS PROPERTY, PLANT AND EQUIPMENT Utility plant $ 544,643 $ 504,371 Less accumulated depreciation 268,110 247,926 - ----------------------------------------------------------------------------------------------------------- Utility plant, net 276,533 256,445 - ----------------------------------------------------------------------------------------------------------- Other property, net 394 193 - ----------------------------------------------------------------------------------------------------------- CURRENT ASSETS Cash 803 727 Accounts receivable Gas 26,999 22,215 Merchandise 1,730 1,546 Other 2,955 1,399 Affiliated companies 10,582 199 Allowance for doubtful accounts (2,985) (2,000) Inventories, at average cost Storage gas inventory 28,214 20,276 Materials and supplies 5,828 5,860 Liquified natural gas in storage 2,417 3,539 Deferred gas costs 1,975 1,426 Regulatory asset 2,246 6,321 Deferred income taxes 6,344 7,416 Prepayments and other 2,904 2,302 - ----------------------------------------------------------------------------------------------------------- Total current assets 90,012 71,226 - ----------------------------------------------------------------------------------------------------------- DEFERRED CHARGES AND OTHER ASSETS 7,467 7,403 - ----------------------------------------------------------------------------------------------------------- TOTAL ASSETS $ 374,406 $ 335,267 ===========================================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 24 25 BALANCE SHEETS ALABAMA GAS CORPORATION
=========================================================================================================== YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 =========================================================================================================== 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 1996 and 1995 $ 20 $ 20 Premium on capital stock 31,682 31,682 Capital surplus 2,802 2,802 Retained earnings 95,044 87,638 - ----------------------------------------------------------------------------------------------------------- Total common shareholder's equity 129,548 122,142 Cumulative preferred stock, $0.01 par value, 120,000 shares authorized -- -- Long-term debt 125,000 100,000 - ----------------------------------------------------------------------------------------------------------- Total capitalization 254,548 222,142 - ----------------------------------------------------------------------------------------------------------- CURRENT LIABILITIES Long-term debt due within one year -- -- Notes payable to banks -- -- Accounts payable Trade 23,758 26,160 Affiliated companies 1,512 -- Accrued taxes 18,067 10,236 Customers' deposits 17,364 18,218 Supplier refunds due customers 17,257 3,315 Other amounts due customers 489 13,231 Accrued wages and benefits 4,459 5,228 Other 10,611 9,444 - ----------------------------------------------------------------------------------------------------------- Total current liabilities 93,517 85,832 - ----------------------------------------------------------------------------------------------------------- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes 16,883 16,343 Accumulated deferred investment tax credits 3,617 4,103 Regulatory liability 5,038 6,001 Customer advances for construction and other 803 846 - ----------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 26,341 27,293 - ----------------------------------------------------------------------------------------------------------- TOTAL CAPITAL AND LIABILITIES $ 374,406 $ 335,267 ===========================================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 25 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, 1993 1,972,052 $ 20 $21,682 $ 2,802 $ 74,886 Net income 14,896 Cash dividends (8,695) Capital contribution from parent 10,000 - ------------------------------------------------------------------------------------------------------------ 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 ============================================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 26 27 STATEMENTS OF CASH FLOWS ALABAMA GAS CORPORATION
=========================================================================================================== YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 =========================================================================================================== OPERATING ACTIVITIES Net Income $ 16,961 $ 15,721 $ 14,896 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 21,269 19,370 17,941 Deferred income taxes, net 835 177 (2,418) Deferred investment tax credits (487) (487) (487) Net change in: Accounts receivable (5,539) (113) 896 Inventories (6,784) 3,725 (23,913) Deferred gas costs (549) 34 1,505 Accounts payable -- gas purchase (1,614) 9,882 1,220 Accounts payable -- other trade (788) (2,856) (2,110) Other current assets and liabilities 12,048 (3,057) 15,763 Other, net (1,019) 673 (2,116) - ------------------------------------------------------------------------------------------------------------ Net cash provided by operating activities 34,333 43,069 21,177 - ------------------------------------------------------------------------------------------------------------ INVESTING ACTIVITIES Additions to property, plant and equipment (42,037) (41,560) (37,853) Net advances (to) from parent company (8,871) (199) 87 Other, net 1,377 (15) 181 - ------------------------------------------------------------------------------------------------------------ Net cash used in investing activities (49,531) (41,774) (37,585) - ------------------------------------------------------------------------------------------------------------ FINANCING ACTIVITIES Payment of dividends on common stock (9,555) (9,170) (8,695) Reduction of long-term debt and preferred stock -- (37,214) (9,891) Proceeds from medium term notes 24,829 49,660 49,670 Proceeds from capital contribution from parent -- -- 10,000 Net change in short-term debt -- (4,000) (25,000) - ------------------------------------------------------------------------------------------------------------ Net cash provided by (used in) financing activities 15,274 (724) 16,084 - ------------------------------------------------------------------------------------------------------------ Net change in cash and cash equivalents 76 571 (324) Cash and cash equivalents at beginning of period 727 156 480 - ------------------------------------------------------------------------------------------------------------ Cash and cash equivalents at end of period $ 803 $ 727 $ 156 ============================================================================================================
The accompanying Notes to Financial Statements are an integral part of these statements. 27 28 NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - -------------------------------------------------------------------------------- Alabama Gas Corporation (Alagasco), a wholly-owned subsidiary of Energen Corporation, 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 4.3 percent in 1996, 1995 and 1994. The excess of total acquisition costs over book value of net assets acquired to date is included in utility plant ($23.2 million, net of $6.5 in accumulated amortization at September 30, 1996) and is being amortized on a straight-line basis over approximately 23 years. 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 for the fourth time on October 7, 1996, 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 28 29 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, an $8.2 million annual increase in revenue became effective December 1, 1995, and a $1.3 million decrease in revenue became effective October 1, 1996. Effective December 15, 1990, the APSC approved 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. On October 7, 1996, the APSC issued an order providing for the refund to customers of approximately $17.1 million, including interest, of supplier refunds. The Order provides that refunds shall be returned to customers prior to January 31, 1997. These 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 will be used to fund the supplier refunds discussed above. On June 12, 1995, Alagasco received approval from the APSC to issue $50 million of debt, a portion of which was used to redeem all of Alagasco's 9 percent debentures and 11 percent First Mortgage Bonds. In connection with the early call of the redeemed debt, Alagasco paid an early call premium of approximately $1.3 million. Because the APSC authorized Alagasco to collect the early call premium through customer rates, a regulatory asset of $1.3 million was recorded at September 30, 1995, and the amounts were collected during fiscal 1996. 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 $2.7 million are being returned to ratepayers over approximately 14 years. At September 30, 1996 and 1995, regulatory liabilities of $5 million and $6 million, respectively, were included in the financial statements related to income taxes. FERC Regulation: On March 15, 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 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. On April 11, 1996, the FERC issued its Order on Rehearing approving the Settlement with minor modifications. The Settlement, as approved by FERC, provides for the following: (1) the resolution of all cost of service and rate design issues in Southern's six pending rate cases and the establishment of reduced rates for the purpose of calculating rate case refunds; (2) the implementation of reduced settlement rates for supporting parties commencing March 1, 1995; (3) the resolution of all GSR and other transition cost issues resulting from FERC Order 636; (4) lower GSR cost recovery through the reduction and earlier payout of GSR costs; (5) a three-year moratorium on general rate increases; and (6) the resolution and disposition of all rate case and GSR refunds for supporting parties. With respect to this last point, the Settlement provides that all rate case refunds will be used to offset a portion of Southern's remaining GSR liability. In addition, as a result of the recalculated GSR surcharges for the period January 1, 1994, to February 28, 1995, Southern refunded over-collected GSR costs. As a 29 30 result of this FERC order, Alagasco received other refunds based on contracts with other suppliers whose prices were tied to Southern's rates. In total, $17.1 million will be refunded to customers prior to January 31, 1997, and includes amounts received from Southern, other suppliers and accrued interest. The Settlement, as approved by 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 $0.8 million to be paid through December 1997 and approximately $1.4 million in other transition costs to be paid through June 1998. Because these costs will be recovered in full from its customers, Alagasco recorded regulatory assets of $2.2 million and $5 million at September 30, 1996 and 1995, respectively.
3. LONG-TERM DEBT AND NOTES PAYABLE ========================================================================================================= Long-term debt consists of the following: ========================================================================================================= As of September 30, (in thousands) 1996 1995 ========================================================================================================= Medium-term Notes, interest ranging from 5.4% to 7.97%, for notes redeemable December 1, 1998, to September 23, 2026 $ 125,000 $ 100,000 Less amounts due within one year -- -- - --------------------------------------------------------------------------------------------------------- Total $ 125,000 $ 100,000 =========================================================================================================
In the prior year, Alagasco deposited $37.6 million into an irrevocable trust to complete an in-substance defeasance of its 9 percent debentures and 11 percent Series H First Mortgage Bonds. The funds in the trust, primarily obtained through the issuance of medium-term notes and short-term borrowings, were used solely to satisfy the principal, interest, and call premium of the defeased debt. Accordingly, the debt and related accrued interest were excluded from the 1995 balance sheet. No gain or loss was recorded in the financial statements as the APSC granted Alagasco regulatory relief related to the income statement impact of this defeasance. The aggregate maturities of long-term debt for the next five years are as follows:
===================================================================================================== Years ending September 30, (in thousands) ===================================================================================================== 1997 1998 1999 2000 2001 - ----------------------------------------------------------------------------------------------------- $ -- $ -- $ 5,350 $ -- $ 4,650 =====================================================================================================
Energen and Alagasco have short-term credit lines and other credit facilities of $156 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) 1996 1995 1994 ========================================================================================================= Alagasco outstanding $ -- $ -- $ 4,000 Other Energen outstanding 59,000 32,300 2,000 Available for borrowings 97,000 77,700 104,000 - --------------------------------------------------------------------------------------------------------- Total $ 156,000 $ 110,000 $ 110,000 ========================================================================================================= Maximum amount outstanding at any month-end $ 22,000 $ 5,000 $ 60,000 Average daily amount outstanding $ 6,672 $ 447 $ 13,836 Weighted average interest rates based on: Average daily amount outstanding 5.73% 5.69% 3.32% Amount outstanding at year-end -- -- 5.17% =========================================================================================================
Total interest expense for Alagasco in 1996, 1995 and 1994 was $9,585,000, $9,652,000, and $8,320,000, respectively. 30 31
4. INCOME TAXES ============================================================================================================ The components of income taxes consist of the following: ============================================================================================================ For the years ended September 30, (in thousands) 1996 1995 1994 ============================================================================================================ Taxes estimated to be payable currently: Federal $ 7,924 $ 7,633 $ 9,664 State 775 759 959 ============================================================================================================ Total current 8,699 8,392 10,623 ============================================================================================================ Taxes deferred: Federal 274 (326) (2,689) State 74 16 (216) ============================================================================================================ Total deferred 348 (310) (2,905) ============================================================================================================ Total income tax expense $ 9,047 $ 8,082 $ 7,718 ============================================================================================================
Temporary differences and carryforwards which give rise to a significant portion of deferred tax assets and liabilities for 1996 and 1995 are as follows:
============================================================================================================ As of September 30, (in thousands) 1996 1995 ============================================================================================================ Current Noncurrent Current Noncurrent ========================== ========================== Deferred tax assets: Deferred investment tax credits $ -- $ 1,205 $ -- $ 1,386 Regulatory liabilities -- 1,872 -- 2,229 Unbilled revenue 1,658 -- 1,565 -- Insurance and accruals 2,239 -- 1,923 -- Gas supply adjustment -- -- 930 -- Accrued vacation 1,067 -- 988 -- Allowance for uncollectible accounts 1,268 -- 902 -- Other, net 2,300 74 2,022 52 - ------------------------------------------------------------------------------------------------------------ Subtotal 8,532 3,151 8,330 3,667 Valuation allowance -- -- -- -- - ------------------------------------------------------------------------------------------------------------ Total deferred tax assets $ 8,532 $ 3,151 $ 8,330 $ 3,667 ============================================================================================================ Deferred tax liabilities: Depreciation and basis differences $ -- $ 19,087 $ -- $ 19,297 Gas supply adjustment 500 -- -- -- Other, net 1,688 947 914 713 - ------------------------------------------------------------------------------------------------------------ Total deferred tax liabilities $ 2,188 $ 20,034 $ 914 $ 20,010 ============================================================================================================
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. 31 32 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) 1996 1995 1994 ============================================================================================================= Income tax expense at statutory federal income tax rate $ 9,103 $ 8,331 $ 7,915 Increase (decrease) resulting from: Investment tax credits-deferred (487) (487) (487) State income taxes, net of federal income tax benefit 559 512 486 Other, net (128) (274) (196) - ------------------------------------------------------------------------------------------------------------- Total income tax expense $ 9,047 $ 8,082 $ 7,718 =============================================================================================================
There were no tax-related balances due to affiliates at September 30, 1996 or 1995. 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, 1996, 1995 and 1994, was $412,000, $1,158,000, and $15,000, respectively. The expense for the second plan covering employees under certain labor union agreements (Plan B) for 1996, 1995 and 1994 was $197,000, $339,000, and $555,000, respectively. The funded status of the plans is as follows:
========================================================================================================= As of June 30, (in thousands) Plan A Plan B ========================================================================================================= 1996 1995 1996 1995 ===================== ======================== Vested benefits $(56,828) $(46,073) $ (14,210) $ (13,499) Nonvested benefits (4,323) (5,912) (2,336) (2,083) - --------------------------------------------------------------------------------------------------------- Accumulated benefit obligation (61,151) (51,985) (16,546) (15,582) Effects of salary progression (12,607) (11,047) -- -- - --------------------------------------------------------------------------------------------------------- Projected benefit obligation (73,758) (63,032) (16,546) (15,582) Fair value of plan assets, primarily equity and fixed income securities 80,750 69,431 18,358 16,429 Unrecognized net gain (loss) (337) 1,470 (433) 296 Unrecognized prior service cost 35 41 1,205 1,412 Unrecognized net transition obligation (asset) (4,303) (5,111) 340 396 - --------------------------------------------------------------------------------------------------------- Accrued pension asset $ 2,387 $ 2,799 $ 2,924 $ 2,951 =========================================================================================================
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. At September 30, 1995, for both plans the discount rate used to measure the projected benefit obligation was 7.5 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 5.5 percent. 32 33 The components of net pension costs for 1996, 1995 and 1994 were:
============================================================================================================= For the years ended September 30, (in thousands) Plan A Plan B ============================================================================================================= 1996 1995 1994 1996 1995 1994 ============================ =========================== Service Cost $ 2,147 $ 2,052 $ 1,873 $ 255 $ 224 $ 224 Interest cost on projected benefit obligation 4,617 4,728 4,550 1,166 1,095 1,042 Actual (return) on plan assets (22,733) (8,787) (504) (2,971) (2,172) (372) Net amortization and deferral 16,381 2,106 (5,904) 1,747 1,192 (339) Loss due to special termination benefits -- 1,489 -- -- -- -- Settlement gain -- (430) -- -- -- -- - ------------------------------------------------------------------------------------------------------------- Net pension expense $ 412 $ 1,158 $ 15 $ 197 $ 339 $ 555 =============================================================================================================
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 for certain key executives providing for payments on retirement, termination, death or disability. The deferred compensation expense under these agreements for 1996, 1995 and 1994 was $1,002,000, $808,000, and $461,000, respectively. At June 30, 1996 and 1995, the accumulated post-retirement benefit obligation related to these agreements was $6,206,000 and $4,770,000, the projected benefit obligation was $9,442,000 and $5,904,000, and the accrued post-retirement benefit liability was $464,000 and $199,000. 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. In a prior year, the Company adopted SFAS No.106, Employers' Accounting for Post-retirement benefits Other Than Pensions, with respect to the accrual of such costs for salaried employees. During fiscal year 1994, the Company adopted SFAS 106 with respect to such costs for employees under collective bargaining agreements. There was no cumulative effect on the income statement resulting from the adoption of FAS 106, as the Company elected to amortize transition costs over a 20-year period. On December 6, 1993, the APSC adopted an order which allows the Company to recover all costs accrued under SFAS 106 through rates. 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, 1996, 1995, and 1994 was $1,984,000, $2,271,000, and $2,319,000, respectively. The expense for union employees was $4,076,000, $3,613,000, and $3,685,000 during 1996, 1995 and 1994, 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 ========================================================================================================= 1996 1995 1996 1995 ====================== ======================== Retirees $ (10,344) $ (9,091) $ (14,982) $(13,030) Active, fully-eligible (1,574) (3,306) (4,011) (3,776) Other active (7,989) (8,360) (14,415) (12,794) - ---------------------------------------------------------------------------------------------------------- Accumulated post-retirement benefit obligation (19,907) (20,757) (33,408) (29,600) Fair value of plan assets, primarily equity and fixed income securities 17,519 12,659 8,399 4,419 Unamortized amounts 1,210 7,550 20,887 24,237 - ---------------------------------------------------------------------------------------------------------- Accrued post-retirement benefit liability $ (1,178) $ (548) $ (4,122) $ (944) ==========================================================================================================
33 34 Net periodic post-retirement benefit cost for the years ended September 30, 1996, 1995, and 1994 included the following:
============================================================================================================= For the years ended September 30, (in thousands) Salaried Employees Union Employees ============================================================================================================= 1996 1995 1994 1996 1995 1994 ============================ =========================== Service cost $ 516 $ 512 $ 450 $ 876 $ 807 $ 481 Interest cost on accumulated post-retirement benefit obligation 1,679 1,696 1,726 2,195 1,793 1,920 Amortization of transition obligation 723 723 723 1,285 1,285 1,285 Amortization of actuarial gains and losses (277) -- -- -- -- -- Deferred asset (gain) loss 658 539 (453) 177 424 -- Actual (return) on plan assets (1,315) (1,199) (127) (457) (696) (1) - ------------------------------------------------------------------------------------------------------------- Net periodic post-retirement benefit expense $ 1,984 $ 2,271 $ 2,319 $ 4,076 $ 3,613 $ 3,685 =============================================================================================================
The weighted average discount rate used in determining the accumulated post-retirement benefit obligation was 7.75 percent and 7.5 percent in 1996 and 1995, respectively. 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 percent in 1996 and 1995. 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. The assumed health care cost trend rate of 8 percent is not currently expected to change. For pay-related life insurance benefits, the salary scale averages 5 percent. 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, 1996, 1995, and 1994 was $370,000, $155,000, and $150,000, respectively. 6. CAPITAL STOCK ================================================================================ Alagasco's authorized common stock consists of 3 million, $0.01 par value common shares. At September 30, 1996 and 1995, 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. 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. 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 1996, 1995 and 1994, Alagasco sold $8,831,000, $8,454,000 and $6,784,000, respectively, of installment receivables. At September 30, 1996 and 1995, the balance of these installment receivables was $16,964,000 and $15,618,000, 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. 34 35 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. 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 460,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, Alagasco believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure. LEASE OBLIGATIONS: Total payments related to leases included as operating expense in the accompanying consolidated statements of income were $2,146,000, $2,201,000, and $2,147,000 in 1996, 1995 and 1994, respectively. Minimum future rental payments (in thousands) required after 1996 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
=========================================================================================================== 1997 1998 1999 2000 2001 2002 and thereafter =========================================================================================================== $ 1,950 $ 724 $ 286 $ 256 $ 80 $ 80 ===========================================================================================================
8. SUPPLEMENTAL CASH FLOW INFORMATION ================================================================================ Supplemental information concerning cash flow activities is as follows:
=========================================================================================================== For the years ended September 30, (in thousands) 1996 1995 1994 =========================================================================================================== Interest paid, net of amount capitalized $ 9,216 $ 11,166 $ 7,762 Income taxes paid $ 5,932 $ 10,920 $ 9,097 Noncash investing activities: Capitalized depreciation $ 166 $ 166 $ 155 Allowance for funds used during construction $ 972 $ 1,054 $ 465 Noncash financing activities (debt issuance costs) $ 171 $ 340 $ 330 ===========================================================================================================
9. FINANCIAL INSTRUMENTS ================================================================================ The fair value of cash and cash equivalents and trade receivables (net of allowance), approximates fair value due to the short maturity of the instruments. The fair value of fixed-rate long-term debt, including the current portion, would be $121,567,000 at September 30, 1996. The fair value was based on the market value of debt with similar maturities and with interest rates currently trading in the marketplace. 35 36 10. RECENT PRONOUNCEMENTS OF THE FASB ================================================================================ In June 1995, the Financial Accounting Standards Board (FASB) issued SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This statement requires that long-lived assets be reviewed for impairment whenever events or changes in the circumstances indicate that the carrying amount for an asset may not be recoverable. The Company is required to adopt this Statement in its 1997 fiscal year, but, based on known facts and circumstances, does not expect implementation to have a material impact on the Company's financial statements. In October 1995, SFAS No. 123, Accounting for Stock-Based Compensation, was issued and also requires adoption by the Company in its fiscal year 1997. SFAS No. 123 establishes a fair value-based method of accounting for employee stock options but allows companies to continue to follow the accounting treatment prescribed by APB Opinion 25 with proper disclosure. The Company has not yet determined the method of accounting that it will follow for stock options but does not expect that adoption of the requirements of SFAS No. 123 will have a material impact on the Company's financial statements. In June 1996, SFAS No. 125, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, was issued and provides accounting and reporting standards for such transactions. The Statement requires adoption by the Company in its fiscal year 1998. Implementation of SFAS No. 125 is not expected to have a material impact on the Company's financial statements. 11. 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.
