-----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, RJtnT7oxloQ0hw1NXayZ4/2earwZKXQgHdJYjMKFm8vUj8vCqUgHrq9Ya+YfKm8a FSXd6YwTgyLITmmtamuoWg== 0001096385-03-000073.txt : 20030618 0001096385-03-000073.hdr.sgml : 20030618 20030618112542 ACCESSION NUMBER: 0001096385-03-000073 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030618 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VECTREN CORP CENTRAL INDEX KEY: 0001096385 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 352086905 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-15467 FILM NUMBER: 03748271 BUSINESS ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 BUSINESS PHONE: 8124914000 MAIL ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 10-K/A 1 vvc-10k_2002amended.txt VECTREN CORP AMENDED 10K 2002 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K/A Amendment No. 1 (Mark One) |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2002 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________________ to ________________________ Commission file number: 1-15467 VECTREN CORPORATION ------------------------------------------------------------------------------ (Exact name of registrant as specified in its charter) INDIANA 35-2086905 - ------------------------------------------------ -------------------- (State or other jurisdiction of incorporation (IRS Employer or organization) Identification No.) 20 N.W. Fourth Street, Evansville, Indiana 47708 - ------------------------------------------- ------------ (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 812-491-4000 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered - ----------------------- ----------------------------------------- Common - Without Par New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X|. No ___. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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| Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes |X|. No __. The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 28, 2002 was $1,624,281,589. Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Common Stock- Without Par Value 68,011,649 February 15, 2003 ------------------------------- ---------------- ----------------- Class Number of Shares Date Documents Incorporated by Reference Certain information in the Company's definitive Proxy Statement for the 2003 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year, is incorporated by reference in Part III of this Form 10-K.
Definitions AFUDC: allowance for funds used MMBTU: millions of British thermal units during construction APB: Accounting Principles Board MW: megawatts EITF: Emerging Issues Task Force MWh/GWh: megawatt hours / millions of megawatt hours (gigawatt hour) FASB: Financial Accounting Standards Board NOx: nitrogen oxide FERC: Federal Energy Regulatory Commission OUCC: Indiana Office of the Utility Consumer Counselor IDEM: Indiana Department of Environmental PUCO: Public Utilities Commission of Ohio Management IURC: Indiana Utility Regulatory Commission SFAS: Statement of Financial Accounting Standards MCF/BCF: millions / billions of cubic feet USEPA: United States Environmental Protection Agency MDth/MMDth: thousands /millions of Throughput: combined gas sales and gas dekatherms transportation volumes
Table of Contents Item Page Number Number Part I 1 Business ......................................................... 1 2 Properties ....................................................... 11 3 Legal Proceedings................................................. 12 4 Submission of Matters to Vote of Security Holders................. 12 Part II 5 Market for the Company's Common Equity and Related Stockholder Matters ............................................ 12 6 Selected Financial Data........................................... 13 7 Management's Discussion and Analysis of Results of Operations and Financial Condition.............................. 14 7A Qualitative and Quantitative Disclosures About Market Risk........ 40 8 Financial Statements and Supplementary Data....................... 42 9 Change in and Disagreements with Accountants on Accounting and Financial Disclosure............................. 89 Part III 10 Directors and Executive Officers of the Registrant................ 89 11 Executive Compensation............................................ 90 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters...................... 90 13 Certain Relationships and Related Transactions.................... 91 Part IV 14 Controls and Procedures........................................... 91 15 Exhibits, Financial Statement Schedules, and Reports on Form 8-K............................................. 92 Signatures........................................................ 94 Access to Information Vectren Corporation makes available all SEC filings and recent annual reports free of charge through its website at www.vectren.com, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows: Mailing Address: Phone Number: Investor Relations Contact: P.O. Box 209 (812) 491-4000 Steven M. Schein Evansville, Indiana Vice President, Investor Relations 47702-0209 sschein@vectren.com Explanatory Note This Amendment No. 1 to Form 10-K filed on Form 10-K/A for the year ended December 31, 2002, is being filed to clarify various disclosures in the Description of Business section of Item 1 of Part I, the Results of Operations by Business Segments and Financial Condition sections of Item 7 of Part II and the Consolidated Statements of Cash Flows and Notes 2, 7, 8, 14 and 16 to the Consolidated Financial Statements of Item 8 of Part II. All information contained herein is as of February 26, 2003, and does not reflect any events or changes in information that may have occurred subsequent to February 26, 2003. For a discussion of events and developments relating to periods subsequent to February 26, 2003, see the Company's reports filed with the Securities and Exchange Commission for such subsequent periods, including the Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2003. PART I ITEM 1. BUSINESS Description of the Business Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP) are the predecessor companies to Vectren Corporation. Indiana Energy, incorporated under Indiana law on October 24, 1985, was engaged in natural gas distribution, gas portfolio administrative services, and marketing of natural gas, electric power and related services. Indiana Energy had fourteen subsidiaries, including ten nonregulated direct or indirect subsidiaries, a not-for-profit foundation and three utility subsidiaries, as well as investments in four nonregulated joint ventures. SIGCORP, incorporated under Indiana law on October 19, 1994, was engaged in electric generation, transmission, and distribution, natural gas distribution, coal mining, and broadband communication services. SIGCORP had eleven wholly-owned subsidiaries, including ten nonregulated subsidiaries. Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company was organized on June 10, 1999 solely for the purpose of effecting the merger of Indiana Energy and SIGCORP. On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with APB Opinion No. 16 "Business Combinations" (APB 16). The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI), serves as the intermediate holding company for its three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations. Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935. Indiana Gas provides natural gas distribution and transportation services to a diversified customer base in 49 of Indiana's 92 counties. SIGECO provides electric generation, transmission, and distribution services to 8 counties in southwestern Indiana, including counties surrounding Evansville, and participates in the wholesale power market. SIGECO also provides natural gas distribution and transportation services to 10 counties in southwestern Indiana, including counties surrounding Evansville. The Ohio operations provide natural gas distribution and transportation services to 17 counties in west central Ohio, including counties surrounding Dayton. The Company is also involved in nonregulated activities in four primary business areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure Services, and Broadband. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal to the Company's utility operations and to other parties and generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. Broadband invests in broadband communication services such as analog and digital cable television, high-speed Internet and data services, and advanced local and long distance phone services. In addition, the nonregulated group has other businesses that provide utility services, municipal broadband consulting, and retail products and services and that invest in energy-related opportunities, real estate and leveraged leases. Acquisition of the Gas Distribution Assets of The Dayton Power and Light Company On October 31, 2000, the Company acquired the natural gas distribution assets of The Dayton Power and Light Company for $471 million, including transaction costs. The acquisition has been accounted for as a purchase transaction in accordance with APB 16, and accordingly, the results of operations of the acquired assets are included in the Company's financial results since the date of acquisition. The Company acquired the natural gas distribution assets as a tenancy in common through two separate wholly owned subsidiaries. Vectren Energy Delivery of Ohio, Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and Indiana Gas holds a 47% undivided ownership interest. VEDO is the operator of the assets, and these operations are referred to as "the Ohio operations." Narrative Description of the Business The Company segregates its businesses into gas utility services, electric utility services, nonregulated, and corporate and other business segments. The Company collectively refers to its gas and electric utility services segments as its regulated operations. At December 31, 2002, the Company had $2.9 billion in total assets, with $2.4 billion (83%) attributed to the regulated operations, $0.4 billion (14%) attributed to the nonregulated operations, and $0.1 billion (3%) attributed to the corporate and other group. Net income for the year ended 2002 was $114.0 million, or $1.69 per share of common stock, with $93.6 million attributed to regulated, $19.0 million attributed to nonregulated, and $1.4 million attributed to corporate and other. Net income, as restated, for the year ended 2001 was $52.7 million, or $0.79 per share of common stock. The year ending December 31, 2001 included nonrecurring charges with an after tax impact of $26.4 million. Nonrecurring items net of tax in 2001 included $8.0 million of merger and integration costs, $11.8 million of restructuring costs, $7.7 million of extraordinary loss, and a $1.1 million gain resulting from a cumulative effect of change in accounting principle. For further information refer to Note 3 regarding the restatement of previously reported information, Note 18 regarding the segments' activities and assets, Note 19 regarding special charges in 2001 and 2000, Note 5 regarding the extraordinary loss, and Note 16 regarding the cumulative effect of change in accounting principle in the Company's consolidated financial statements included under Item 8 Financial Statements and Supplementary Data. Following is a more detailed description of the regulated and nonregulated business segments. The operations of the corporate and other business segment, which include primarily information technology services, are not significant. Regulated Business Segments The Company's regulated operations are comprised of its Gas Utility Services and Electric Utility Services segments. The Gas Utility Services segment includes the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas distribution business and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and west central Ohio. The Electric Utility Services segment includes the operations of SIGECO's electric transmission and distribution services, which provides electricity primarily to southwestern Indiana, and SIGECO's power generating and power marketing operations. Gas Utility Services At December 31, 2002, the Company supplied natural gas service to 966,761 Indiana and Ohio customers, including 882,151 residential, 80,483 commercial, and 4,127 industrial and other customers. This represents customer base growth of 1.4% compared to 2001. The Company's service area contains diversified manufacturing and agriculture-related enterprises. The principal industries served include automotive assembly, parts and accessories, feed, flour and grain processing, metal castings, aluminum products, appliance manufacturing, polycarbonate resin (Lexan) and plastic products, gypsum products, electrical equipment, metal specialties, glass, steel finishing, pharmaceutical and nutritional products, gasoline and oil products, and coal mining. The largest Indiana communities served are Evansville, Muncie, Anderson, Lafayette, West