========================================================================================================== 1996 Fiscal Quarters First Second Third Fourth ========================================================================================================== 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) ==========================================================================================================
1995 Fiscal Quarters First Second Third Fourth ========================================================================================================== Operating revenues $ 67,226 $ 134,141 $ 55,865 $ 38,735 Operating income (loss) $ 3,696 $ 19,276 $ 3,383 $ (1,924) Net income (loss) available for common $ 1,751 $ 17,267 $ 1,772 $ (5,069) ==========================================================================================================
12. TRANSACTIONS WITH RELATED PARTIES ================================================================================ Alagasco purchased natural gas from affiliates amounting to $5,097,000, $4,644,000, and $10,255,000, in 1996, 1995, and 1994, respectively. These amounts are included in gas purchased for resale. Alagasco had net receivables from affiliates of $9,049,000 at September 30, 1996, and net payables to affiliates of $183,000 at September 30, 1995. 36 37 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 bene incorporated by reference in this Form 10-K from page 52 of the 1996 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 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, 1996 37 38 SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS Energen Corporation and Subsidiaries
==================================================================================================== YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 ==================================================================================================== ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at beginning of year $ 2,533 $ 2,037 $ 1,927 - ---------------------------------------------------------------------------------------------------- Additions: Charged to income: 2,361 2,431 1,825 Recoveries and adjustments (187) 67 153 - ---------------------------------------------------------------------------------------------------- 2,174 2,498 1,978 - ---------------------------------------------------------------------------------------------------- Less uncollectible accounts written off 1,705 2,002 1,868 - ---------------------------------------------------------------------------------------------------- BALANCE AT END OF YEAR $ 3,002 $ 2,533 $ 2,037 ====================================================================================================
38 39 SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS ALABAMA GAS CORPORATION
==================================================================================================== YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 ==================================================================================================== ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at beginning of year $ 2,000 $ 2,000 $ 1,800 - ---------------------------------------------------------------------------------------------------- Additions: Charged to income: 2,349 1,935 1,805 Recoveries and adjustments (187) 67 263 - ---------------------------------------------------------------------------------------------------- 2,162 2,002 2,068 - ---------------------------------------------------------------------------------------------------- Less uncollectible accounts written off 1,177 2,002 1,868 - ---------------------------------------------------------------------------------------------------- BALANCE AT END OF YEAR $ 2,985 $ 2,000 $ 2,000 ====================================================================================================
39 EX-10.(E) 2 EXECUTIVE RETIREMENT AGREEMENT 1 EXHIBIT 10(e) EXECUTIVE RETIREMENT SUPPLEMENT AGREEMENT THIS EXECUTIVE RETIREMENT SUPPLEMENT AGREEMENT made effective as of _________________________ between Energen Corporation, a corporation (the "Company"), and ___________________________ (the "Executive"). R E C I T A L S The Executive has been employed by the Company and/or one or more of its subsidiaries for a number of years, and as an employee has provided capable executive leadership and management so as to enable the Company to operate efficiently and effectively. The Company and the Executive desire to enter into this Agreement to provide for payment to the Executive and the Executive's eligible spouse certain deferred compensation in the form of a retirement supplement under certain circumstances. NOW, THEREFORE, in consideration of the mutual promises of the parties and the parties agree as follows: ARTICLE 1 -- DEFINITIONS 1.1 Agreement: This document, including any attached schedules, and any amendments to the same. 1.2 Birthday: An anniversary of the Executive's birth regardless of whether the Executive survives to such anniversary. 1.3 Cause: Termination of employment by the Employer for "Cause" shall mean TERMINATION based on any of the following: (a) The willful and continued failure by the Executive to substantially perform such Executive's duties with the Employer (other than any such failure resulting from such Executive's incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to the Executive specifically identifying the manner in which such Executive has not substantially performed such Executive's duties; (b) The engaging by the Executive in willful misconduct which is demonstrably injurious to the Employer monetarily or otherwise; or (c) The conviction of the Executive of a felony. 1.4 Code: The Internal Revenue Code of 1986, as the same may from time to time be amended. 1 2 1.5 Committee: The Officers Review Committee of the Board of Directors of the Company or any person or persons appointed by the Board of Directors to administer the Agreement. 1.6 Compensation: The sum of A plus B. For purposes of this definition, A shall equal the average aggregate monthly basic pay from all Employers for the 36 consecutive calendar months during which the Executive had the highest average monthly basic pay out of the 60 calendar months immediately preceding the Severance Date. For purposes of this definition, B shall equal C divided by 12, where C equals the average of the Executive's three highest annual cash incentive awards under the Energen Annual Incentive Compensation Plan (or successor annual cash incentive plan) for the five Company fiscal years immediately preceding the earlier of (i) the fiscal year during which the Severance Date occurs or (ii) the fiscal year during which the Executive's 61st birthday occurs. 1.7 Disability: Total and permanent disability which entitles the Executive to a disability benefit under the disability program sponsored and/or maintained by the Company or the Executive's Employer. 1.8 Eligibility Date: The earliest date on which the Executive could be entitled to receive the Executive's "primary insurance amount" or any portion thereof under the federal Social Security Act as amended and in effect on the Severance Date assuming that the Executive survives to such date. 1.9 Employer: The Company and any and all subsidiaries of the Company and their respective successors and assigns. 1.10 Lump Sum Election: An election made by the Executive pursuant to Section 2.5 to receive a lump sum payment in lieu of the Supplemental Retirement Benefit. 1.11 Normal Retirement Date: The first day of the month on or next following the Executive's 60th Birthday; provided, however, if the Executive's employment with an Employer continues beyond such date, the first day of the month on or next following the date on which the Executive actually Retires shall be Normal Retirement Date. 1.12 Present Value: The present value of a benefit or benefits determined using the discount rate used to determine the present value of payments under Section 280G of the Code that is in effect at the date payment is to be made and the mortality assumptions utilized to determine actuarial equivalent benefits under the Retirement Plan at that date. 1.13 Retire or Retirement: Termination of employment (for whatever reason including death) from all Employers after attaining age 60. 1.14 Retirement Plan: The "Energen Corporation Retirement Income Plan," as the same may be amended and in effect from time to time hereafter. 2 3 1.15 Retirement Plan Benefit: The monthly amount of retirement benefit payable to the Executive from the Retirement Plan in the normal form, with no election of an optional form of payment, calculated under the terms of the Retirement Plan as in effect on the Severance Date and with the following assumptions: (i) the Executive will accrue no Years of Service or partial Years of Service under the Retirement Plan after the Severance Date; (ii) the first payment to the Executive under the Retirement Plan will be made on the first day of the month on or next following the later of the Executive's 60th Birthday or the Severance Date; and (iii) the Executive will live to the payment date described in the preceding clause (ii). 1.16 Service: The number of the Executive's completed months of continuous employment with the Employer ending on the Executive's Severance Date. 1.17 Service Factor: If the Executive has 240 or more months of Service then the Service Factor shall equal one (l). At any time prior to the time when the Executive has both earned a vested benefit under the Retirement Plan and been continuously employed by an Employer for five years, the Service Factor shall be 0. Except as otherwise provided in the foregoing sentences, the Service Factor shall be a fraction, the numerator of which shall be the number of the Executive's months of Service and the denominator of which shall be 240. 1.18 Severance Date: The earlier of (i) the first date on which (for whatever reason) the Executive is no longer employed by an Employer, or (ii) the date of termination of this Agreement pursuant to Article 3. 1.19 Social Security Benefit: The amount of the monthly benefit, as estimated by the Committee in a consistent and uniform manner, which, under the provisions of the federal Social Security Act as amended and in effect on the Severance Date, such Executive is, or will be, entitled to receive as the Executive's "primary insurance amount" or any portion thereof at the later of the Eligibility Date or the Normal Retirement Date assuming (i) that the Executive has or will make appropriate and timely application for such benefit, (ii) that no event has occurred or will occur by reason of which the amount of such benefit has been or will be delayed, suspended or forfeited in whole or in part, (iii) that if the Severance Date occurs prior to the Executive's 60th Birthday, the Executive will continue to receive, until the Executive's 60th Birthday, earnings at the Compensation rate taxable as wages by the Social Security Act, and (iv) that, after the later to occur of the Executive's 60th birthday or Normal Retirement Date, the Executive will have no further earnings taxable as wages by the Social Security Act. 1.20 Spouse: The spouse to whom the Executive was married at the date of the Executive's death and throughout the twelve-month period preceding the Executive's Severance Date. 1.21 Supplemental Retirement Benefit: The benefit described in Section 2.2. 1.22 Supplemental Spouse's Retirement Benefit: The benefit described in Section 2.3. 3 4 1.23 The masculine gender shall be deemed to include the feminine; the feminine to include the masculine; the singular to include the plural; and the plural to include the singular in each case where appropriate. ARTICLE 2 -- BENEFITS 2.1 Eligibility. The Executive and Spouse, as applicable, shall be entitled to the benefits described in Sections 2.2 and 2.3; provided, that no benefits shall be paid under this Agreement if (i) the Executive's employment by an Employer is terminated for Cause, or (ii) the Severance Date occurs for any reason before the Executive has both earned a vested benefit under the Retirement Plan and been continuously employed by an Employer for five years. 2.2 Supplemental Retirement Benefit. Subject to the other provisions of this Agreement, commencing on the Executive's Normal Retirement Date the Executive shall be entitled to receive a Supplemental Retirement Benefit, which shall be payable monthly during the Executive's life with the last payment being the payment made or due for the month in which the Executive dies. No benefit shall be payable under this Section 2.2 if the Executive dies on or before the Normal Retirement Date. The Supplemental Retirement Benefit shall be an amount equal to the product of "A" multiplied by the Service Factor. With respect to Supplemental Retirement Benefit payments made for periods commencing prior to the Eligibility Date, "A" shall equal the amount by which 60% of Compensation exceeds the Retirement Plan Benefit. With respect to Supplemental Retirement Benefit payments made for periods commencing on or after the Eligibility Date, "A" shall equal the amount by which 60% of Compensation exceeds the sum of the Retirement Plan Benefit plus the Social Security Benefit. If the Executive terminates employment due to Disability, (i) the period that the Executive receives disability benefits from a disability program sponsored or maintained by an Employer shall be treated as Service, and (ii) the Supplemental Retirement Benefit shall not commence, and the Executive shall not be deemed to have had a Severance Date, while the Executive is receiving disability benefits payable from a disability program sponsored or maintained by an Employer. For purposes of this Section 2.2, reclassification under the Retirement Plan from Disability Retirement to Retirement shall constitute cessation of disability benefits. 2.3 Supplemental Spouse's Retirement Benefit. (a) Subject to the other provisions of this Agreement, following the Executive's death the surviving Spouse shall be entitled to a Supplemental Spouse's Retirement Benefit, which shall be payable monthly commencing on the later of (i) the first day of the month following the month of the Executive's death or (ii) the first day of the month of the Executive's 55th Birthday, and continuing until the Spouse's death. The Supplemental Spouse's Retirement Benefit shall be an amount equal to 50% of the monthly Supplemental Retirement Benefit which the Executive would have been entitled to receive had death not occurred (based on Service through the 4 5 Severance Date and adjusting on the Eligibility Date); provided that if the Executive's death occurs after the Severance Date, for each of the first three months following the Executive's death the Supplemental Spouse's Retirement Benefit shall be 100% of such amount. (b) If the Executive shall die while a Lump Sum Election is in effect and while the Executive is still employed by the Employer, the surviving Spouse shall receive in lieu of the benefit described in Section 2.3(a) above, a lump sum payment equal to one-half of the Present Value of the Supplemental Retirement Benefit which the Executive would have been entitled to receive based on Service through the Severance Date if the Executive had survived to the Normal Retirement Date. Such benefit shall be paid as promptly as practicable after the Executive's death and, in all events, within forty-five (45) days after the Executive's death. For purposes of this Section 2.3(b), the determination of whether a Spouse has survived the Executive shall be made in accordance with the provisions of Section 43-8-43 of the Code of Alabama of 1975, as the same may from time to time be amended (as of the date of this Agreement, Section 43-8-43 generally treats a person as having predeceased a decedent unless the person survives the decedent by five days). (c) If the Executive shall die after the Severance Date, while a Lump Sum Election is in effect, and prior to receipt of the lump sum payment, the lump sum benefit shall be payable to the Executive's estate and no Supplemental Spouse's Retirement Benefit shall be payable to the surviving Spouse, if any. (d) If the Executive dies after payment of a lump sum pursuant to Section 2.5, no Supplemental Spouse's Retirement Benefit shall be payable to the Executive's surviving Spouse, if any. (e) No benefit shall be payable following the Executive's death except as provided in this Section 2.3. 2.4 Spouse's Age. If a Spouse who is entitled to a benefit under this Article 2 is more than ten (10) years younger than the Executive, any benefit payable to the Spouse under Section 2.3(a) (but not 2.3(b)) shall be reduced by 1/20 for each full year of age difference more than ten (10). 2.5 Payment Elections. (a) By checking the appropriate box on the signature page of this Agreement, the Executive may elect to receive, in lieu of the Supplemental Retirement Benefit to which the Executive will otherwise become entitled under Section 2.2 hereof, a lump sum payment that is the Present Value, as of the date payment is made, of such Supplemental Retirement Benefit. Such payment shall be made as promptly as practicable after the Executive's Severance Date and, in all events, within forty-five (45) days after such Severance Date. (b) By executing and filing with the Company a form substantially identical to Exhibit I hereof, or such other form as the Company may prescribe or approve, the 5 6 Executive may revoke an election made pursuant to paragraph (a) above or may make any election which could be made pursuant to such paragraph, but any such election or revocation of an election shall not become effective if the Executive's Severance Date occurs within one year from the date such revocation or election is made. 2.6 Leave of Absence. In the event the Executive is granted a leave of absence, the Executive's employment shall be deemed to continue and shall be treated as Service, during the period of such leave of absence unless specifically determined to the contrary by the Committee. ARTICLE 3 -- AMENDMENT OR TERMINATION OF AGREEMENT 3.1 Subject to Section 3.2 below, the Company reserves the right to terminate this Agreement at any time by action of its Board of Directors or the Committee, and the continuance of this Agreement is not guaranteed to the Executive. 3.2 No termination of this Agreement shall operate to reduce, cancel or void the Company's obligation to pay benefits provided for under this Agreement and accrued prior to the Severance Date. 3.3 This Agreement may be amended by written instrument executed by the Executive and by an officer of the Company thereunto duly authorized by the Board of Directors of the Company. ARTICLE 4 -- MISCELLANEOUS 4.1 This Agreement shall under no circumstances be deemed to have any effect upon the terms or conditions of employment of the Executive. The establishment and maintenance of this Agreement shall not be construed as creating or modifying any contract between an Employer and the Executive nor is it in lieu of any other benefits. This Agreement shall under no circumstances be deemed to constitute a contract of insurance. 4.2 This Agreement shall not give the Executive the right to be retained in the employ of an Employer or any right or interest hereunder other than as specifically provided herein. 4.3 Benefits under this Agreement shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge or encumbrance by the Executive or the Spouse and any attempt to so transfer or encumber the benefits shall be null and void. Benefits under this Agreement shall not be subject to or liable for the debts, contracts, liabilities, engagements or torts of the Executive or of the Spouse nor may the same be subject to attachment or seizure by any creditor of the Executive or the Executive's spouse under any circumstances. 6 7 4.4 In the event of the Executive's Retirement, Disability or death, the Executive or the Executive's Spouse, as the case may be, should notify the Committee promptly, and the Committee will then provide a Claimant's statement form for completion which should be returned to the Committee together with evidence of Disability or with an official death certificate, if applicable. In the event that any claim hereunder is denied, the Committee will provide adequate notice in writing to the Executive or Spouse, setting forth the specific reasons for such denial and, in addition, the Committee will afford a reasonable opportunity for a full and fair review of those reasons. IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer and the Executive has hereunto set his/her hand and seal all as of the day and year first above written. ENERGEN CORPORATION By: ------------------------------------ Its: ----------------------------------- EXECUTIVE ---------------------------------------- ELECTION [ ] I hereby elect to have my benefit paid as provided in Section 2.2 of this Agreement. [ ] Pursuant to Section 2.5 of this Agreement, I hereby elect to have my benefit paid in a lump sum. 7 8 EXHIBIT I ELECTION PURSUANT TO EXECUTIVE RETIREMENT SUPPLEMENT AGREEMENT I hereby revoke any and all elections heretofore made by me pursuant to the terms of that certain Executive Retirement Supplement Agreement entered into by and between Energen Corporation and myself dated as of ________________, and elect to have my benefit [ ] paid as provided in Section 2.2 of such Agreement. [ ] paid in a lump sum pursuant to Section 2.5 of such Agreement. I understand that the foregoing election (and revocation, if applicable), will not become effective if my Severance Date occurs within one-year from the date of acceptance indicated below. ---------------------------------------- EXECUTIVE ---------------------------------------- Accepted by: ENERGEN CORPORATION ---------------------------------------- By: ---------------------------------- Its: ---------------------------------- Date: ---------------------------------- 8 EX-10.(G) 3 SEVERENCE COMPENSATION AGREEMENT 1 EXHIBIT 10(g) SEVERANCE COMPENSATION AGREEMENT THIS AGREEMENT ("Agreement") is made and entered into as of the ____ day of _________, 199_, by and between ENERGEN CORPORATION, an Alabama corporation ("Energen"), and _______________________________, ("Executive"). W I T N E S S E T H: WHEREAS, Executive is an effective and valuable employee of Energen and/or one or more of its subsidiaries; WHEREAS, Executive desires certain assurances with respect to any change in control of Energen; WHEREAS, Energen recognizes that the uncertainties involved in a potential or actual change in control of Energen could result in the distraction or departure of management personnel such as Executive to the detriment of Energen and its shareholders; and WHEREAS, Energen desires to lessen the personal and economic pressure which a potential or actual change in control may impose on Executive and thereby facilitate Executive's ability to bargain successfully for the best interests of Energen's shareholders in the event of such a change in control; NOW, THEREFORE, in consideration of the premises and the mutual agreements herein contained, Energen and Executive hereby agree as follows: Section 1. Definitions. As used in this Agreement the following words and terms shall have the following meanings: (a) "Applicable Period" means the period commencing with the earliest date that a Change in Control occurs and ending on the last day of the thirty-sixth calendar month following the calendar month during which such Change in Control occurred. Anything in this Agreement to the contrary notwithstanding, if a Change in Control occurs, and if the Date of Termination with respect to Executive's employment with Energen occurs prior to the date on which the Change in Control occurs, and if it is reasonably demonstrated by Executive that such termination of employment (i) was at the request of a third party who has taken steps reasonably calculated to effect the Change in Control or (ii) otherwise arose in connection with or in anticipation of the Change in Control, then for all purposes of this Agreement the "Applicable Period" shall be deemed to have commenced on the date immediately preceding the Date of Termination. 2 (b) "Cause". Termination of employment by Employer for "Cause" shall mean termination based on any of the following: (1) The willful and continued failure by the Executive to substantially perform Executive's duties with Employer (other than any such failure resulting from Executive's incapacity due to physical or mental illness) after a written demand for substantial performance is delivered to Executive specifically identifying the manner in which Executive has not substantially performed Executive's duties; (2) The engaging by Executive in willful misconduct which is demonstrably injurious to Employer monetarily or otherwise; or (3) The conviction of Executive of a felony. (c) "Change in Control" means the occurrence of any one or more of the following: (1) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a "Person") of beneficial ownership (within the meaning of Rule 13(d)-3 promulgated under the Exchange Act) of 25% or more of either (i) the then outstanding shares of common stock of Energen (the "Outstanding Common Stock") or (ii) the combined voting power of the then outstanding voting securities of Energen entitled to vote generally in the election of directors (the "Outstanding Voting Securities"); provided, however, that for purposes of this subsection (1) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by Energen or any corporation controlled by Energen shall not constitute a Change in Control; (2) Individuals who, as of June 1, 1996, constitute the Board of Directors of Energen (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board of Directors of Energen (the "Board of Directors"); provided, however that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by Energen's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board of Directors; (3) Consummation of a reorganization, merger or consolidation involving, or sale or other disposition of all or substantially all of the assets of, Energen (a "Business Combination"), in each case, unless, following such Business Combination, (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Common Stock and Outstanding Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 75% of, respectively, the then outstanding shares of common stock and the combined voting power of the then 2 3 outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns Energen or all or substantially all of Energen's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Common Stock and Outstanding Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of Energen or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 25% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board of Directors, providing for such Business Combination; (4) The occurrence of one transaction or a series of transactions, which has the effect of a divestiture by Energen of 25% or more of the combined voting power of Alabama Gas Corporation's outstanding voting securities; (5) 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 Alabama Gas Corporation (other than to Energen or an entity controlled by Energen); or (6) Any transaction or series of transactions which is expressly designated by resolution of the Board of Directors to constitute a Change in Control for purposes of this Agreement. (d) "Code" means the Internal Revenue Code of 1986, as the same may be from time to time amended. (e) "Compensation" means an amount equal to the sum of (A) plus (B), where (A) is the Executive's annualized base salary in effect at the time of a Change in Control, and (B) is the highest annual bonus awarded Executive by Employer pursuant to the Energen Annual Incentive Compensation Plan (or any successor annual cash incentive plan) with respect to the three (3) fiscal years immediately preceding the fiscal year in which the Change in Control occurs. (f) "Date of Termination" means the date that a termination of Executive's employment with Employer is first effective. (g) "Disability" means the total and permanent disability which entitles Executive to a disability benefit under a disability program sponsored and/or maintained by Energen. (h) "Employer" means Energen and its Subsidiaries. 3 4 (i) "Excess Parachute Payment" shall have the same meaning as the term "excess parachute payment" defined in Section 280G(b)(1) of the Code. (j) "Exchange Act" means the Securities Exchange Act of 1934, as amended. (k) "Good Reason" means the occurrence during an Applicable Period of any of the following events without Executive's prior written consent: (1) The assignment to Executive by Employer of duties inconsistent with Executive's position, authority, duties, responsibilities and status with Employer immediately prior to a Change in Control, or a change in Executive's titles or offices as in effect immediately prior to a Change in Control, or any removal of Executive from or any failure to reelect Executive to any of such positions, if such assignment, change, or removal results in a diminution in Executive's position, authority, duties, responsibilities or status with Employer immediately prior to a Change in Control or any other action by Employer that results in such a diminution in Executive's position, authority, duties, responsibilities or status; (2) A reduction in Executive's aggregate rate of monthly base pay from the Employer; (3) The termination or material adverse modification of the Energen Annual Incentive Compensation Plan or the Energen Corporation 1996 Long-Range Performance Share Plan (or any other short or long-term incentive compensation plan in effect immediately prior to a Change in Control) without substitution of new short or long-term incentives providing comparable compensation opportunities for Executive. (4) A failure by Employer to use its best efforts to provide Executive with either the same fringe benefits (including retirement benefits and paid vacations) as were provided to Executive immediately prior to a Change in Control or a package of fringe benefits that, though one or more of such benefits may vary from those in effect immediately prior to the Change in Control, is substantially comparable in all material respects to the fringe benefits (taken as a whole) in effect prior to a Change in Control; (5) Executive's relocation by Employer to any place more than 25 miles from the location at which Executive performed the substantial portion of Executive's duties prior to a Change in Control, except for required travel by Executive on Employer's business to an extent substantially consistent with Executive's business travel obligations immediately prior to such Change in Control; (6) Any material breach by Energen of any provision of this Agreement or any other agreement between Energen and Executive which breach continues for a period of thirty days following delivery by Executive to Energen of written notice of such breach. 4 5 (l) "Independent Auditor" means the firm of certified public accountants which at the time of the Change in Control had been most recently engaged by Energen to prepare Energen's audited financial statements, or any other firm of certified public accountants mutually agreeable to Energen and Executive. (m) "Notice of Termination" has the meaning set forth in Section 2(a) of this Agreement. (n) ""Parachute Payment" shall have the same meaning as the term "parachute payment" defined in Section 280G(b)(2) of the Code. (o) "Qualified Termination" shall mean (1) during a Window Period, any termination (including Retirement) of Executive's employment, other than for Cause, death or Disability, and (2) during the Applicable Period but not during a Window Period, (i) any termination by Employer of Executive's employment other than for Cause, (ii) a termination of Executive's employment which Executive and Energen agree in writing will constitute a Qualified Termination for purposes of this Agreement, and (iii) a voluntary termination of Executive's employment by Executive for Good Reason. (p) "Reasonable Compensation" shall have the same meaning as provided for the term "reasonable compensation" in Section 280G(b)(4) of the Code. (q) "Retirement" means termination of Executive's employment (other than for Good Reason) by the Executive on or after Executive's having reached age 60. (r) "Subsidiary" means any corporation, the majority of the outstanding voting stock of which is owned directly or indirectly, by Energen. (s) "Window Period" shall mean the 30-day period immediately following the first anniversary of a Change in Control. Section 2. Notice of Termination. During any Applicable Period: (a) Any termination (other than for Retirement, death or Disability) of Executive's employment, whether by Employer or Executive, shall be communicated by the terminating party transmitting or sending the other party a written notice ("Notice of 5 6 Termination") referencing this Agreement and, if such termination is for Cause or Good Reason, indicating in reasonable detail the facts and circumstances providing a basis for such termination. The failure of Executive or Employer to set forth in the Notice of Termination any fact or circumstance which contributes to a showing of Good Reason or Cause shall not waive any right of Executive or Energen hereunder or preclude Executive or Energen from asserting or relying upon the omitted fact or circumstance in enforcing Executive's or Energen's rights hereunder. (b) Subject to (c) below, such termination of Executive's employment shall be effective upon delivery of a Notice of Termination or at such later date as may be specified in the Notice of Termination. (c) In the event that each party delivers a Notice of Termination, the Notice of Termination first delivered shall establish the effective date of such Notice of Termination. Section 3. Severance Payment. In the event of a Qualified Termination, then Executive shall, subject to the provisions of Sections 5 and 8 hereof, receive as severance pay an amount equal to his Compensation multiplied by a factor of [1.5 or 2 or 2.5]. Subject to Section 5 hereof, any severance payment to be made under this Section 3 shall be paid in one payment and in full on or prior to the thirtieth day following the Date of Termination. Section 4. Other Benefits. Subject to Sections 5 and 8 hereof, in the event of a Qualified Termination (other than Retirement), for a period of twenty-four months commencing with the Date of Termination, Executive and the Executive's family shall continue to be covered at the expense of Energen by the same or substantially equivalent hospital, medical, dental, vision, accident, disability and life insurance coverages as were provided to Executive and the Executive's family by Employer immediately prior to the Change in Control; provided, however, that if Executive becomes employed with another employer and is eligible to receive benefits of the type described above from such other employer, Energen's obligations under this Section 4 and the benefits described herein shall be secondary to those provided by such other employer. Section 5. Limitation on Benefits. (a) Basic Rule. Except as otherwise provided in paragraph (c) below, any benefits payable or to be provided to the Executive by Employer, whether pursuant to this Agreement or otherwise (including, without limitation, Awards under the Energen Corporation 1992 or 1996 Long-Range Performance Share Plans), which constitute Parachute Payments shall be modified or reduced as provided in paragraph (b) below to the extent necessary so that the benefits payable or to be provided to Executive under this Agreement that constitute Parachute Payments, as well as any payments or benefits provided outside of this Agreement that constitute Parachute Payments, shall not cause Employer to have paid an Excess Parachute Payment. All provisions of Section 280G of the Code, and the regulations (proposed, interim, or final) thereunder, shall be taken into account in computing such amount, including making appropriate adjustment to such calculation for amounts established to be Reasonable Compensation. 6 7 (b) Reductions. In the event that the amount of any Parachute Payment otherwise payable to or for the benefit of the Executive must be modified or reduced to comply with paragraph (a) above, the Executive shall direct which Parachute Payments are to be modified or reduced; provided, however, that no increase in the amount of any payment or any change in the timing of payment shall be made without the consent of Energen. (c) Optimization. Prior to the first date any Parachute Payment is due to be made, Energen shall, at its own expense, cause the Independent Auditor to determine whether X exceeds Y, where (i) X is the total amount of Parachute Payments that would be made to the Executive, whether pursuant to this Agreement or otherwise, if the limitation provided for in paragraph (a) above were not applied, reduced by the total amount of applicable federal, state, and local income, payroll and excise taxes that would be payable by the Executive with respect to such Parachute Payments, and (ii) Y is the total amount of Parachute Payments that would be payable to the Executive, whether pursuant to this Agreement or otherwise, if the limitation provided for in paragraph (a) above were applied, reduced by the total amount of applicable federal, state and local income, payroll and excise taxes that would be payable by the Executive with respect to such Parachute Payments. If X exceeds Y, then the limitation provided for in paragraph (a) above shall not apply. For purposes of making the determination provided for in this paragraph (c), the Independent Auditor shall assume that all Parachute Payments to be made to the Executive will be subject to federal income tax at the maximum rate in effect at the time the determination is made unless the Executive provides the Independent Auditor with evidence satisfactory to the Independent Auditor that it is more probable than not that one or more Parachute Payments will be taxable at a lower rate, or lower rates, in which case the Independent Auditor shall assume that such Parachute Payments will be taxed at the lower rate or rates. (d) Subsequent Payments. As a result of various incentive or other plans, Executive may be entitled to receive various Parachute Payments over a period of several years. In such event, the Independent Auditor may need to update its Section 5(c) calculations one or more times. In the event that all or a portion of a Parachute Payment is not made due to the limitations of this Section 5, Energen shall not be relieved of liability for such amount but such Parachute Payment shall be deferred and included in calculations with respect to subsequent Parachute Payments. (e) Overpayments and Underpayments. As a result of uncertainty in the application of section 280G of the Code at the time of determinations by the Independent Auditor hereunder, uncertainties in the valuation of future payments, and deferrals pursuant to Section 5(d), it is possible that Parachute Payments will have been made by Energen which should not have been made (an "Overpayment") or that additional Parachute Payments which will not have been made by Energen could have been made (an "Underpayment"), consistent in each case 7 8 with the other provisions of this Section 5. In the event that the Independent Auditor, based upon the assertion of a deficiency by the Internal Revenue Service against Energen or the Executive which the Independent Auditor believes has a high probability of success, determines that an Overpayment has been made, such Overpayment shall be treated for all purposes as a loan to the Executive which the Executive shall repay to Energen, together with interest at the applicable federal rate provided for in section 7872(f)(2)(A) of the Code; provided, however, that no amount shall be payable by the Executive to Energen if and to the extent that such payment would not reduce the amount which is subject to taxation under section 4999 of the Code. In the event that the Independent Auditor determines that an Underpayment has occurred, such Underpayment shall promptly be paid or transferred by Energen to or for the benefit of the Executive, together with interest at the applicable federal rate provided for in section 7872(f)(2)(A) of the Code. Section 6. No Obligation To Seek Further Employment; No Effect on Other Benefits. (a) Executive shall not be required to seek other employment, nor (except as otherwise provided under Section 4 with respect to insurance coverages) shall the amount of any severance payment or other benefit to be made or provided under this Agreement be reduced by any compensation or benefit earned by Executive as the result of employment by another employer after the Date of Termination, or otherwise. (b) Subject to Section 5 hereof, any severance payment or benefit to be made or provided under this Agreement is in addition to all other benefits, if any, to which Executive may be entitled under other agreements, plans or programs of Energen. Section 7. Continuing Obligations of Executive. As a result of and in connection with Executive's employment by Employer, Executive is involved in a number of matters of strategic importance and value to Employer including various projects, proceedings, planning processes, and negotiations. Any number of these matters may be ongoing and continuing after the Date of Termination. In addition Employee is privy to proprietary and confidential information of Employer including without limitation, financial information and projections, business plans and strategies, customer and vendor lists and information, and oil and gas properties and prospects. The Executive agrees as follows: (a) Consulting Services. For a period of three years following the Date of Termination, Executive agrees to fully assist and cooperate with Employer and its representatives (including outside auditors, counsel and consultants) with respect to any matters with which the Executive was involved during the course of employment with Employer, including being available upon reasonable notice for interviews, consultation, and litigation preparation. Except as otherwise agreed by Executive, Executive's obligation under this Section 7 (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 Employer but scheduled to accommodate Executive's reasonable scheduling requirements. Executive shall receive no additional fee for such services but shall be reimbursed all reasonable out-of-pocket expenses. 