Lafayette, Bloomington, Terre Haute, Marion, New Albany, Columbus, Jeffersonville, New Castle, and Richmond. The largest community served outside of Indiana is Dayton, Ohio. Revenues For the year ended December 31, 2002, natural gas revenues were approximately $909.0 million of which residential customers accounted for 67%, commercial 23%, and industrial and other 10%, respectively. The Company receives gas revenues by selling gas directly to residential, commercial, and industrial customers at approved rates or by transporting gas through its pipelines at approved rates to commercial and industrial customers that have purchased gas directly from other producers, brokers, or marketers. Total volumes of gas provided to both sales and transportation customers (throughput) was 207,693 MDth for the year ended December 31, 2002. Transported gas represented 44% of total throughput. Rates for transporting gas provide for the same margins generally earned by selling gas under applicable sales tariffs. The sale of gas is seasonal and strongly affected by variations in weather conditions. To mitigate seasonal demand, the Company owns and operates seven underground gas storage fields and six liquefied petroleum air-gas manufacturing plants. The Company also contracts with ProLiance and other parties to ensure availability of gas. Natural gas purchased from suppliers is injected into storage during periods of light demand which are typically periods of lower prices. The injected gas is then available to supplement contracted and manufactured volumes during periods of peak requirements. Approximately 909,500 MCF of gas per day can be withdrawn during peak demand periods from all sources and for all utilities. Gas Purchases In 2002, the Company purchased natural gas from multiple suppliers including ProLiance Energy, LLC (ProLiance). ProLiance is an unconsolidated, nonregulated, energy marketing affiliate of Vectren and Citizens Gas and Coke Utility. (See Note 4 in the Company's consolidated financial statements included in Item 8 Financial Statements and Supplementary Data regarding transactions with ProLiance ). The Company purchased 120,764 MDth volumes of gas in 2002 at an average cost of $4.57 per Dth, of which 94% was purchased from ProLiance. The average cost of gas per Dth purchased for the last five years was; $4.57 in 2002; $5.83 in 2001; $5.60 in 2000; $3.58 in 1999; and $3.53 in 1998. Regulatory and Environmental Matters See Item 7 Management's Discussion and Analysis of Results of Operations and Financial Condition regarding the Company's regulated environment and issues involving manufactured gas plants. Electric Utility Services At December 31, 2002, the Company supplied electric service to 134,057 Indiana customers, including 116,979 residential, 16,881 commercial, and 197 industrial and other customers. This represents customer base growth of 0.6% compared to 2001. In addition, the Company is obligated to provide for firm power commitments to several municipalities and to maintain spinning reserve margin requirements under an agreement with the East Central Area Reliability Group. The principal industries served include polycarbonate resin (Lexan) and plastic products, aluminum smelting and recycling, aluminum sheet products, automotive assembly, steel finishing, appliance manufacturing, pharmaceutical and nutritional products, automotive glass, gasoline and oil products, and coal mining. Revenues For the year ended December 31, 2002, retail and firm wholesale electricity sales totaled 6,187,132 MWh, resulting in revenues of approximately $305.3 million. Residential customers accounted for 35% of 2002 revenues; commercial 26%; industrial and municipalities 37%; and other 2%. In addition, the Company sold 10,711,614 MWh through non-firm wholesale contracts in 2002 generating revenue of $302.8 million. Generating Capacity Installed generating capacity as of December 31, 2002 was rated at 1,351 MW. Coal-fired generating units provide 1,056 MW of capacity, and gas or oil-fired turbines used for peaking or emergency conditions provide 295 MW. New peaking capacity of 80 MW fueled by natural gas was added during 2002 and was available for the summer peaking season. In addition to its generating capacity, throughout 2002 the Company had 82MW available under firm contracts and 95 MW available under interruptible contracts. On January 1, 2003, a 50 MW firm contract expired and was no longer required and therefore not renewed. The Company has interconnections with Louisville Gas and Electric Company, Cinergy Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc., Big Rivers Electric Corporation, Wabash Valley Power Association, and the City of Jasper, Indiana, providing the historic ability to simultaneously interchange approximately 500 MW. However, the ability of the Company to effectively utilize the electric transmission grid in order to achieve import/export capability may be impacted because the Company, as a member of the Midwest Independent System Operator (MISO), has turned over operational control over the interchange facilities and its own transmission assets like many other Midwestern electric utilities to the MISO. See Item 7 Management's Discussion and Analysis of Results of Operations and Financial Condition regarding the Company's participation in MISO. Total load for each of the years 1998 through 2002 at the time of the system summer peak, and the related reserve margin, is presented below in MW. Date of summer peak load 8/5/02 7/31/01 8/17/00 7/6/99 7/21/98 ------ ------- ------- ------ ------- Total load at peak (1) 1,258 1,234 1,212 1,255 1,154 Generating capability 1,351 1,271 1,256 1,256 1,256 Firm purchase supply 82 82 75 - - Interruptible contracts 95 95 95 95 85 - ------------------------------------------------------------------------------- Total power supply capacity 1,528 1,448 1,426 1,351 1,341 - ------------------------------------------------------------------------------- Reserve margin at peak 21% 17% 18% 8% 16% - ------------------------------------------------------------------------------- (1) The total load at peak is increased 25MW in 2002, 2001, 1999, and 1998 from the total load actually experienced. The additional 25 MW represents load that would have been incurred if summer cycler programs had not been activated. The 25 MW is also included in the interruptible contract portion of the Company's total power supply capacity. On the date of peak in 2000, summer cycler programs were not activated. The winter peak load of the 2001-2002 season of approximately 