8 9 (b) Non-Compete. For a period of twelve months following the Date of Termination, the Executive shall not Compete, (as defined below) or assist others in Competing with the Employer. For purposes of this Agreement, "Compete" means (i) solicit in competition with Alabama 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 Employer does not constitute Competition by Executive so long as Executive does not directly participate in, assist or advise with respect to such Competition. (c) Confidentiality. Executive agrees that at all times following the Date of Termination, Executive will not, without the prior written consent of Energen, disclose to any person, firm or corporation any confidential information of Employer which is now known to Executive or which hereafter may become known to Executive as a result of Executive's employment or association with Employer, 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. Section 8. Board Resignation. Energen shall have no obligation under Sections 3 and 4 hereof if Executive shall not, promptly after the Date of Termination and upon receiving a written request to do so, resign from each officer and/or director position which Executive then holds with Energen and any Subsidiary. Section 9. Payment of Professional Fees and Expenses. Energen agrees to pay promptly as incurred, to the full extent permitted by law, all legal, accounting and other professional fees and expenses which Executive may reasonably incur (i) as a result of any contest (regardless of the outcome thereof) by Energen, Executive or others of the validity or enforceability of, or liability under, any provision of this Agreement or any guarantee of performance thereof (including as a result of any contest by Executive about the amount of any payment pursuant to this Agreement); plus in each case interest on any delayed payment at the applicable Federal rate provided for in Section 7872(f)(2)(A) of the Code; or (ii) as a result of any contest by a taxing authority of Executive's tax treatment of any amounts received under this or any other Employer agreement or plan to the extent such tax treatment is consistent with the determinations made by the Independent Auditor under Section 5. Section 10. Term. This Agreement shall terminate (except to the extent of any unpaid or unfulfilled obligation with respect to a prior termination of Executive's employment) on the first to occur of (i) any termination of Executive's employment with Employer which does not constitute a Qualified Termination or (ii) expiration of the Term. The initial "Term" of this Agreement shall be for a period of three years from the date hereof. On each anniversary of the date hereof, the Term shall automatically extend by one year unless at least thirty days prior to such an anniversary Energen notifies Executive that there will be no such extension, in which event the term shall continue until the later to occur of (i) two years from such anniversary or (ii) three years from the date of the most recent Change in Control, if any. 9 10 Section 11. Binding Effect; Successors. (a) This Agreement shall be binding upon and inure to the benefit of Executive and Executive's personal representative and heirs, and Energen and its successors and assigns including any successor organization or organizations which shall succeed to substantially all of the business and property of Energen, whether by means of merger, consolidation, acquisition of assets or otherwise, including operation of law. (b) Without the prior consent of Energen, Executive may not assign the Agreement, except by will or the laws of descent and distribution. Section 12. Notice. For purposes of this Agreement, notices and all other communications provided for in this Agreement shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, as follows: If to Energen or Employer: Energen Corporation 2101 Sixth Avenue North Birmingham, Alabama 35203 Attention: Chairman If to Executive: ------------------------------ ------------------------------ ------------------------------ or such other address as either party may have furnished to the other in writing in accordance herewith, except that notices of change of address shall be effective only upon receipt. Section 13. Miscellaneous. No provisions of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing signed by Executive and Energen. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly in this Agreement. This Agreement shall be governed by and construed in accordance with the laws of the State of Alabama. Section 14. Validity. The invalidity or unenforceability of any provisions of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect. 10 11 Section 15. Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument. Section 16. Amendment and Restatement of Prior Agreement. This agreement constitutes a complete amendment and restatement and fully supersedes that certain Severance Compensation Agreement between the parties dated ____________________, 19__. IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written. ENERGEN CORPORATION By ------------------------------------- Its ------------------------------------- EXECUTIVE ---------------------------------------- 11 EX-13 4 RESULTS OF OPERATIONS AND FINANCIAL CONDITION 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 1996 fiscal year was $21.5 million, or $1.95 per share. This represented a 10 percent increase in per share earnings over prior year net income of $19.3 million, or $1.77 per share, and resulted from the continued financial and operating strength of Alabama Gas Corporation's (Alagasco's) utility operations combined with significant growth at Taurus Exploration Inc. (Taurus), Energen's nonregulated oil and gas subsidiary. In 1994 Energen reported earnings of $23.8 million, or $2.19 per share, including a one-time gain of $2 million, or 18 cents per share, for the sale of propane assets and a reduction in investment in high temperature combustion technology. 1996 VS 1995: Alagasco achieved record net income for a sixth consecutive year, increasing to $17.0 million over prior-year earnings of $15.7 million. This 8 percent growth in income reflected the utility's ability to earn within its allowed range of return on an increased level of equity. Fiscal 1995 earnings included a one-time after-tax charge of $503,000 resulting from a voluntary early retirement program. Taurus's net income grew 28.5 percent to $4.5 million 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. 1995 VS 1994: Alagasco's 1995 net income of $15.7 million increased 5.4 percent over 1994 net income of $14.9 million primarily due to the utility earning for a full year on a higher level of equity generated by a $21 million investment in underground storage working gas made in 1994; the utility received a $10 million equity infusion from Energen to help fund the investment. The one-time charge for the voluntary early retirement program in fiscal 1995 partially offset this increase. Taurus earned net income of $3.5 million in 1995, a decrease of 46 percent from 1994. The major factor negatively affecting Taurus's earnings was comparatively lower natural gas commodity prices which affected Taurus's gas production revenues as well as income from price-sensitive coalbed methane operating fees. Taurus's 1995 earnings also were negatively impacted by increased operating and DD&A expenses. OPERATING INCOME Consolidated operating income in 1996, 1995, and 1994 totaled $38.8 million, $32.0 million and $35.3 million, respectively. In the current year, operating income was influenced significantly by Taurus as it implemented Energen's growth strategy and recognized a gain on the sale of reserves. Growth in Alagasco's operating income was consistent with its increased level of equity. Operating income in 1995 was impacted by lower natural gas commodity prices and increased operating expense at Taurus. 23 2 ALAGASCO: Alagasco generates revenues through the sale and transportation of natural gas. Shifts between transportation and sales gas can cause large 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 $326.8 million, $265.5 million, and $315.3 million in 1996, 1995, and 1994, respectively. Several factors contributed to the 23 percent current-year increase in sales revenues including the influence of significantly colder weather on total throughput and higher commodity gas costs passed through to customers in rates. As a result of Alagasco's temperature adjustment mechanism, however, the margins associated with the colder weather were removed via an adjustment to customer bills. In 1995 pricing and weather had the opposite impact as lower prices and warmer weather resulted in substantially lower revenues. Alagasco's coldest winter in 18 years coupled with steady demand for commercial and industrial sales and transportation volumes led to a new gas throughput record of 111 Bcf in 1996. Residential sales volumes increased 27 percent in the current year as weather in Alagasco's service area was 13 percent colder than normal and 40 percent colder than the prior year. Sales and transportation volumes to commercial and industrial customers totaled 76.5 Bcf in 1996 and 74 Bcf in 1995. While volumes to large customers remained relatively stable, small commercial and industrial customers, more sensitive to weather, experienced volume increases similar to residential customers. In 1995 residential volumes decreased significantly due to weather which was 19 percent warmer than normal. The addition of several large customers that year resulted in a 12 percent increase in throughput to commercial and industrial customers. Higher commodity gas cost and higher sales volumes resulting from the cold weather in fiscal 1996 generated a 36 percent increase in cost of gas. Conversely, lower prices and sales volumes in a warm year created the significant decrease in 1995.
- ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (DOLLARS IN THOUSANDS) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Gross natural gas sales revenues ..................................... $ 326,844 $ 265,477 $ 315,317 Cost of natural gas ................................................... (181,400) (133,556) (188,592) Revenue taxes ....................................................... (20,055) (16,051) (20,018) - ----------------------------------------------------------------------------------------------------------------------- Net natural gas sales margin ......................................... 125,389 115,870 106,707 Net natural gas transportation margin ................................. 30,408 30,490 29,320 - ----------------------------------------------------------------------------------------------------------------------- Net natural gas sales and transportation margin ....................... $ 155,797 $ 146,360 $ 136,027 - ----------------------------------------------------------------------------------------------------------------------- Natural gas sales volumes (MMcf) Residential ....................................................... 34,963 27,489 31,254 Commercial and industrial-small ................................... 14,972 12,288 13,536 Commercial and industrial-large ................................... 30 29 106 - ----------------------------------------------------------------------------------------------------------------------- Total natural gas sales volumes ..................................... 49,965 39,806 44,896 Natural gas transportation volumes (Mmcf) ........................... 61,458 61,640 52,635 - ----------------------------------------------------------------------------------------------------------------------- Total deliveries (Mmcf) ............................................... 111,423 101,446 97,531 - ----------------------------------------------------------------------------------------------------------------------
24 3 Several items contributed to the 5 percent increase in operations and maintenance (O&M) expense at the utility in 1996. Distribution expenses, which include labor and maintenance costs, increased as a result of colder-than-normal weather. Secondly, to reflect its increased exposure from higher commodity gas costs in accounts receivable, Alagasco increased its provision for doubtful accounts. Thirdly, the utility increased its marketing efforts over the previous year. Partially offsetting these items was the inclusion in the prior year and the resulting savings in the current year of expense associated with an early retirement option. On a per customer basis, the increase in O&M fell within the inflation-based cap established by the Alabama Public Service Commission (APSC) as part of the utility's rate-setting mechanism. In 1995 increased labor and related expenses, including the early retirement charge, created the majority of the 7 percent increase. As a result of these costs, O&M expense per customer exceeded the cap and a portion of the excess was returned to customers. Consistent with growth in the utility's depreciable base, depreciation expense rose 9.8 percent in 1996 and 8 percent in 1995. 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 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. TAURUS: Revenues from oil and gas production activities grew notably in the first year of Taurus's aggressive growth strategy. Total production volumes rose 60 percent to 16.1 Bcfe and included production from new acquisitions as well as the addition of prior-year offshore discoveries. Natural gas production, including coalbed methane, increased 43 percent to 12.3 Bcf. Oil volumes increased to 635 MBbl from 250 MBbl. Higher oil and gas prices magnified the impact of increased production. Gas prices rose 14.5 percent to $1.97 per Mcf, while oil prices increased 8 percent to $16.25 per barrel. Reflected in those prices is the effect of Taurus hedging or placing under contract 66 percent of its production at an average price of $2.00 per Mcf and $18.30 per barrel, before consideration of any related basis differential. Coalbed methane operating fees represent a percentage of net proceeds on certain coalbed methane 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 in 1996 increased 14 percent to $3.8 million largely due to higher natural gas prices. Coalbed methane consulting revenues decreased significantly in the current year as Taurus completed several contracts. Under Energen's aggressive growth strategy, Taurus may, in the ordinary course of business, be involved in the sale of both developed and undeveloped properties as a revenue source. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of marginal assets, and accepting offers where the buyer gives greater value to a property than Taurus's technical staff. The largest of several property sales in 1996 occurred in September when Taurus recorded a $3.2 million gain after selling its working interest in reserves associated with PMC Reserve Acquisition Company. 25 4
- ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (DOLLARS IN THOUSANDS, EXCEPT UNIT PRICE) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Revenues Natural gas production ............................................... $24,262 $14,748 $17,292 Oil production ....................................................... 10,313 3,765 2,725 Operating and consulting fees ....................................... 4,100 4,373 5,194 Other ............................................................... 3,949 769 -- - ----------------------------------------------------------------------------------------------------------------------- Total Revenues ......................................................... $42,624 $23,655 $25,211 - ----------------------------------------------------------------------------------------------------------------------- Production volumes Natural gas (Mmcf) ................................................... 12,308 8,597 9,169 Oil (Mbbl) ........................................................... 635 250 191 - ----------------------------------------------------------------------------------------------------------------------- Average unit sales price Natural gas (per Mcf) ............................................... $ 1.97 $ 1.72 $ 1.89 Oil (per Bbl) ....................................................... $ 16.25 $ 15.07 $ 14.25 - -----------------------------------------------------------------------------------------------------------------------
Weak natural gas prices had the greatest impact on production revenues in fiscal 1995. Although Taurus hedged 65 percent of its natural gas production at $2.06 per Mcf (before basis differential), the average sales price was $1.72 per Mcf, a decline of 9 percent from the previous year. Production revenues also were affected by a 6 percent decrease in volumes resulting from lower offshore production caused in part by the timing of production schedules. Oil revenues benefitted from an increase in volumes and prices. Operating fees were $1.1 million lower in 1995 primarily due to lower prices. Consulting fees were slightly higher due to the inclusion of revenues from a new contract. Also included in 1995 revenues was a $769,000 gain associated with the buy out of a long-term sales contract. Operations expense increased $4.3 million in 1996 primarily due to Taurus's acquisition and exploration strategy. Lease operating expense was significantly higher because of current-year acquisitions plus an entire year's activity related to fiscal 1995 acquisitions. Additionally, exploration expense increased as a result of Taurus's expanded exploratory efforts. In 1995 operations expense increased $3 million primarily due to increased labor and related expense, exploration expense and administrative expense. DD&A expense rose $9.6 million from the prior year largely due to increased production (16.1 Bcf in 1996 compared to 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. For 1995 the 8 percent increase in DD&A was due largely to an increased average depletion rate ($0.78 per Mcf in 1994) associated with downward reserve revisions. OTHER ACTIVITIES AND INTERCOMPANY ELIMINATIONS: Operating income from Energen's group of other activities did not vary significantly in 1996. The notable decrease in 1995 was due almost exclusively to the absence of contribution from propane activities following the sale of the Company's propane assets in June 1994. Intercompany eliminations relate to intercompany natural gas sales and vary based on pricing and volumes. 26 5 NON-OPERATING ITEMS CONSOLIDATED: Fiscal 1996 interest expense increased $2.2 million primarily due to the financing of Taurus's aggressive acquisition strategy, largely through the use of the Company's short-term credit facilities. The average daily outstanding balance under the short-term credit facilities was $38 million compared to $0.9 million in the prior year. Also influencing the current year was interest for a full year on $50 million of medium-term notes (MTNs) issued in mid-1995 and, to a lesser degree, the issuance of $65 million of MTNs in the fourth quarter of fiscal 1996. Interest expense in 1995 increased 4 percent over 1994 due primarily to the $50 million of MTNs discussed above, offset to some degree by the repayment of $6.3 million of notes payable and lower average short-term debt outstanding. The decrease in total other income in the current year was largely due to the inclusion of the amortization of the early call premium associated with the redemption of debt in the prior year. Other income in 1995 decreased significantly from 1994 as a result of pre-tax gains associated with the 1994 sale of the Company's propane assets ($2.1 million) and the sale of the Company's investment in equity securities ($1.5 million). The Company's effective tax rates in 1996, 1995, and 1994 were lower than statutory federal tax rates primarily due to the recognition of nonconventional fuel tax credits and the amortization of investment tax credits. Changes in income tax expense in both years resulted primarily from changes in pre-tax income. 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. FINANCIAL POSITION AND LIQUIDITY The Company's net cash from operating activities totaled $52.5 million, $60.9 million, and $34.3 million in 1996, 1995, and 1994, respectively. Colder weather in 1996 impacted cash provided by operations 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 Southern Natural Gas Company and other suppliers in settlement of matters before the FERC (see Note 2 to the Consolidating Financial Statements) positively affected cash flows in the current year. The increase in operating cash flow in 1995 primarily is due to the net cash outflow of $23.5 million in 1994 to purchase storage gas at Alagasco. For both years, cash flow was affected by fluctuations in other receivables and payables which are generally the result of timing of payments. Cash used in investing activities increased $84.5 million and $39.6 million in 1996 and 1995, respectively, largely due to the implementation of Energen's diversified growth strategy. In 1996 Taurus invested $108 million in property acquisitions with development potential adding 178 Bcfe of proved developed and undeveloped oil and gas reserves. Current-year acquisitions include the $61 million purchase of 105 Bcf of coalbed methane reserves in Alabama. Prior-year acquisitions totaled $16.9 million and added 26.8 Bcfe to proved reserves. Taurus sold its entire working interest in reserves associated with the PMC acquisition venture in 1996 resulting in cash proceeds of $13.1 million. Proceeds of $13.4 million for the 1994 sale of both propane assets and equity securities contributed to the increase in cash used in 1995. Cash provided by financing activities totaled $80 million in 1996. The Company issued $40 million of MTNs redeemable September 20, 2001, to September 15, 2026, with interest rates ranging from 7.1 percent to 8.1 percent. The Company utilized 27 6 an additional $26.7 million in short-term credit facilities. Proceeds from these issuances were used to finance the acquisition strategy at Taurus. Also included in current-year financing activities were the proceeds from the issuance of $25 million in Alagasco MTNs redeemable December 1, 1998, to September 23, 2026, with interest rates ranging from 5.6 percent to 8 percent. These proceeds will be used for customer refunds (see Note 2 to the Consolidated Financial Statements), 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 defease a portion of its long-term debt (see Note 3 to the Consolidated Financial Statements). In 1994 cash provided by financing activities was $6.2 million and included the issuance of 550,000 shares of Energen common stock and $50 million in Alagasco MTNs. Proceeds from these issuances were used to fund the purchase of underground storage gas, redeem other long-term debt, and fund additional capital needs. CAPITAL EXPENDITURES NATURAL GAS DISTRIBUTION: During the last three fiscal years, Alagasco has invested $124.4 million for capital projects: $95.9 million was spent on normal expansion replacements and support of its distribution system; $14.6 million was used in connection with the development of a new customer information system; $6.5 million was used to improve gas availability; and $7.5 million was used to purchase five municipal gas systems.
- ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Capital expenditures for: Renewals, replacements, system expansion and other ................... $35,064 $30,611 $30,264 Additions to improve gas availability ............................... 1,799 3,024 1,644 Municipal gas system acquisitions ................................... 3,305 3,972 178 Customer information system ......................................... 3,007 5,173 6,387 - ----------------------------------------------------------------------------------------------------------------------- Total ............................................................. $43,175 $42,780 $38,473 - -----------------------------------------------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION: Taurus has spent $167.9 million for capital projects over the last three fiscal years, $7.8 million of which was charged to income as exploration expense. Expenditures for property acquisitions were $130.5 million, exploratory expenditures totaled $17.7 million, and $17.5 million was spent in development activities.
- ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Capital and exploration expenditures for: Property acquisitions ............................................... $110,008 $17,939 $2,541 Exploration ......................................................... 9,855 3,794 4,091 Development ......................................................... 10,040 6,044 1,438 Other ............................................................... 583 716 900 - ----------------------------------------------------------------------------------------------------------------------- Total ............................................................. $130,486 $28,493 $8,970 - ----------------------------------------------------------------------------------------------------------------------- Exploration expenditures charged to income (included above) ........... $ 4,169 $ 2,064 $1,614 - -----------------------------------------------------------------------------------------------------------------------
28 7 OTHER ACTIVITIES: Capital expenditures by Energen's other activities totaled $1.3 million in the last three fiscal years and primarily related to gathering activities. FUTURE CAPITAL RESOURCES AND LIQUIDITY Utility capital expenditures could approximate $37.6 million in 1997 and primarily represent additions for normal distribution system expansion. Alagasco also will maintain an investment in storage working gas which is expected to average approximately $24 million in 1997. Alagasco anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. The Company's strategy to dramatically grow its oil and gas exploration and production subsidiary involves investing $400 million in the acquisition of producing properties with development potential and $100 million in offshore Gulf of Mexico exploration and development in the five-year period ending September 30, 2000. During 1997 Taurus plans to invest $90 million in property acquisitions and in the development of existing reserves and $20 million in offshore exploration and development. It should be noted that Taurus's ability to invest in property acquisitions will be significantly influenced by industry trends as the producing property acquisition market has historically been cyclical. To finance Taurus's investment program, the Company initially will utilize short-term credit facilities of $156 million to supplement internally generated cash flow, but long-term debt and equity will be issued for permanent financing. During fiscal 1996, Energen filed a $250 million shelf registration for debt and common stock. MTNs of $40 million were issued in September 1996, and the Company plans to offer a combination of debt and equity during the second fiscal quarter of 1997. OUTLOOK NATURAL GAS DISTRIBUTION: A recent five-year extension of the utility's rate-setting mechanism gives Alagasco the opportunity to continue earning a return on average equity at year-end within a range of 13.15 percent to 13.65 percent. Alagasco has previously implemented and will continue to utilize flexible rate strategies to help compete effectively for large commercial and industrial customer load in the deregulated marketplace and combat fuel-switching and the threat of bypass of the distribution system. To supplement traditional service area growth, the utility will continue to pursue the acquisition of municipal gas systems in Alabama. Although residential unbundling is being considered by some in the industry as a potential means to improve efficiency and achieve market-driven pricing, Energen believes that electric and gas utility market competition in Alabama already fulfills that purpose for Alagasco; however, the Company will continue to assess the advisability of residential unbundling. EXPLORATION AND PRODUCTION: Taurus's oil and gas production is expected to increase 70 percent to more than 27 Bcfe in 1997. Seventy-two percent of production is expected to come from currently producing wells; another 17 percent should be generated by existing wells coming on-line during the year; and 11 percent is targeted from new acquisitions to be made in 1997. To hedge its exposure to price fluctuations, Taurus has entered into futures contracts or placed under sales contracts 70 percent of estimated gas production at an average price of $2.18 per Mcf. Taurus also has hedged more than half of its estimated oil production at $20.98 per barrel. Hedge prices do not reflect basis differential. Coalbed methane production during 1997 is expected to generate more than $6 million in tax credits. 29 8 OTHER: Certain of the statements set forth above contain forward-looking information. Such statements involve risks and uncertainties, and there are certain important factors that could cause actual results to differ materially from those anticipated. Some of these important factors include, but are not limited to, economic and competitive conditions, inflation, rates, regulatory changes, financial market conditions, future business decisions, and other uncertainties, all of which are difficult to predict and most of which are beyond the control of the Company. 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, including many factors beyond the control of the Company. As discussed in Note 12 to the Consolidated Financial Statements, the total amount or timing of actual future production may vary significantly from the amount of reserves disclosed. In the event Taurus is unable to fully invest its planned acquisition expenditures, operating revenues and proved reserves would be negatively affected. The Company's results of operations and cash flows also could be affected by changing oil and gas prices. Although Taurus makes use of futures contracts to mitigate risk, fluctuations in oil and gas prices may affect the Company's financial position. RECENT PRONOUNCEMENTS OF THE FASB During fiscal 1997, the Company is required to adopt two Statements issued in 1995 by the Financial Accounting Standards Board. Statement of Financial Accounting Standard (SFAS) No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, requires long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount for an asset may not be recoverable. Based on known facts and circumstances, its adoption is not expected to have a material impact on the Company's financial statements. SFAS No. 123,Accounting for Stock-Based Compensation, establishes a fair value-based method of accounting for employee stock options but allows companies to continue to follow the accounting treatment prescribed by APB Opinion 25 with proper disclosure. The Company has not yet determined the method of accounting that it will follow for stock options but does not expect the requirements of SFAS No. 123 to have a material impact on the Company's financial statements. In June 1996, SFAS No. 125, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, was issued and provides accounting and reporting standards for such transactions. The Company is required to adopt this Statement in fiscal 1998, and it is not expected to have a material impact on the Company's financial statements. QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
- ------------------------------------------------------------------------------------------------------------------------ QUARTER ENDED (IN DOLLARS) High Low Close Dividends Paid - ------------------------------------------------------------------------------------------------------------------------ December 31, 1994 ................................................... 22 3/4 19 3/4 22 .28 March 31, 1995 ..................................................... 23 1/2 20 5/8 22 7/8 .28 June 30, 1995 ....................................................... 23 1/4 20 1/8 21 1/2 .28 September 30, 1995 ................................................. 22 3/8 21 21 3/4 .29 - ------------------------------------------------------------------------------------------------------------------------ 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 - ------------------------------------------------------------------------------------------------------------------------
30 9 CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION AND SUBSIDIARIES - ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (IN THOUSANDS, EXCEPT SHARE DATA) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Natural gas distribution ................................................... $ 357,252 $ 295,967 $ 344,637 Oil and gas production activities ........................................... $ 42,624 23,655 25,211 Other ....................................................................... 2,158 2,298 8,810 Intercompany eliminations ................................................... (2,592) (3,340) (4,155) - ----------------------------------------------------------------------------------------------------------------------- Total operating revenues ............................................... 399,442 318,580 374,503 - ----------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas ................................................................. 178,810 130,220 184,458 Operations ................................................................. 100,822 93,293 89,829 Maintenance ................................................................. 11,078 9,849 9,469 Depreciation, depletion and amortization ................................... 41,118 29,556 27,976 Taxes, other than income taxes ............................................. 28,817 23,629 27,443 - ----------------------------------------------------------------------------------------------------------------------- Total operating expenses ............................................... 360,645 286,547 339,175 - ----------------------------------------------------------------------------------------------------------------------- OPERATING INCOME ........................................................... 38,797 32,033 35,328 - ----------------------------------------------------------------------------------------------------------------------- OTHER INCOME (EXPENSE) Interest expense, net of amounts capitalized ............................... (13,920) (11,693) (11,284) Gain on sale of assets ..................................................... -- -- 2,142 Other, net ................................................................. 1,712 2,649 4,176 - ----------------------------------------------------------------------------------------------------------------------- Total other income (expense) ........................................... (12,208) (9,044) (4,966) - ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES ................................................. $ 26,589 $ 22,989 $ 30,362 Income taxes ............................................................... 5,048 3,681 6,611 - ----------------------------------------------------------------------------------------------------------------------- NET INCOME ................................................................. $ 21,541 $ 19,308 $ 23,751 - ----------------------------------------------------------------------------------------------------------------------- EARNINGS PER AVERAGE COMMON SHARE ........................................... $ 1.95 $ 1.77 $ 2.19 - ----------------------------------------------------------------------------------------------------------------------- AVERAGE COMMON SHARES OUTSTANDING ........................................... 11,023,434 10,906,315 10,833,619 - -----------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 31 10 CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION AND SUBSIDIARIES - ----------------------------------------------------------------------------------------------------------------------- AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995 - ----------------------------------------------------------------------------------------------------------------------- ASSETS PROPERTY, PLANT AND EQUIPMENT Utility plant ............................................................................. $544,643 $504,371 Less accumulated depreciation ............................................................. 268,110 247,926 - ----------------------------------------------------------------------------------------------------------------------- Utility plant, net ................................................................... 276,533 256,445 - ----------------------------------------------------------------------------------------------------------------------- Oil and gas properties, successful efforts method ......................................... 224,469 117,339 Less accumulated depreciation, depletion and amortization ................................. 60,152 51,170 - ----------------------------------------------------------------------------------------------------------------------- Oil and gas properties, net ............................................................... 164,317 66,169 - ----------------------------------------------------------------------------------------------------------------------- Other property, net ....................................................................... 4,066 4,650 - ----------------------------------------------------------------------------------------------------------------------- Total property, plant and equipment, net ................................................. 444,916 327,264 - ----------------------------------------------------------------------------------------------------------------------- CURRENT ASSETS Cash and cash equivalents ................................................................. 17,074 36,695 Accounts receivable, net of allowance for doubtful accounts of $3,002 in 1996 and $2,533 in 1995 ................................................... 42,353 30,813 Inventories, at average cost Storage gas inventory ................................................................. 28,214 20,276 Materials and supplies ............................................................... 7,704 7,711 Liquified natural gas in storage ..................................................... 2,417 3,539 Deferred income taxes ..................................................................... 7,995 9,667 Prepayments and other ..................................................................... 9,538 10,330 - ----------------------------------------------------------------------------------------------------------------------- Total current assets ..................................................................... 115,295 119,031 - ----------------------------------------------------------------------------------------------------------------------- OTHER ASSETS Deferred charges and other ............................................................... 10,760 12,789 - ----------------------------------------------------------------------------------------------------------------------- Total other assets ................................................................... 10,760 12,789 - ----------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS ............................................................................. $570,971 $459,084 - -----------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 32 11
- ----------------------------------------------------------------------------------------------------------------------- AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995 - ----------------------------------------------------------------------------------------------------------------------- CAPITAL AND LIABILITIES 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, 11,162,634 shares outstanding in 1996 and 10,921,733 shares outstanding in 1995 ................................................................... 112 109 Premium on capital stock ................................................................. 86,833 81,243 Capital surplus ......................................................................... 2,802 2,802 Retained earnings ....................................................................... 98,658 90,020 Treasury stock, at cost (11,627 shares in 1995) ........................................... -- (250) - ----------------------------------------------------------------------------------------------------------------------- Total common shareholder's equity ....................................................... 188,405 173,924 Long-term debt ............................................................................. 195,545 131,600 - ----------------------------------------------------------------------------------------------------------------------- Total capitalization ................................................................... 383,950 305,524 - ----------------------------------------------------------------------------------------------------------------------- CURRENT LIABILITIES Long-term debt due within one year ......................................................... 1,805 1,775 Notes payable to banks ..................................................................... 59,000 32,300 Accounts payable ........................................................................... 32,659 32,242 Accrued taxes ............................................................................... 17,567 11,339 Customer's deposits ......................................................................... 17,364 18,218 Amounts due customers ....................................................................... 17,746 16,546 Accrued wages and benefits ................................................................. 11,584 10,955 Other ....................................................................................... 18,049 14,923 - ----------------------------------------------------------------------------------------------------------------------- Total current liabilities ............................................................... 175,774 138,298 - ----------------------------------------------------------------------------------------------------------------------- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes ....................................................................... 972 2,540 Other ....................................................................................... 10,275 12,722 - ----------------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities ........................................... 11,247 15,262 - ----------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES ............................................................... -- -- - ----------------------------------------------------------------------------------------------------------------------- TOTAL CAPITAL AND LIABILITIES ............................................................... $570,971 $459,084 - -----------------------------------------------------------------------------------------------------------------------
33 12 CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
ENERGEN CORPORATION AND SUBSIDIARIES - ---------------------------------------------------------------------------------------------------------------------------- (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, 1993 10,320,317 $103 $66,368 $2,802 $71,040 -- $ -- Net income 23,751 Shares issued for: Stock Offering 550,000 6 13,531 Dividend reinvestment plan 7,717 181 Employee benefit plans 39,870 993 Cash dividends -- $1.09 per share (11,749) - ---------------------------------------------------------------------------------------------------------------------------- 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 -- $ -- - ----------------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 34 13 CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION AND SUBSIDIARIES - ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net income ............................................................... $ 21,541 $19,308 $23,751 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization ............................... 41,118 29,556 27,976 Deferred income taxes, net ............................................. (672) (2,061) (2,802) Deferred investment tax credits, net ................................... (486) (487) (487) Gain on sale of assets ................................................. -- -- (2,142) Gain on sale of equity securities ..................................... -- -- (2,878) Net change in: Accounts receivable ................................................. (11,540) 3,332 1,523 Inventories ......................................................... (6,809) 3,775 (23,467) Deferred gas cost ................................................... (549) 34 1,505 Accounts payable gas purchases ....................................... (1,614) 9,882 1,220 Accounts payable trade ............................................... 2,031 (5,120) (1,349) Supplier refunds due customers ....................................... 13,942 2,483 92 Other current assets and liabilities ................................. (2,272) (3,290) 14,201 Other, net ............................................................. (2,233) 3,457 (2,800) - ----------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities ........................... 52,457 60,869 34,343 - ----------------------------------------------------------------------------------------------------------------------- INVESTING ACTIVITIES Additions to property, plant and equipment ............................... (168,414) (68,940) (45,543) Proceeds from sale of assets ............................................. 13,134 -- 8,624 Proceeds from sale of equity securities ................................... -- -- 4,808 Payments on notes receivable ............................................. 1,557 816 1,639 Other, net ............................................................... 1,627 501 2,485 - ----------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities ............................... (152,096) (67,623) (27,987) - ----------------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES Payment of dividends on common stock ..................................... (12,903) (12,330) (11,749) Issuance of common stock ................................................. 4,645 84 14,711 Purchase of treasury stock ............................................... (1,985) (2,721) -- Reduction of long-term debt ............................................... (1,025) (45,070) (12,470) Proceeds from issuance of long-term debt ................................. 64,586 49,660 49,670 Net change in short-term debt ............................................. 26,700 26,300 (34,000) - ----------------------------------------------------------------------------------------------------------------------- Net cash provided by financing activities ........................... 80,018 15,923 6,162 - ----------------------------------------------------------------------------------------------------------------------- Net change in cash and cash equivalents ................................... (19,621) 9,169 12,518 Cash and cash equivalents at beginning of period ......................... 