854 MW occurred on March 4, 2002 and was 8% lower than the previous winter peak load of approximately 925 MW which occurred on December 19, 2000. The Company maintains a 1.5% interest in the Ohio Valley Electric Corporation (OVEC). The OVEC is comprised of several electric utility companies, including SIGECO and supplies power requirements to the United States Department of Energy's (DOE) uranium enrichment plant near Portsmouth, Ohio. The participating companies are entitled to receive from OVEC, and are obligated to pay for, any available power in excess of the DOE contract demand. At the present time, the DOE contract demand is essentially zero. Because of this decreased demand, the Company's 1.5% interest in the OVEC makes available approximately 32 MW of capacity, in addition to its generating capacity, for use in other operations. Fuel Costs and Purchased Power Electric generation for 2002 was fueled by coal (97.5%) and natural gas (2.5%). Oil was used only for testing of gas/oil-fired peaking units. There are substantial coal reserves in the southern Indiana area, and coal for coal-fired generating stations has been supplied from operators of nearby Indiana coal mines including those owned by Vectren Fuels, Inc., a wholly owned subsidiary of the Company. Approximately 3.1 million tons of coal was purchased for generating electricity during 2002. Of this amount, Vectren Fuels, Inc. supplied 2.7 million tons from its mines and third party purchases. The average cost of coal consumed in generating electrical energy for the years 1998 through 2002 follows: Year -------------------------------------------------------------- Avg. Cost Per 2002 2001 2000 1999 1998 ------- ------- ------- ------- ------- Ton $ 23.50 $ 22.48 $ 22.49 $ 21.88 $ 21.34 MWh 11.00 10.53 10.39 10.13 9.97 The Company will also purchase power as needed from the wholesale market to supplement its generation capabilities in periods of peak demand; however, the majority of power purchased through the wholesale market is used to optimize and hedge the Company's sales to non-firm wholesale customers. Volumes purchased in 2002 totaled 10,362,196 MWh. Regulatory and Environmental Matters See Item 7 Management's Discussion and Analysis of Results of Operations and Financial Condition regarding the Company's regulated environment, and a discussion of the Company's Clean Air Act Compliance Plan, and the USEPA's lawsuit against SIGECO for alleged violations of the Clean Air Act. Competition See Item 7 Management's Discussion and Analysis of Results of Operations and Financial Condition regarding competition within the public utility industry for the Company's regulated Indiana and Ohio operations. Nonregulated Business Segment The Company is involved in nonregulated activities in four primary business areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure Services, and Broadband. Energy Marketing and Services The Energy Marketing and Services group relies heavily upon a customer focused, value added strategy. The group provides natural gas and fuel supply management services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions through ProLiance. ProLiance is a significant gas supplier to the Company's regulated operations. The group also focuses on performance-based energy contracting through Energy Systems Group, LLC. This service helps schools, hospitals, and other governmental and private institutions reduce their energy and maintenance costs by upgrading their facilities with energy-efficient equipment. ProLiance is an unconsolidated affiliate of the Company and Citizens Gas and Coke Utility (Citizens Gas). Energy Systems Group, LLC is a consolidated venture between the Company and Citizens Gas, with the Company owning two-thirds. In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP Energy Services, LLC (SES) with ProLiance was completed. SES provided natural gas and related services to SIGECO and others prior to the integration. In exchange for the contribution of SES' net assets totaling $19.2 million, including cash of $2.0 million, Vectren's allocable share of ProLiance's profits and losses increased from 52.5% to 61%, consistent with Vectren's new ownership percentage. In March 2001 Vectren's allocable share of profits and losses increased from 50% to 52.5% when ProLiance began managing the Ohio operations' gas portfolio. Governance and voting rights remain at 50% for each member. Since governance of ProLiance remains equal between the members, Vectren continues to account for its investment in ProLiance using the equity method of accounting. At December 31, 2002, the Energy Marketing and Services group's natural gas marketing operations had 1,060 customers, up from 984 in 2001. The collective revenue of ProLiance and SES exceeded $1.7 billion in 2002. Coal Mining The Coal Mining group provides the mining and sale of coal to the Company's utility operations and to other third parties through its wholly owned subsidiary Vectren Fuels, Inc. The Coal Mining group also generates income tax credits through IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels through its 8.3% ownership in Pace Carbon Synfuels, LP. The Company's two coal mines produced 3.5 million tons in 2002, up from 3.3 million in 2001. The Company's investment in Pace Carbon is accounted for using the equity method of accounting. Utility Infrastructure Services Utility Infrastructure Services provides underground construction and repair of utility infrastructure services to the Company and to other gas, water, electric, and telecommunications companies as well as facilities locating and meter reading services through its investment in Reliant Services, LLC (Reliant). Reliant is a 50% owned strategic alliance with an affiliate of Cinergy Corp. and is accounted for using the equity method of accounting. In December 2000, Reliant purchased the common stock of Miller Pipeline Corporation (Miller) from NiSource, Inc. for approximately $68.3 million. Vectren and Cinergy Corp. each contributed $16.0 million of equity, and the remaining $36.3 million was funded with 7-year intermediate bank loans. The acquisition combines Reliant's utility services of underground facility locating, contract meter reading, and installation of telecommunications infrastructure with Miller's underground pipeline construction, replacement, and repair services. Miller is one of the nation's premier natural gas distribution contractors with over 50 years of experience in the construction industry, currently providing such services to Indiana Gas, among