36,695 27,526 15,008 - ----------------------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of period ............................... $ 17,074 $36,695 $27,526 - -----------------------------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 35 14 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ENERGEN CORPORATION AND SUBSIDIARIES 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, and in the exploration, production, acquisition and development of oil and gas in the continental United States. 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 4.3 percent in 1996, 1995 and 1994. The excess of total acquisition costs over book value of net assets acquired to date is included in utility plant ($23.2 million, net of $6.5 in accumulated amortization at September 30, 1996) and is being amortized on a straight-line basis over approximately 23 years. 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 PRODUCING ACTIVITIES 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 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. HEDGING: Taurus periodically enters into futures contracts to hedge its exposure to price fluctuations on oil and gas production. Gains and losses on futures contracts are recorded in the income statement as the hedged volumes are recognized. 36 15 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, 1996. Gains and losses on the sale of property in the ordinary course of business are classified as operating revenue; current year gains of $3.9 million were recorded. 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 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. 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 12). 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 for the fourth time on October 7, 1996, 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, an $8.2 million annual increase in revenue became effective December 1, 1995, and a $1.3 million decrease in revenue became effective October 1, 1996. Effective December 15, 1990, the APSC approved 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. On October 7, 1996, the APSC issued an order providing for the refund to customers of approximately $17.1 million, including interest, of supplier refunds. The 37 16 Order provides that refunds shall be returned to customers prior to January 31, 1997. These 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 will be used to fund the supplier refunds discussed above. On June 12, 1995, Alagasco received approval from the APSC to issue $50 million of debt, a portion of which was used to redeem all of Alagasco's 9 percent debentures and 11 percent First Mortgage Bonds. In connection with the early call of the redeemed debt, Alagasco paid an early call premium of approximately $1.3 million. Because the APSC authorized Alagasco to collect the early call premium through customer rates, a regulatory asset of $1.3 million was recorded at September 30, 1995, and the amounts were collected during fiscal 1996. 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 $2.7 million are being returned to ratepayers over approximately 14 years. At September 30, 1996 and 1995, regulatory liabilities of $5 million and $6 million, respectively, were included in the financial statements related to income taxes. FERC REGULATION: On March 15, 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 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. On April 11, 1996, the FERC issued its Order on Rehearing approving the Settlement with minor modifications. The Settlement, as approved by FERC, provides for the following: (1) the resolution of all cost of service and rate design issues in Southern's six pending rate cases and the establishment of reduced rates for the purpose of calculating rate case refunds; (2) the implementation of reduced settlement rates for supporting parties commencing March 1, 1995; (3) the resolution of all GSR and other transition cost issues resulting from FERC Order 636; (4) lower GSR cost recovery through the reduction and earlier payout of GSR costs; (5) a three-year moratorium on general rate increases; and (6) the resolution and disposition of all rate case and GSR refunds for supporting parties. With respect to this last point, the Settlement provides that all rate case refunds will be used to offset a portion of Southern's remaining GSR liability. In addition, as a result of the recalculated GSR surcharges for the period January 1, 1994, to February 28, 1995, Southern refunded over-collected GSR costs. As a result of this FERC order, Alagasco received other refunds based on contracts with other suppliers whose prices were tied to Southern's rates. In total, $17.1 million will be refunded to customers prior to January 31, 1997, and includes amounts received from Southern, other suppliers and accrued interest. The Settlement, as approved by 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 $0.8 million to be paid through December 1997 and approximately $1.4 million in other transition costs to be paid through June 1998. Because these costs will be recovered in full from its customers, Alagasco recorded regulatory assets of $2.2 million and $5 million at September 30, 1996 and 1995, respectively. 38 17 3. LONG-TERM DEBT AND NOTES PAYABLE Long-term debt consists of the following:
- ----------------------------------------------------------------------------------------------------------------------- AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995 - ----------------------------------------------------------------------------------------------------------------------- Energen Corporation: Medium-term Notes, interest ranging from 7.07% to 8.09%, for notes redeemable September 20, 2001, to September 15, 2026 ............................... $ 40,000 $ -- 8% Debentures, due up to $1,000,000 annually to February 1, 2007 ..................... 18,714 18,746 Series 1993 Notes, interest ranging from 5.25% to 7.25%, due annually in payments ranging from $805,000 to $1,604,000 from March 1, 1997, to March 1, 2008 ..................................................................... 13,636 14,629 Alabama Gas Corporation: Medium-term Notes, interest ranging from 5.4% to 7.97%, for notes redeemable December 1, 1998, to September 23, 2026 ................................... 125,000 100,000 - ----------------------------------------------------------------------------------------------------------------------- Total ................................................................................... 197,350 133,375 Less amounts due within one year ....................................................... 1,805 1,775 - ----------------------------------------------------------------------------------------------------------------------- Total ................................................................................. $195,545 $131,600 - -----------------------------------------------------------------------------------------------------------------------
In the prior year, the Company deposited $37.6 million into an irrevocable trust to complete an in-substance defeasance of Alagasco's 9 percent debentures and 11 percent Series H First Mortgage Bonds. The funds in the trust, primarily obtained through the issuance of medium-term notes and short-term borrowings, were used solely to satisfy the principal, interest, and call premium of the defeased debt. Accordingly, the debt and related accrued interest were excluded from the 1995 consolidated balance sheet. No gain or loss was recorded in the financial statements as the APSC granted Alagasco regulatory relief related to the income statement impact of this defeasance. The aggregate maturities of long-term debt for the next five years are as follows:
- ------------------------------------------------------------------------------------- YEARS ENDING SEPTEMBER 30, (IN THOUSANDS) - ------------------------------------------------------------------------------------- 1997 1998 1999 2000 2001 - ------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------- $1,805 $1,855 $7,219 $1,965 $ 18,648 - -------------------------------------------------------------------------------------
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, 1996, Energen had a tangible net worth of $188,178,000. The Company and Alagasco have short-term credit lines and other credit facilities of $156 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) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Amount outstanding ....................................................... $ 59,000 $ 32,300 $ 6,000 Available for borrowings ................................................. 97,000 77,700 104,000 - ----------------------------------------------------------------------------------------------------------------------- Total ................................................................... $156,000 $110,000 $110,000 - ----------------------------------------------------------------------------------------------------------------------- Maximum amount outstanding at any month-end ............................... $ 95,000 $ 32,300 $ 60,000 Average daily amount outstanding ......................................... $ 37,960 $ 917 $ 13,836 Weighted average interest rates based on: Average daily amount outstanding ....................................... 5.68% 5.76% 3.32% Amount outstanding at year-end ......................................... 5.62% 5.96% 5.17% - -----------------------------------------------------------------------------------------------------------------------
Total interest expense for Energen in 1996, 1995 and 1994 was $13,920,000, $11,693,000, and $11,284,000, respectively. 39 18 4. INCOME TAXES The components of income taxes consist of the following:
- ----------------------------------------------------------------------------------------------------------------------- FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Taxes estimated to be payable currently: Federal ................................................................. $5,218 $5,377 $8,550 State ................................................................... 989 873 1,369 - ----------------------------------------------------------------------------------------------------------------------- Total current ......................................................... 6,207 6,250 9,919 - ----------------------------------------------------------------------------------------------------------------------- Taxes deferred: Federal ................................................................. (1,221) (2,580) (2,976) State ................................................................... 62 11 (332) - ----------------------------------------------------------------------------------------------------------------------- Total deferred ....................................................... (1,159) (2,569) (3,308) - ----------------------------------------------------------------------------------------------------------------------- Total income tax expense ................................................. $5,048 $3,681 $6,611 - -----------------------------------------------------------------------------------------------------------------------
Temporary differences and carryforwards which give rise to a significant portion of deferred tax assets and liabilities for 1996 and 1995 are as follows:
- ------------------------------------------------------------------------------------------------------------------------ AS OF SEPTEMBER 30, (IN THOUSANDS) 1996 1995 - ------------------------------------------------------------------------------------------------------------------------ Current Noncurrent Current Noncurrent --------------------------------------------- Deferred tax assets: Regulatory liabilities ............................................. $ -- $1,872 $ -- $ 2,229 Minimum tax credit ................................................. -- 16,379 -- 14,622 Insurance and accruals ............................................. 2,487 -- 2,175 -- Unbilled revenue ................................................... 1,658 -- 1,565 -- Other, net ......................................................... 5,812 1,952 6,691 2,012 - ------------------------------------------------------------------------------------------------------------------------ Subtotal ......................................................... 9,957 20,203 10,431 18,863 Valuation allowance ............................................... -- -- -- -- - ------------------------------------------------------------------------------------------------------------------------ Total deferred tax assets ....................................... $9,957 $20,203 $10,431 $18,863 - ------------------------------------------------------------------------------------------------------------------------ Deferred tax liabilities: Depreciation and basis differences ................................. $ -- $18,227 $ -- $18,497 Basis differences on oil and gas producing properties ............... -- 1,960 -- 2,160 Other, net ......................................................... 1,962 988 764 746 - ------------------------------------------------------------------------------------------------------------------------ Total deferred tax liabilities ................................. $1,962 $21,175 $ 764 $21,403 - ------------------------------------------------------------------------------------------------------------------------
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, 1996, the amount of minimum tax credit which can be carried forward indefinitely to reduce future regular tax liability is $16,379,000. 40 19 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) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Income tax expense at statutory federal income tax rate ........................... $9,306 $8,046 $10,627 Increase (decrease) resulting from: Nonconventional fuel credits-current ........................................... (3,575) (2,343) (4,259) Nonconventional fuel credits-deferred ........................................... (646) (1,779) 127 Investment tax credits-deferred ................................................. (487) (487) (487) State income taxes, net of federal income tax benefit ........................... 681 625 700 Other, net ..................................................................... (231) (381) (97) - ----------------------------------------------------------------------------------------------------------------------- Total income tax expense ......................................................... $5,048 $3,681 $ 6,611 - -----------------------------------------------------------------------------------------------------------------------
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, 1996, 1995 and 1994, was $412,000, $1,158,000, and $15,000, respectively. The expense for the second plan covering employees under certain labor union agreements (Plan B) for 1996, 1995 and 1994 was $197,000, $339,000, and $555,000, respectively. The funded status of the plans is as follows:
- ----------------------------------------------------------------------------------------------------------------------- AS OF JUNE 30, (IN THOUSANDS) PLAN A PLAN B - ----------------------------------------------------------------------------------------------------------------------- 1996 1995 1996 1995 ---------------------------------------------- Vested benefits ................................................... $(56,828) $(46,073) $(14,210) $(13,499) Nonvested benefits ............................................... (4,323) (5,912) (2,336) (2,083) - ----------------------------------------------------------------------------------------------------------------------- Accumulated benefit obligation ................................... (61,151) (51,985) (16,546) (15,582) Effects of salary progression ..................................... (12,607) (11,047) -- -- - ----------------------------------------------------------------------------------------------------------------------- Projected benefit obligation ..................................... (73,758) (63,032) (16,546) (15,582) Fair value of plan assets, primarily equity and fixed income securities ....................................... 80,750 69,431 18,358 16,429 Unrecognized net gain (loss) ..................................... (337) 1,470 (433) 296 Unrecognized prior service cost ................................... 35 41 1,205 1,412 Unrecognized net transition obligation (asset) ................... (4,303) (5,111) 340 396 - ----------------------------------------------------------------------------------------------------------------------- Accrued pension asset ............................................. $ 2,387 $ 2,799 $ 2,924 $ 2,951 - -----------------------------------------------------------------------------------------------------------------------
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. At September 30, 1995, for both plans the discount rate used to measure the projected benefit obligation was 7.5 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 5.5 percent. 41 20 The components of net pension costs for 1996, 1995 and 1994 were:
- ----------------------------------------------------------------------------------------------------------------------- FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) PLAN A PLAN B - ----------------------------------------------------------------------------------------------------------------------- 1996 1995 1994 1996 1995 1994 ----------------------------------------------------------------------- Service Cost ............................... $ 2,147 $2,052 $1,873 $ 255 $ 224 $ 224 Interest cost on projected benefit obligation 4,617 4,728 4,550 1,166 1,095 1,042 Actual (return) on plan assets ............. (22,733) (8,787) (504) (2,971) (2,172) (372) Net amortization and deferral ............... 16,381 2,106 (5,904) 1,747 1,192 (339) Loss due to special termination benefits ... -- 1,489 -- -- -- -- Settlement gain ............................. -- (430) -- -- -- -- - ----------------------------------------------------------------------------------------------------------------------- Net pension expense ......................... $ 412 $1,158 $ 15 $ 197 $ 339 $ 555 - -----------------------------------------------------------------------------------------------------------------------
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 for certain key executives providing for payments on retirement, termination, death or disability. The deferred compensation expense under these agreements for 1996, 1995 and 1994 was $1,002,000, $808,000, and $461,000, respectively. At June 30, 1996 and 1995, the accumulated post-retirement benefit obligation related to these agreements was $6,206,000 and $4,770,000, the projected benefit obligation was $9,442,000 and $5,904,000, and the accrued post-retirement benefit liability was $464,000 and $199,000. 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. In a prior year, the Company adopted SFAS No.106, Employers' Accounting for Post-retirement benefits Other Than Pensions, with respect to the accrual of such costs for salaried employees. During fiscal year 1994, the Company adopted SFAS 106 with respect to such costs for employees under collective bargaining agreements. There was no cumulative effect on the income statement resulting from the adoption of FAS 106, as the Company elected to amortize transition costs over a 20-year period. On December 6, 1993, the APSC adopted an order which allows the Company to recover all costs accrued under SFAS 106 through rates. 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, 1996, 1995, and 1994 was $1,984,000, $2,271,000, and $2,319,000, respectively. The expense for union employees was $4,076,000, $3,613,000, and $3,685,000 during 1996, 1995 and 1994, 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 - ----------------------------------------------------------------------------------------------------------------------- 1996 1995 1996 1995 --------------------------------------------------- Retirees ....................................................... $(10,344) $(9,091) $(14,982) $(13,030) Active, fully-eligible ......................................... (1,574) (3,306) (4,011) (3,776) Other active ................................................... (7,989) (8,360) (14,415) (12,794) - ----------------------------------------------------------------------------------------------------------------------- Accumulated post-retirement benefit obligation ................. (19,907) (20,757) (33,408) (29,600) Fair value of plan assets, primarily equity and fixed income securities ....................................... 17,519 12,659 8,399 4,419 Unamortized amounts ............................................. 1,210 7,550 20,887 24,237 - ----------------------------------------------------------------------------------------------------------------------- Accrued post-retirement benefit liability ....................... $ (1,178) $ (548) $ (4,122) $ (944) - -----------------------------------------------------------------------------------------------------------------------
42 21 Net periodic post-retirement benefit cost for the years ended September 30, 1996, 1995, and 1994 included the following:
FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) SALARIED EMPLOYEES UNION EMPLOYEES - ------------------------------------------------------------------------------------------------------------------------ 1996 1995 1994 1996 1995 1994 ------------------------------------------------------------- Service cost ....................................... $ 516 $ 512 $ 450 $ 876 $ 807 $ 481 Interest cost on accumulated post-retirement benefit obligation ............................... 1,679 1,696 1,726 2,195 1,793 1,920 Amortization of transition obligation ............... 723 723 723 1,285 1,285 1,285 Amortization of actuarial gains and losses ......... (277) -- -- -- -- -- Deferred asset (gain) loss ......................... 658 539 (453) 177 424 -- Actual (return) on plan assets ..................... (1,315) (1,199) (127) (457) (696) (1) - ------------------------------------------------------------------------------------------------------------------------ Net periodic post-retirement benefit expense ....... $1,984 $2,271 $2,319 $4,076 $3,613 $3,685 - ------------------------------------------------------------------------------------------------------------------------
The weighted average discount rate used in determining the accumulated post-retirement benefit obligation was 7.75 percent and 7.5 percent in 1996 and 1995, respectively. 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 percent in 1996 and 1995. 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. The assumed health care cost trend rate of 8 percent is not currently expected to change. For pay-related life insurance benefits, the salary scale averages 5 percent. 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, 1996, 1995, and 1994 was $370,000, $155,000, and $150,000, 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, 1996, 352,177 common shares were reserved for issuance under the ESP. Expense associated with Company contributions to the ESP was $2,902,000, $2,944,000, and $2,772,000 for 1996, 1995 and 1994, 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, 62,630, 56,430, and 49,120 performance units were awarded in 1996, 1995 and 1994, respectively, leaving 243,326 performance units available for award at September 30, 1996. The Company recorded expense of $1,223,000, $1,628,000, and $939,000 for 1996, 1995 and 1994, respectively, under the Plan. The Restricted Stock Incentive Plan of Energen Corporation, adopted in 1984, provided for the award of common stock to eligible participants. Stock awarded under the Plan is subject to certain restrictions against sale or pledge. Pursuant to its terms, the Plan terminated effective January 1994 subject to completion of restriction periods applicable to previously 43 22 awarded shares. Under the Plan, no common shares were awarded in 1996, 1995, or 1994. Expense of $50,000, $121,000, and $218,000 was charged during 1996, 1995 and 1994, respectively, under this 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, 1996, 830,908 common shares were reserved under this Plan. 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. Options expire 10 years from the date of grant. Transactions under the Plan are summarized as follows:
- ---------------------------------------------------------------------------------------------------------------------- AS OF SEPTEMBER 30, 1996 1995 1994 - ---------------------------------------------------------------------------------------------------------------------- Outstanding at beginning of year ($16.75 - $20.125) ............................. 152,056 141,556 141,556 Granted (at $20.125 - $22.125) ................................................. 10,000 10,500 -- - ---------------------------------------------------------------------------------------------------------------------- Outstanding at year-end ......................................................... 162,056 152,056 141,556 - ---------------------------------------------------------------------------------------------------------------------- Exercisable at year-end ......................................................... 162,056 152,056 141,556 - ---------------------------------------------------------------------------------------------------------------------- Remaining reserved for issuance at year-end ..................................... 93,348 103,348 113,848 - ----------------------------------------------------------------------------------------------------------------------
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, 4,322, 3,829, and 3,515 shares were issued in 1996, 1995 and 1994, respectively, leaving 85,272 shares reserved for issuance at September 30, 1996. 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 outstand- ing under the Shareholder Rights Plan at September 30, 1996 and 1995, were convertible into 74,418 and 72,734 shares, respectively, of Series A Junior Participating Preferred Stock (1/100 share of preferred stock for each full right) subject to adjustment upon the 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 the occurrence of certain take-over related events. In general, in the absence of certain takeover-related events, as described in the Plan, the rights may be redeemed prior to their 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 2008. These contracts typically contain minimum demand charge obligations on the part of the Company. Taurus has entered into a three-and-one-half-year agreement with Sonat Exploration Company. Under the agreement, which extends through calendar year 1998, Taurus expects to spend between $25 and $50 million annually as its proportionate share of acquisitions made through Sonat Exploration's reserve acquisition program. 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 1996, 1995 and 1994, the Company sold $8,831,000, $8,454,000 and $6,784,000, respectively, of installment receivables. At 44 23 September 30, 1996 and 1995, the balance of these installment receivables was $16,964,000 and $15,618,000, 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. During 1996, Taurus entered into a sales contract covering the production from its current year coalbed methane acquisition. The contract, in part, provides for variable and fixed prices with fixed prices of $2.37 per Mcf and $2.02 per Mcf for fiscal years 1997 and 1998, respectively. Taurus's net production subject to the fixed prices is estimated at 4 Bcf per year. Taurus's gross estimated production committed to the fixed price component of the contract approximates 80 percent of the total anticipated production from the acquisition during the next two fiscal years. HEDGING: Revenues from the Company's oil and gas subsidiary are primarily the result of sales of natural gas and oil production. Market prices of natural gas and oil may fluctuate and significantly impact operating results. To mitigate this risk, Taurus periodically enters into futures contracts to hedge its exposure to price reductions on its oil and gas production. Under this program, Taurus has entered into futures contracts for the sale of 11.5 Bcf of its fiscal 1997 gas production at an average contract price of $2.12 per Mcf and for the sale of 558 MBbl of its fiscal 1997 oil production at an average contract price of $20.98 per barrel. Hedge prices do not include basis differential. 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, Alagasco, and their affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and Alagasco. It should be noted, however, that Energen, Alagasco and their 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. 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 460,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure. 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. 45 24 LEASE OBLIGATIONS: Total payments related to leases included as operating expense in the accompanying consolidated statements of income were $3,050,000, $3,035,000, and $2,986,000 in 1996, 1995 and 1994, respectively. Minimum future rental payments (in thousands) required after 1996 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
- ------------------------------------------------------------------------------------------------------- 1997 1998 1999 2000 2001 2002 and thereafter - ------------------------------------------------------------------------------------------------------- $3,010 $1,608 $1,109 $1,029 $ 528 $80 - -------------------------------------------------------------------------------------------------------
8. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental information concerning cash flow activities is as follows:
- ------------------------------------------------------------------------------------------------------------------- FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------------- Interest paid ........................................................... $13,261 $13,994 $11,055 Income taxes paid ....................................................... $ 5,486 $ 6,234 $10,965 Noncash investing activities: Capitalized depreciation ............................................. $ 166 $166 $ 155 Allowance for funds used during construction ......................... $ 972 $ 1,054 $ 465 Noncash financing activities (debt issuance costs) ..................... $ 414 $ 340 $ 330 - -------------------------------------------------------------------------------------------------------------------
9. 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, would be $194,497,000 at September 30, 1996. The fair value was based on the market value of debt with similar maturities and with interest rates currently trading in the marketplace. 10. RECENT PRONOUNCEMENTS OF THE FASB In June 1995, the Financial Accounting Standards Board (FASB) issued SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. This statement requires that long-lived assets be reviewed for impairment whenever events or changes in the circumstances indicate that the carrying amount for an asset may not be recoverable. The Company is required to adopt this Statement in its 1997 fiscal year, but, based on known facts and circumstances, does not expect implementation to have a material impact on the Company's financial statements. In October 1995, SFAS No. 123, Accounting for Stock-Based Compensation, was issued and also requires adoption by the Company in its fiscal year 1997. SFAS No. 123 establishes a fair value-based method of accounting for employee stock options but allows companies to continue to follow the accounting treatment prescribed by APB Opinion 25 with proper disclosure. The Company has not yet determined the method of accounting that it will follow for stock options but does not expect that adoption of the requirements of SFAS No. 123 will have a material impact on the Company's financial statements. In June 1996, SFAS No. 125, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, was issued and provides accounting and reporting standards for such transactions. The Statement requires adoption by the Company in its fiscal year 1998. Implementation of SFAS No. 125 is not expected to have a material impact on the Company's financial statements. 46 25 11. 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.
- ----------------------------------------------------------------------------------------------------------------------- 1996 FISCAL QUARTERS -------------------------------------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 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) - -----------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------- 1995 Fiscal Quarters -------------------------------------------- First Second Third Fourth - ----------------------------------------------------------------------------------------------------------------------- Operating revenues ............................................... $72,807 $140,166 $60,954 $44,653 Operating income (loss) ........................................... $ 5,281 $ 30,237 $ 3,238 $(6,723) Net income (loss) ................................................. $ 2,736 $ 21,714 $ 1,129 $(6,271) Earnings (loss) per average common share ......................... $ 0.25 $ 1.99 $ 0.10 $ (0.58) - -----------------------------------------------------------------------------------------------------------------------
12. 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 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) 1996 1995 1994 - ---------------------------------------------------------------------------------------------------------------------- Proved ........................................................................... $222,428 $115,720 $90,709 Unproved ......................................................................... 2,041 1,619 1,646 - ---------------------------------------------------------------------------------------------------------------------- Total capitalized costs ......................................................... 224,469 117,339 92,355 Accumulated depreciation, depletion and amortization ............................. 60,152 51,170 43,052 - ---------------------------------------------------------------------------------------------------------------------- Capitalized costs, net ........................................................... $164,317 $66,169 $49,303 - ----------------------------------------------------------------------------------------------------------------------
47 26 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) 1996 1995 1994 - ---------------------------------------------------------------------------------------------------------------------- Property acquisition: Proved ....................................................................... $108,315 $16,950 $1,372 Unproved ..................................................................... 1,693 989 1,169 Exploration ..................................................................... 11,124 4,666 4,565 Development ..................................................................... 10,040 6,044 1,438 - ---------------------------------------------------------------------------------------------------------------------- Total costs incurred ........................................................... $131,172 $28,649 $8,544 - ----------------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS The following table sets forth results of the Company's oil and gas producing activities:
- ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Gross revenues: Unaffiliated (excluding consulting revenues) ................................. $36,706 $20,397 $21,577 Affiliated ................................................................... 1,715 2,259 2,917 Production (lifting) costs ..................................................... 10,573 5,995 5,882 Exploration expense ............................................................. 5,439 2,933 2,088 Depreciation, depletion and amortization ....................................... 18,583 8,847 8,080 Income tax benefit ............................................................. (3,004) (2,410) (1,607) - ----------------------------------------------------------------------------------------------------------------------- Results of operations from producing activities ................................. $ 6,830 $ 7,291 $10,051 - -----------------------------------------------------------------------------------------------------------------------
AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE
- ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Average sales price: Gas (per Mcf) ................................................................. $ 1.97 $ 1.72 $ 1.89 Oil (per barrel) ............................................................. $16.25 $15.07 $14.25 Average production (lifting) cost (per Mcf equivalent) ......................... $ 0.66 $ 0.59 $ 0.57 Average depreciation rate (per Mcf equivalent) ................................. $ 1.15 $ 0.88 $ 0.78 - -----------------------------------------------------------------------------------------------------------------------
DRILLING ACTIVITY The following table sets forth the total number of net productive and dry exploratory and development wells drilled:
- ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Exploratory: Productive ................................................................... 1.1 0.9 0.6 Dry ........................................................................... 1.5 1.0 0.4 - ----------------------------------------------------------------------------------------------------------------------- Total ....................................................................... 2.6 1.9 1.0 - ----------------------------------------------------------------------------------------------------------------------- Development: Productive ................................................................... 2.4 1.0 0.7 Dry ........................................................................... -- 0.1 -- - ----------------------------------------------------------------------------------------------------------------------- Total ....................................................................... 2.4 1.1 0.7 - -----------------------------------------------------------------------------------------------------------------------
As of September 30, 1996, the Company was participating in the drilling of 1 gross well, with the Company's interest equivalent to .33 wells. 48 27 PRODUCTIVE WELLS AND ACREAGE The following table sets forth the total gross and net productive gas and oil wells as of September 30, 1996, and developed and undeveloped acreage as of the latest practicable date prior to year-end:
- ----------------------------------------------------------------------------------------------------------- Gross Net - ----------------------------------------------------------------------------------------------------------- Gas Wells ....................................................................... 1,247 406 Oil Wells ....................................................................... 1,548 64 Developed Acreage ............................................................... 396,487 93,400 Undeveloped Acreage ............................................................. 152,261 18,280 - -----------------------------------------------------------------------------------------------------------
The Company also had a revenue interest only in an additional 236 gross wells. There were 103 gross wells with multiple completions with the Company's interest being an equivalent of 49.3 wells. 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 Securities and Exchange Commission. 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 7 for pricing information regarding the hedging activities of the Company. The proved reserves are located in the United States, both onshore and offshore, and are as follows:
- ------------------------------------------------------------------------------------------------------------------------ YEARS ENDED SEPTEMBER 30, 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------------------ Gas Oil Gas Oil Gas Oil MMcf MBbl MMcf MBbl MMcf Mbbl ------------------ ------------------- ----------------- Proved reserves at beginning of year ............... 71,267 3,986 60,057 1,485 67,298 1,289 Revisions of previous estimates ..................... 502 369 (1,462) 142 (3,579) 144 Purchase of minerals in place ....................... 155,647 3,805 11,919 2,472 456 201 Discoveries and other additions ..................... 5,113 49 9,350 137 5,051 42 Production ......................................... (12,308) (635) (8,597) (250) (9,169) (191) Sales of minerals in place ......................... (7,244) (1,259) -- -- -- -- - ------------------------------------------------------------------------------------------------------------------------ Proved reserves at end of year ..................... 212,977 6,315 71,267 3,986 60,057 1,485 - ------------------------------------------------------------------------------------------------------------------------ Proved developed reserves at end of year ........... 175,124 5,012 50,657 3,380 45,538 1,281 - ------------------------------------------------------------------------------------------------------------------------
During the year, Taurus invested $108 million in property acquisitions and added 178 Bcfe of proved reserves. Additional development expenditures are required. Also, Taurus sold approximately 15 Bcfe and recorded a pre-tax gain of $3.9 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. 49 28
- ------------------------------------------------------------------------------------------------------------------------ YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------------------ Future gross revenues ......................................................... $502,607 $156,367 $105,986 Future production costs ....................................................... 216,755 63,311 41,113 Future development costs ..................................................... 40,665 19,029 13,024 - ------------------------------------------------------------------------------------------------------------------------ Future net cash flows before income taxes ..................................... 245,187 74,027 51,849 Future income tax expense (benefit) including tax credits ..................... 3,707 (10,533) (15,856) - ------------------------------------------------------------------------------------------------------------------------ Future net cash flows after income taxes ..................................... 241,480 84,560 67,705 Discount at 10% per annum ..................................................... 70,641 21,001 16,051 - ------------------------------------------------------------------------------------------------------------------------ Standardized measure of discounted future net cash flows relating to proved oil and gas reserves ..................................... $170,839 $ 63,559 $ 51,654 - ------------------------------------------------------------------------------------------------------------------------
The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
- ------------------------------------------------------------------------------------------------------------------------ YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------------------ Balance at beginning of year ................................................. $ 63,559 $51,654 $72,784 - ------------------------------------------------------------------------------------------------------------------------ Revisions to reserves proved in prior years: Net changes in prices, production costs and future development costs ......................................................... 15,051 (1,984) (24,969) Net changes due to revisions in quantity estimates ......................... 552 (2,474) (2,278) Development costs incurred, previously estimated ........................... 6,713 3,207 1,723 Accretion of discount ....................................................... 6,356 5,166 7,278 Other ....................................................................... 1,215 (37) (560) - ------------------------------------------------------------------------------------------------------------------------ Total Revisions ............................................................... 29,887 3,878 (18,806) New field discoveries and extensions, net of future production and development costs ........................................... 4,705 6,021 523 Sales of oil and gas produced, net of production costs ....................... (24,002) (12,518) (14,635) Purchases of minerals in place ............................................... 94,728 13,894 1,354 Sales of minerals in place ................................................... (10,597) -- -- Net change in income taxes ................................................... 12,559 630 10,434 - ------------------------------------------------------------------------------------------------------------------------ Net change in standardized measure of discounted future net cash flows ............................................................. 107,280 11,905 (21,130) - ------------------------------------------------------------------------------------------------------------------------ Balance at end of year ....................................................... $170,839 $63,559 $51,654 - ------------------------------------------------------------------------------------------------------------------------
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, 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------------------ Proved reserves at beginning of year (Mmcf) ................................... 25,004 26,712 34,109 Revisions of previous estimates ............................................... 4,231 1,842 (3,687) Purchases of minerals in place ............................................... 105,762 -- -- Discoveries and other additions ............................................... -- 159 -- Production ................................................................... (4,610) (3,709) (3,710) - ------------------------------------------------------------------------------------------------------------------------ Proved reserves at end of year ............................................... 130,387 25,004 26,712 - ------------------------------------------------------------------------------------------------------------------------ Estimated proved reserves qualifying for tax credits (Mmcf) ................... 30,142 15,837 18,947 - ------------------------------------------------------------------------------------------------------------------------ Net capitalized costs (in thousands) ......................................... $77,708 $19,370 $21,924 - ------------------------------------------------------------------------------------------------------------------------ Gross wells in which Taurus has working and/or revenue interest ............... 825 634 657 - ------------------------------------------------------------------------------------------------------------------------ Net productive wells ......................................................... 279.1 154.4 164.2 - ------------------------------------------------------------------------------------------------------------------------
50 29 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 per Mcf of qualifying production. Accordingly, a significant portion of the value of proved coalbed methane reserves is associated with this tax credit. 13. INDUSTRY SEGMENT INFORMATION The Company is principally engaged in the purchase, distribution and sale of natural gas in central and north Alabama and the development of oil and gas in the continental United States. The Company also is engaged in intrastate gas transmission services. Certain reclassifications have been made to conform the prior year to the current year presentation.