other customers. Broadband Broadband invests in broadband communication services such as cable television, high-speed Internet, and advanced local and long distance phone services. The Broadband group provides telecommunications services to approximately 26,800 residential and commercial customers (an increase of 7.9% from 2001) in the greater Evansville area in southwestern Indiana. The present customer base has yielded approximately 78,000 residential revenue generating units (up from approximately 70,000 at the end of 2001) indicating multiple services being utilized by the same residential customer. The Company has an approximate 1% equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom). Utilicom is a provider of bundled communication services focusing on last mile delivery to residential and commercial customers. The Company also has an 18.9% equity interest in SIGECOM Holdings, Inc., which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to the greater Evansville, Indiana, area. Utilicom also plans to provide services to Indianapolis, Indiana, and Dayton, Ohio. However, the funding of these projects has been delayed due to the continued difficult environment within the telecommunication capital markets, which has prevented Utilicom from obtaining debt financing on terms it considers acceptable. While the existing investors remain interested in the Indianapolis and Dayton projects, the Company is not required to make further investments and does not intend to proceed unless commitments are obtained to fully fund these projects. Franchising agreements have been extended in both locations. The convertible subordinated debt investment totals $30.7 million, of which $28.6 million is convertible into Utilicom ownership at the Company's option or upon the event of a public offering of stock by Utilicom and $2.1 million is convertible into common equity interests in the Indianapolis and Dayton ventures at the Company's option. Upon conversion, the Company would have up to a 12% interest in Utilicom, assuming completion of all required funding and up to a 31% interest in the Indianapolis and Dayton ventures. Other Businesses In addition to the nonregulated business groups previously discussed, the Other Businesses group invests in a portfolio of interests in gas and power storage, distributed generation projects, and similar energy-related businesses. Additional activities include: o A utility services business, which supplies utilities with a number of important services ranging from supply chain management to environmental compliance testing. o A retail unit, providing natural gas and other related products and services primarily in Ohio serving customers opting for choice among energy providers. o A broadband consulting business. Major investments include Haddington Energy Partnerships, two partnerships both approximately 40% owned; CIGMA, LLC, a 50% owned strategic alliance with an affiliate of Citizens Gas; and the wholly owned subsidiaries Southern Indiana Properties, Inc., Energy Realty, Inc., Vectren Retail, LLC, Vectren Communication Services, Inc., and IEI Financial Services, LLC. Personnel As of December 31, 2002, the Company and its consolidated subsidiaries had 1,876 employees, of which 896 are subject to collective bargaining arrangements. In August 2001, the Company signed a new four-year labor agreement, ending in September 2005 with Local 135 of the Teamsters, Chauffeurs, Warehousemen and Helpers. The new agreement provides for annual wage increases of 3.25%, a new 401(k) savings plan and improvements in the areas of health insurance and pension benefits. Concurrent with the Company's purchase of the Ohio operations, VEDO and Local Union 175, Utility Workers Union of America approved a labor agreement effective November 2000, through October 2005. The agreement provides a 3.25% wage increase each year, and the other terms and conditions are substantially the same as the agreement reached between the Utility Workers Union and Dayton Power and Light Company in August of 2000. In July 2000, SIGECO signed a new four-year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 2004. The new agreement provides a 3% wage increase for each year in addition to improvements in health care coverage, retirement benefits and incentive pay. ITEM 2. PROPERTIES Gas Utility Services Indiana Gas owns and operates four gas storage fields located in Indiana covering 58,489 acres of land with an estimated ready delivery from storage capability of 4.2 BCF of gas with delivery capabilities of 119,160 MCF per day. Indiana Gas also owns and operates three liquefied petroleum (propane) air-gas manufacturing plants located in Indiana with the ability to store 1.5 million gallons of propane and manufacture for delivery 31,000 MCF of manufactured gas per day. In addition to its owned storage and manufacturing and daily delivery capabilities, Indiana Gas contracts for a maximum of 17.2 BCF of gas availability across various pipelines with a delivery capability of 283,298 MCF per day. Indiana Gas' gas delivery system includes 11,590 miles of distribution and transmission mains, all of which are in Indiana except for pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported by Indiana Gas to ultimate customers in Indiana. SIGECO owns and operates three underground gas storage fields located in Indiana covering 6,070 acres of land with an estimated ready delivery from storage capability of 8.7 BCF of gas with delivery capabilities of 124,748 MCF per day. In addition to its owned storage and daily delivery capabilities, SIGECO contracts for a maximum of 0.5 BCF of gas availability across various pipelines with a delivery capability of 18,753 MCF per day. SIGECO's gas delivery system includes 2,996 miles of distribution and transmission mains, all of which are located in Indiana. The Ohio operations owns and operates three liquefied petroleum (propane) air-gas manufacturing plants and one cavern for propane storage, all of which are located in Ohio. The plants and cavern can store 3.7 million gallons of propane, and the plants can manufacture for delivery 51,047 MCF of manufactured gas per day. In addition to its owned storage and manufacturing and daily delivery capabilities, the Ohio operations contracts for a maximum of 13.2 BCF of gas availability across various pipelines with a delivery capability of 281,491 MCF per day. The Ohio operations' gas delivery system includes 5,176 miles of distribution and transmission mains, all of which are located in Ohio. Electric Utility Services