- ----------------------------------------------------------------------------------------------------------------------- As of September 30, (in thousands) 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------------------- Operating revenues, unaffiliated customers: Natural gas distribution $357,252 $295,967 $344,637 Oil and gas production 40,909 21,396 22,294 Other 1,281 1,217 7,572 - ----------------------------------------------------------------------------------------------------------------------- Total $399,442 $318,580 $374,503 - ----------------------------------------------------------------------------------------------------------------------- Intersegment revenues: Natural gas distribution $ -- $ -- $ -- Oil and gas production 1,715 2,259 2,917 Other 877 1,081 1,238 - ----------------------------------------------------------------------------------------------------------------------- Total $ 2,592 $ 3,340 $ 4,155 - ----------------------------------------------------------------------------------------------------------------------- Depreciation, depletion and amortization expense: Natural gas distribution $ 21,269 $ 19,368 $ 17,941 Oil and gas production 19,335 9,767 9,065 Other 514 421 970 - ----------------------------------------------------------------------------------------------------------------------- Total $ 41,118 $ 29,556 $ 27,976 - ----------------------------------------------------------------------------------------------------------------------- Capital expenditures: Natural gas distribution $ 43,175 $ 42,780 $ 38,473 Oil and gas production 126,317 26,429 7,356 Other 60 951 334 - ----------------------------------------------------------------------------------------------------------------------- Total $169,552 $ 70,160 $ 46,163 - ----------------------------------------------------------------------------------------------------------------------- Identifiable assets: Natural gas distribution $363,823 $335,267 $308,905 Oil and gas production 197,549 113,701 92,019 Other 9,599 10,116 10,390 - ----------------------------------------------------------------------------------------------------------------------- Total $570,971 $459,084 $411,314 - ----------------------------------------------------------------------------------------------------------------------- Operating income (loss) before income taxes: Natural gas distribution $ 35,270 $ 32,513 $ 30,017 Oil and gas production 4,494 483 5,701 Other 263 236 1,014 Eliminations and corporate expenses (1,230) (1,199) (1,404) - ----------------------------------------------------------------------------------------------------------------------- Total $ 38,797 $ 32,033 $ 35,328 - -----------------------------------------------------------------------------------------------------------------------
30 MANAGEMENT'S 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 management's best estimates and judgments. Financial information presented elsewhere in this report is consistent with the information in the financial statements. Management maintains a comprehensive system of internal accounting controls and relies on the system to discharge its responsibility for the integrity of the financial statements. This system provides reasonable assurance that corporate assets are safeguarded and that transactions are recorded in such a manner as to permit the preparation of 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, 1996, 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. /s/ Geoffrey C. Ketcham - ----------------------- 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, 1996 and 1995, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended September 30, 1996. 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, 1996 and 1995, and the consolidated results of their operations and cash flows for each of the three years in the period ended September 30, 1996, in conformity with generally accepted accounting principles. /s/ Coopers & Lybrand L.L.P. - ---------------------------- Coopers & Lybrand L.L.P. Birmingham, Alabama October 23, 1996 52 31 10-YEAR GRAPHS NET INCOME CAPITALIZATION Dollars in millions Dollars in millions [GRAPH] [GRAPH] TOTAL ASSETS PROPERTY, PLANT AND EQUIPMENT, NET Dollars in millions Dollars in millions [GRAPH] [GRAPH] RETURN ON AVERAGE EQUITY CAPITAL EXPENDITURES Percent Dollars in millions [GRAPH] [GRAPH] 53 32 SELECTED FINANCIAL DATA
ENERGEN CORPORATION AND SUBSIDIARIES - --------------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1996 1995 1994 1993 - --------------------------------------------------------------------------------------------------------------------------- INCOME STATEMENT Operating revenues ............................................. $399,442 $318,580 $374,503 $355,878 Income before cumulative effect of change in accounting principle ....................................... $ 21,541 $ 19,308 $ 23,751 $ 18,081 Net income ..................................................... $ 21,541 $ 19,308 $ 23,751 $ 18,081 Earnings per share before cumulative effect ..................... $1.95 $ 1.77 $ 2.19 $ 1.77 Earnings per average common share ............................... $1.95 $ 1.77 $ 2.19 $ 1.77 - --------------------------------------------------------------------------------------------------------------------------- BALANCE SHEET Capitalization at year-end: Common shareholder's equity ................................... $188,405 $173,924 $167,026 $140,313 Preferred stock ............................................... -- -- -- -- Long-term debt ............................................... 195,545 131,600 118,302 85,852 - --------------------------------------------------------------------------------------------------------------------------- Total capitalization ....................................... $383,950 $305,524 $285,328 $226,165 - --------------------------------------------------------------------------------------------------------------------------- Total assets ................................................... $570,971 $459,084 $411,314 $ 70,685 - --------------------------------------------------------------------------------------------------------------------------- Property, plant and equipment, net ............................. $444,916 $327,264 $287,182 $273,097 - --------------------------------------------------------------------------------------------------------------------------- COMMON STOCK DATA Annual dividend rate at year-end ............................... $ 1.20 $ 1.16 $ 1.12 $ 1.08 Cash dividends paid per common share ........................... $ 1.17 $ 1.13 $ 1.09 $ 1.05 Book value per common share ..................................... $ 16.88 $ 15.94 $ 15.30 $ 13.60 Market-to-book ratio at year-end (%) ........................... 142 136 147 182 Yield at year-end (%) ........................................... 5.0 5.3 5.0 4.4 Return on average common equity (%) ............................. 11.6 11.0 14.6 13.0 Price-to-earnings ratio at year-end ............................. 12.3 12.3 10.3 14.0 Shares outstanding at year-end (000) ........................... 11,163 10,910 10,918 10,320 Price Range: High ......................................................... $ 25 3/8 $ 23 1/2 $ 26 5/8 $ 26 3/4 Low ........................................................... $ 21 3/8 $ 19 3/4 $ 19 1/4 $ 17 5/8 Close ......................................................... $ 24 $ 21 3/4 $ 22 1/2 $ 24 3/4 - --------------------------------------------------------------------------------------------------------------------------- OTHER GENERAL DATA Capital expenditures ........................................... $169,552 $ 70,160 $ 46,163 $ 44,036 - ---------------------------------------------------------------------------------------------------------------------------
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. 54 33
- -------------------------------------------------------------------------------------------------------------------------- 1992 1991 1990 1989 1988 1987 1986 - -------------------------------------------------------------------------------------------------------------------------- $331,065 $324,902 $324,022 $308,604 $353,135 $332,590 $364,853 $ 15,687 $ 14,112 $ 11,267 $ 6,422 $ 11,667 $ 8,950 $ 1,544 $ 16,628 $ 14,112 $ 11,267 $ 6,422 $ 11,667 $ 8,950 $ 1,544 $ 1.54 $ 1.42 $ 1.15 $ .69 $ 1.53 $ 1.38 $ .24 $ 1.64 $ 1.42 $ 1.15 $ .69 $ 1.53 $ 1.38 $ .24 - -------------------------------------------------------------------------------------------------------------------------- $129,858 $121,995 $113,316 $107,950 $ 86,256 $ 63,687 $ 58,325 1,800 1,800 1,800 2,450 2,450 2,850 3,000 90,609 77,677 82,835 86,188 53,203 54,589 42,286 - -------------------------------------------------------------------------------------------------------------------------- $222,267 $201,472 $197,951 $196,588 $141,909 $121,126 $103,611 - -------------------------------------------------------------------------------------------------------------------------- $342,119 $337,516 $326,350 $294,614 $260,560 $237,445 $211,055 - -------------------------------------------------------------------------------------------------------------------------- $254,630 $273,539 $250,983 $238,329 $206,230 $191,099 $170,952 - -------------------------------------------------------------------------------------------------------------------------- $ 1.04 $ 1.00 $ .94 $ .88 $ .827 $ .76 $ .72 $ 1.01 $ .955 $ .895 $ .843 $ .777 $ .73 $ .70 $ 12.75 $ 12.07 $ 11.48 $ 11.13 $ 10.80 $ 9.73 $ 9.02 142 150 157 190 147 163 140 5.7 5.5 5.2 4.2 5.2 4.8 5.7 13.0 11.6 10.0 6.0 15.6 14.7 2.6 11.1 12.8 15.7 30.6 10.4 11.5 52.6 10,183 10,104 9,872 9,695 7,989 6,544 6,467 $ 18 7/8 $ 20 $ 21 1/2 $ 24 3/8 $ 16 1/4 $ 16 1/2 $ 14 3/8 $ 15 $ 16 $ 16 $ 15 3/8 $ 11 3/8 $ 12 1/2 $ 9 $ 18 1/8 $ 18 1/8 $ 18 $ 21 3/8 $ 15 7/8 $ 15 7/8 $ 12 5/8 - -------------------------------------------------------------------------------------------------------------------------- $ 22,758 $ 47,024 $ 37,335 $ 54,474 $ 39,260 $ 40,139 $ 39,688 - --------------------------------------------------------------------------------------------------------------------------
55 34 SELECTED OPERATING DATA
ENERGEN CORPORATION AND SUBSIDIARIES - ----------------------------------------------------------------------------------------------------------------------- YEARS ENDED SEPTEMBER 30, (DOLLARS IN THOUSANDS) 1996 1995 1994 1993 - ----------------------------------------------------------------------------------------------------------------------- NATURAL GAS DISTRIBUTION Gas sold and transported (MMcf) Residential ..................................................... 34,963 27,489 31,254 30,957 Commercial and industrial-small ................................. 14,972 12,289 13,536 13,853 Commercial and industrial-large ................................. 30 29 106 282 Transportation ................................................. 61,458 61,640 52,635 49,346 - ----------------------------------------------------------------------------------------------------------------------- Total ......................................................... 111,423 101,447 97,531 94,438 - ----------------------------------------------------------------------------------------------------------------------- Revenues from gas sold and transported Residential ..................................................... $236,583 $194,089 $229,019 $216,587 Commercial and industrial-small ................................. 87,243 68,409 84,443 83,069 Commercial and industrial-large ................................. 669 290 790 1,223 Transportation ................................................. 30,408 30,490 29,321 27,382 Other ........................................................... 2,349 2,687 1,064 2,299 - ----------------------------------------------------------------------------------------------------------------------- Total ......................................................... $357,252 $295,965 $344,637 $330,560 - ----------------------------------------------------------------------------------------------------------------------- Average number of customers Residential ..................................................... 418,486 410,515 402,531 395,057 Commercial and industrial-small ................................. 34,028 33,115 32,563 32,269 Commercial and industrial-large ................................. 54 48 43 46 - ----------------------------------------------------------------------------------------------------------------------- Total ......................................................... 452,568 443,678 435,137 427,372 - ----------------------------------------------------------------------------------------------------------------------- Degree days (systemwide) 39 year moving average ......................................... 2,590 2,590 2,590 2,590 Actual for year ................................................. 2,933 2,101 2,636 2,624 Ratio of actual to 39-year average (%) ......................... 1.13 .81 101.8 101.3 - ----------------------------------------------------------------------------------------------------------------------- OIL AND GAS PRODUCTION Operating revenues ............................................... $ 42,624 $ 23,655 $ 25,211 $ 19,887 Coalbed methane proved reserves (Mmcf) ........................... 130,387 25,004 26,712 34,109 Conventional proved reserves (Mmcf)* ............................. 120,480 70,179 42,261 40,923 Oil and gas produced (Mmcf)* ..................................... 16,118 10,096 10,316 7,468 - ----------------------------------------------------------------------------------------------------------------------- OTHER ACTIVITIES Operating revenues ............................................... $ 2,158 $ 2,298 $ 8,810 $ 10,320 Operating income ................................................. $ 263 $ 236 $ 1,014 $ 581 Property, plant and equipment, net ............................... $ 1,839 $ 2,339 $ 1,977 $ 6,273 - -----------------------------------------------------------------------------------------------------------------------
* Oil expressed in natural gas equivalents 56 35
------------------------------------------------------------------------------------------------------------------- 1992 1991 1990 1989 1988 1987 1986 ------------------------------------------------------------------------------------------------------------------- 29,119 26,262 28,653 27,210 28,636 27,365 25,373 13,860 14,837 16,581 17,946 21,806 18,482 22,337 2,654 3,411 4,786 9,494 13,026 8,902 20,877 46,235 41,447 39,117 34,447 28,730 26,895 6,636 ------------------------------------------------------------------------------------------------------------------- 91,868 85,957 89,137 89,097 92,198 81,644 75,223 ------------------------------------------------------------------------------------------------------------------- $198,676 $195,250 $188,168 $170,302 $190,836 $181,007 $165,160 78,799 84,260 85,588 85,477 104,420 93,242 112,580 6,501 8,916 13,596 25,000 37,923 24,982 77,989 25,089 22,890 22,734 19,574 15,158 17,871 3,748 1,661 (2,188) 873 731 689 679 648 ------------------------------------------------------------------------------------------------------------------- $310,726 $309,128 $310,959 $301,084 $349,026 $317,781 $360,125 ------------------------------------------------------------------------------------------------------------------- 387,871 382,747 379,362 365,572 358,872 350,712 341,406 31,732 31,432 31,565 30,492 29,717 29,007 28,318 41 39 42 42 37 34 32 ------------------------------------------------------------------------------------------------------------------- 419,644 414,218 410,969 396,106 388,626 379,753 369,756 ------------------------------------------------------------------------------------------------------------------- 2,590 2,590 2,590 2,585 2,585 2,585 2,585 2,434 2,017 2,378 2,383 2,592 2,523 2,345 94.0 77.9 91.8 92.2 100.3 97.6 90.7 ------------------------------------------------------------------------------------------------------------------- $ 15,718 $ 12,661 $ 12,983 $ 13,469 $ 13,034 $ 9,536 $ 8,163 34,306 61,314 44,881 17,384 8,783 9,450 3,594 19,041 14,369 14,626 14,060 7,772 8,985 10,796 7,287 6,455 5,434 5,534 5,540 3,975 2,926 ------------------------------------------------------------------------------------------------------------------- $ 10,953 $ 10,900 $ 10,776 $ 5,962 $ 3,345 $ 3,843 $ 734 $ 1,764 $ 1,348 $ 1,809 $ (94) $ 1,324 $ 1,690 $ 319 $ 6,797 $ 7,098 $ 7,754 $ 9,004 $ 9,814 $ 5,833 $ 5,581 -------------------------------------------------------------------------------------------------------------------
57 36 GLOSSARY BASIS DIFFERENTIAL: The difference between the futures price for a commodity and the corresponding cash or spot price. The differential commonly is related to differences in factors such as product quality, location and contract pricing. BYPASS: Obtaining service from a new gas supplier without utilizing the facility of the former supplier. DEVELOPMENT COSTS: Costs necessary to gain access to, prepare and equip wells drilled to produce proved oil and gas reserves following discovery. EXPLORATORY WELL: A well drilled to a previously untested geologic structure to determine the presence of oil or gas. FEDERAL ENERGY REGULATORY COMMISSION (FERC): The federal agency that, among other functions, regulates all interstate natural gas pipelines and some intrastate gas operations. FUTURES CONTRACTS: Contracts that obligate the seller to deliver and the buyer to purchase a commodity at a fixed price at a specific date. HEDGING: The process of reducing financial exposure to adverse natural gas, oil or other commodity price movements. MUNICIPAL GAS SYSTEM: A natural gas distribution system owned and operated by one or more local governments. OPERATOR (OF OIL AND GAS PROPERTIES): The company responsible for exploration and production activities for a specific project. RATE STABILIZATION AND EQUALIZATION (RSE): A rate-setting mechanism authorized by the Alabama Public Service Commission which provides Alagasco, and some other utilities in Alabama, with the opportunity to earn a return on average equity within a designated range. RESERVES, OIL AND GAS: The amount of commercially recoverable oil or gas estimated to exist within a given reservoir. THROUGHPUT: Total volumes of natural gas sold and transported. TRANSPORTATION OR TRANSPORT: Moving natural gas through company pipelines on a contract basis for others. UNITS OF MEASURE: Mcf -- Thousand cubic feet MMcf -- Million cubic feet Bcf -- Billion cubic feet (When an "e" follows these units of measure, the oil component has been converted to its equivalent in cubic feet, with one barrel of oil equal to 6,000 cubic feet of gas.) WORKING INTEREST: The cost-bearing ownership interest under an oil and gas lease. 58 EX-21 5 SUBSIDIARIES OF ENERGEN CORPORATION 1 EXHIBIT 21 SUBSIDIARIES OF ENERGEN CORPORATION Alabama Gas Corporation Taurus Exploration, Inc. Taurus Exploration USA, Inc. Basin Pipeline Corp American Heat Tech, Inc. EGN Services, Inc. Midtown NGV, Inc. EX-23 6 CONSENT OF INDEPENDENT ACCOUNTANTS 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, 1996, on our audits of the consolidated financial statements of Energen Corporation as of September 30, 1996 and 1995, and for the years ended September 30, 1996, 1995, and 1994, which report is incorporated by reference in this Annual Report on Form 10-K. Coopers & Lybrand L.L.P. Birmingham, Alabama December 19, 1996 EX-27.1 7 FINANCIAL DATA SCHEDULE ENERGEN CORPORATION
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FORM 10K FOR SEPTEMBER 30, 1996, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000277595 ENERGEN CORPORATION 1,000 YEAR SEP-30-1996 OCT-01-1995 SEP-30-1996 PER-BOOK 276,533 168,383 115,295 10,760 0 570,971 112 89,635 98,658 188,405 0 0 195,545 59,000 0 0 1,805 0 0 0 126,216 570,971 399,442 5,048 360,645 365,693 33,749 1,712 35,461 13,920 21,541 0 21,541 12,903 9,890 52,457 1.95 1.95
EX-27.2 8 FINANCIAL DATA SCHEDULE ALABAMA GAS
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE FORM 10K FOR SEPTEMBER 1996, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000003146 ALABAMA GAS CORPORATION 1,000 YEAR SEP-30-1996 OCT-01-1995 SEP-30-1996 PER-BOOK 276,533 394 90,012 7,467 0 374,406 20 34,484 95,044 129,548 0 0 125,000 0 0 0 0 0 0 0 119,858 374,406 357,252 9,047 321,982 331,029 26,223 323 26,546 9,585 16,961 0 16,961 9,555 7,390 34,333 0 0 EARNINGS PER SHARE IS CALCULATED FOR ENERGEN CORPORATION (PARENT COMPANY OF ALAGASCO) AND IS NOT CALCULATED FOR ALAGASCO SEPARATELY AS AMOUNT WOULD NOT BE MEANINGFUL.
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