SIGECO's installed generating capacity as of December 31, 2002, was rated at 1,351 MW. SIGECO's coal-fired generating facilities are: the Brown Station with 500 MW of capacity, located in Posey County approximately eight miles east of Mt. Vernon, Indiana; the Culley Station with 406 MW of capacity, and Warrick Unit 4 with 150 MW of capacity. Both the Culley and Warrick Stations are located in Warrick County near Yankeetown, Indiana. SIGECO's gas-fired turbine peaking units are: the 80 MW Brown 3 Gas Turbine located at the Brown Station; two Broadway Avenue Gas Turbines located in Evansville, Indiana with a combined capacity of 115 MW (Broadway Avenue Unit 1, 50MW and Broadway Avenue Unit 2, 65MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20 MW; and a new 80MW turbine also located at the Brown station (Brown Unit 4) placed into service in 2002. The Brown Unit 3 and Broadway Avenue Unit 2 turbines are also equipped to burn oil. Total capacity of SIGECO's six gas turbines is 295 MW, and they are generally used only for reserve, peaking, or emergency purposes due to the higher per unit cost of generation. SIGECO's transmission system consists of 829 circuit miles of 138,000 and 69,000 volt lines. The transmission system also includes 27 substations with an installed capacity of 4,221.2 megavolt amperes (Mva). The electric distribution system includes 3,212 pole miles of lower voltage overhead lines and 275 trench miles of conduit containing 1,541 miles of underground distribution cable. The distribution system also includes 95 distribution substations with an installed capacity of 1,939.5 Mva and 51,030 distribution transformers with an installed capacity of 2,352.3 Mva. SIGECO owns utility property outside of Indiana approximating eight miles of 138,000 volt electric transmission line which is located in Kentucky and which interconnects with Louisville Gas and Electric Company's transmission system at Cloverport, Kentucky. Nonregulated Services Subsidiaries other than the utility operations have no significant properties other than the ownership and operation of coal mining property in Indiana and investments in real estate partnerships, leveraged leases, and notes receivable. The assets of the coal mining operations comprise approximately 3 percent of total assets. Property Serving as Collateral SIGECO's properties are subject to the lien of the First Mortgage Indenture dated as of April 1, 1932 between SIGECO and Bankers Trust Company, as Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various supplemental indentures. ITEM 3. LEGAL PROCEEDINGS The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 14 of its consolidated financial statements included in Item 8 Financial Statements and Supplementary Data regarding the Clean Air Act and related legal proceedings. Legal proceedings involving transactions with ProLiance were substantially resolved during 2002. See Note 4 for a discussion of regulatory matters related to ProLiance. ITEM 4. Submission of Matters to Vote of Security Holders No matters were submitted during the fourth quarter to a vote of security holders. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's common stock trades on the New York Stock Exchange under the symbol "VVC." For each quarter in 2002 and 2001, the high and low sales prices for the Company's common stock as reported on the New York Stock Exchange and dividends paid are shown in the following table. Common Stock Price Range Cash ------------------------- 2002 Dividend High Low -------- ------- ------- First Quarter $ 0.265 $ 25.95 $ 22.45 Second Quarter 0.265 26.10 23.10 Third Quarter 0.265 25.44 17.95 Fourth Quarter 0.275 25.00 21.05 2001 First Quarter $ 0.255 $ 24.44 $ 21.00 Second Quarter 0.255 23.90 20.38 Third Quarter 0.255 22.46 19.76 Fourth Quarter 0.265 24.07 21.05 On January 22, 2003, the board of directors declared a dividend of $0.275 per share, payable on March 3, 2003, to common shareholders of record on February 14, 2003. As of January 31, 2003, there were 13,460 shareholders of record of the Company's common stock. Dividends on shares of common stock are payable at the discretion of the board of directors out of legally available funds. Future payments of dividends, and the amounts of these dividends, will depend on the Company's financial condition, results of operations, capital requirements, and other factors. ITEM 6. SELECTED FINANCIAL DATA The following selected financial data is derived from the Company's audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto contained in this Form 10-K. The financial information as of and for the years ended December 31, 2001 and 2000 has been restated. Common shareholders' equity as of January 1, 2000 also reflects adjustments related to years prior to 2000. See Note 3 to the consolidated financial statements included under Item 8 Financial Statements and Supplementary Data for further information on the restatement.
Year Ended December 31 - ------------------------------------------------------------------------------------------------------ In millions, except per share data 2002 2001 (1) 2000(2,3) 1999 1998 - ------------------------------------------------------------------------------------------------------ (As Restated) -------------------- Operating Data: Operating revenues $ 1,804.3 $ 2,081.8 $ 1,632.8 $ 1,068.4 $ 997.7 Operating income $ 211.3 $ 127.9 $ 131.7 $ 160.8 $ 148.5 Income before extraordinary loss & cumulative effect of change in accounting principle $ 114.0 $ 59.3 $ 72.0 $ 90.7 $ 86.6 Net income $ 114.0 $ 52.7 $ 72.0 $ 90.7 $ 86.6 Average common shares outstanding 67.6 66.7 61.3 61.3 61.6 Fully diluted common shares outstanding 67.9 66.9 61.4 61.4 61.8 Basic earnings per share before extraordinary loss & cumulative effect of change in accounting principle $ 1.69 $ 0.89 $ 1.18 $ 1.48 $ 1.41 Basic earnings per share on common stock $ 1.69 $ 0.79 $ 1.18 $ 1.48 $ 1.41 Diluted earnings per share before extraordinary loss & cumulative effect of change in accounting principle $ 1.68 $ 0.89 $ 1.17 $ 1.48 $ 1.40 Diluted earnings per share on common stock $ 1.68 $ 0.79 $ 1.17 $ 1.48 $ 1.40 Dividends per share on common stock 1.07 $ 1.03 $ 0.98 $ 0.94 $ 0.90 Balance Sheet Data: Total assets $ 2,926.5 $ 2,878.7 $ 2,943.7 $ 1,980.5 $ 1,798.8 Long-term debt, net $ 954.2 $ 1,014.0 $ 632.0 $ 486.7 $ 388.9 Redeemable preferred stock $ 0.3 $ 0.5 $ 8.1 $ 8.2 $ 8.3 Common shareholders' equity $ 869.9 $ 839.3 $ 733.4 $ 709.8 $ 677.9
(1) Merger and integration related costs incurred for the year ended December 31, 2001 totaled $2.8 million. These costs relate primarily to transaction costs, severance and other merger and acquisition integration activities. As a result of merger integration activities, management retired certain information systems in 2001. Accordingly, the useful lives of these assets were shortened to reflect this decision, resulting in additional depreciation expense of approximately $9.6 million for the year ended December 31, 2001. In total, merger and integration related costs incurred for the year ended December 31, 2001 were $12.4 million ($8.0 million after tax). The Company incurred restructuring charges of $19.0 million, ($11.8 million after tax) relating to employee severance, related benefits and other employee related costs, lease termination fees related to duplicate facilities, and consulting and other fees. (2) Merger and integration related costs incurred for the year ended December 31, 2000 totaled $41.1 million. These costs relate primarily to transaction costs, severance and other merger and acquisition integration activities. As a result of merger integration activities, management identified certain information systems to be retired in 2001. Accordingly, the useful lives of these assets were shortened to reflect this decision, resulting in additional depreciation expense of approximately $11.4 million for the year ended December 31, 2000. In total, merger and integration related costs incurred for the year ended December 31, 2000 were $52.5 million ($36.8 million after tax). (3) Reflects two months of results of the Ohio operations. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto. As discussed in Note 3 in the consolidated financial statements, subsequent to the issuance of the Company's 2001 financial statements, the Company's management determined that previously issued financial statements should be restated. As a result, the Company has restated its 2001 and 2000 financial statements and has increased reported retained earnings as of January 1, 2000 by $1.7 million. The restatement had the effect of decreasing net income for 2001 and 2000 by $10.9 million and $48,000, respectively. Note 3 in the consolidated financial statements includes a summary of the significant effects of the restatement. The effect of the restatement on quarterly results, including previously reported 2002 quarterly information, is discussed in Note 21. The following discussion and analysis gives effect to the restatement. Consolidated Results of Operations Year Ended December 31, - ---------------------------------------------------------------------------- In millions, except per share amounts 2002 2001 2000 - ---------------------------------------------------------------------------- (As Restated) --------------------- Net income $114.0 $ 52.7 $ 72.0 Attributed to: Regulated $ 93.6 $ 40.1 $ 52.5 Nonregulated 19.0 12.1 21.8 Corporate & other 1.4 0.5 (2.3) - ---------------------------------------------------------------------------- Basic earnings per share $ 1.69 $ 0.79 $ 1.18 Attributed to: Regulated $ 1.39 $ 0.60 $ 0.85 Nonregulated 0.28 0.18 0.36 Corporate & other 0.02 0.01 (0.03) In 2002, consolidated net income increased $61.3 million, or $0.90 per share, when compared to 2001, as restated. The year ended December 31, 2001 included nonrecurring merger, integration, and restructuring costs and other nonrecurring items totaling $26.4 million after tax, or $0.40 per share. In addition to the nonrecurring 2001 items, the increase reflects improved margins and lower operating costs. These resulted from favorable weather and a return to lower gas prices and the related reduction in costs incurred in 2001. Also contributing to the increase was increased earnings from the Energy Marketing and Services Group and a smaller loss in the Other Businesses Group, both of which are components of nonregulated operations. In 2001, consolidated net income decreased $19.3 million, or $0.39 per share, compared to 2000. The year ended December 31, 2000 included nonrecurring merger, integration, and restructuring costs net of other nonrecurring items totaling $31.9 million after tax, or $0.52 per share. The decrease reflects lower regulated earnings resulting from extraordinarily high gas costs early in 2001 that unfavorably impacted margins and operating costs, warmer heating weather, especially during late 2001, and a weakened national economy. This reduction was offset somewhat by increased earnings from the Energy Marketing and Services and Coal Mining Groups, both of which are components of nonregulated operations, and a decrease in nonrecurring items. Dividends In November 2002, the Company's board of directors increased its quarterly dividend to $0.275 per share from $0.265 per share. Dividends declared for the year ended December 31, 2002 were $1.07 per share, compared to $1.03 per share and $0.98 per share for the same periods in 2001 and 2000, respectively. Restatement of Previously Reported Results The Company identified adjustments that, in the aggregate, reduced previously reported 2001 earnings by approximately $10.9 million after tax, or $0.16 per share, and other adjustments, as described below, related to 2000 and prior periods. Adjustments were also made to previously reported 2002 quarterly results. In addition to adjustments affecting previously reported net income, other reclassifications were made to the previously reported 2001 and 2000 results to conform with the 2002 presentation. Previously Reported 2001 and 2000 Net Income Adjustments The Company determined that $11.6 million ($7.2 million after tax) of gas costs were improperly recorded as recoverable gas costs due from customers. The error related primarily to the accounting for natural gas inventory and resulted in an overstatement of 2001 earnings. The Company also identified an accounting error related to certain employee benefit and other related costs that are routinely accumulated on the balance sheet and systematically cleared to operating expense and capital projects. Because of inadequate loading rates, these costs were not fully cleared to operating expense and capital projects in 2001. As a result, 2001 earnings were overstated by $5.6 million ($3.5 million after tax). The accounting for certain wholesale power marketing contracts was modified to comply with SFAS 133, which became effective on January 1, 2001. The cumulative effect at adoption was decreased by $2.8 million after tax. This change was offset substantially by an increase in electric margins throughout 2001. The Company identified reconciliation errors and other errors related to the recording of estimates that were not significant, either individually or in the aggregate. As a result of these additional items, 2001 earnings were reduced by $2.6 million ($1.6 million after tax). Originally reflected in 2001, the correction of the year 2000 overstatement of electric revenue totaling $2.4 million ($1.5 million after tax), now reflected in 2000 as discussed below, significantly offset these additional items. The Company also determined that certain billings and collections had been improperly recorded in 2000, resulting in an understatement of gas revenue by $1.8 million ($1.1 million after tax) and an overstatement of electric revenue by $2.4 million ($1.5 million after tax). Other errors were identified that increased 2000 earnings by $0.6 million ($0.3 million after tax). The impact of the restatement of results for the year ended 2000 is a reduction to net income of less than $100,000. In addition, the Company also reduced previously reported revenues and cost of sales by $78.1 million in 2001 and $15.5 million in 2000 to adopt EITF Issue No. 99-19 "Reporting Revenue Gross as a Principal versus Net as an Agent" and to properly eliminate certain transactions in consolidation. Previously Reported 2002 Quarterly Net Income Adjustments As previously reported, in the second quarter of 2002 the Company recorded $5.2 million ($3.2 million after tax) of carrying costs for DSM programs pursuant to existing IURC orders and based on an improved regulatory environment. During the audit of the three years ended December 31, 2002, management determined that the accrual of such carrying costs was more appropriate in periods prior to 2000 when DSM program expenditures were made. Therefore, such carrying costs originally reflected in 2002 quarterly results were reversed and reflected in common shareholders' equity as of January 1, 2000. In addition, the Company identified other adjustments that were not significant, either individually or in the aggregate that increased previously reported 2002 quarterly pre-tax and after tax earnings by approximately $1.4 million and $0.9 million after tax, respectively. The cumulative impact from of these adjustments reduced previously reported earnings for the nine months ended September 30, 2002 by approximately $2.3 million. Beginning Retained Earnings Adjustments In addition to the adjustment of DSM costs above, the Company identified other errors that were not significant, either individually or in the aggregate that relate to years prior to 2000. As a result of these additional items, beginning common shareholders' equity was reduced by $1.5 million. Accordingly, retained earnings as of January 1, 2000 reflects a cumulative net increase of $1.7 million. Other Balance Sheet Adjustments Certain reclassifications were made to reflect separate Company prepaid and accrued taxes that result in the consolidated tax position. This adjustment added approximately $46.4 million of prepaid and other current assets with a corresponding increase in accrued liabilities as of December 31, 2001. The Company also reclassified all previously recorded goodwill not included in rates to goodwill on the balance sheet. This adjustment resulted in a $5.9 million decrease in other assets, a $3.0 million decrease in prepayments and other current assets and an $8.9 million increase in goodwill. The Company has restated its financial statements to give effect to the matters discussed above. A summary of the significant effects of the restatement on previously reported financial position and results of operations is discussed in Note 3. The effects of the restatement on 2001 quarterly results and on 2002 previously reported quarterly information, is discussed in Note 21. The consolidated financial statements are included under Item 8 Financial Statements and Supplementary Data. Nonrecurring Items in 2001 and 2000 Merger & Integration Costs Merger and integration costs incurred for the years ended December 31, 2001 and 2000 were $2.8 million and $41.1 million, respectively. Merger and integration activities resulting from the 2000 merger were completed in 2001. Since March 31, 2000, $43.9 million has been expensed associated with merger and integration activities. Accruals were established at March 31, 2000 totaling $20.7 million. Of this amount, $5.5 million related to employee and executive severance costs, $13.1 million related to transaction costs and regulatory filing fees incurred prior to the closing of the merger, and the remaining $2.1 million related to employee relocations that occurred prior to or coincident with the merger closing. The remaining $23.2 million was expensed ($20.4 million in 2000 and $2.8 million in 2001) for accounting fees resulting from merger-related filing requirements, consulting fees related to integration activities such as organization structure, employee travel between company locations, internal labor of employees assigned to integration teams, investor relations communication activities, and certain benefit costs. The integration activities experienced by the Company included such things as information system consolidation, process review and definition, organization design and consolidation, and knowledge sharing. As a result of merger integration activities, management retired certain information systems in 2001. Accordingly, the useful lives of these assets were shortened in 2000 to reflect this decision, resulting in additional depreciation expense of approximately $9.6 million and $11.4 million for the years ended December 31, 2001 and 2000, respectively. In total, for the year ended December 31, 2001, merger and integration costs totaled $12.4 million ($8.0 million after tax), or $0.12 on a basic earnings per share basis compared to $52.5 million ($36.8 million after tax), or $0.60 on a basic earnings per share basis in 2000. Restructuring Costs As part of continued cost saving efforts, in June 2001, the Company's management and board of directors approved a plan to restructure, primarily, its regulated operations. The restructuring plan included the elimination of certain administrative and supervisory positions in its utility operations and corporate office. Charges of $11.8 million were expensed in June 2001 as a direct result of the restructuring plan. Additional charges of $7.2 million were incurred during the remainder of 2001 primarily for consulting fees, employee relocation, and duplicate facilities costs. In total, the Company incurred restructuring charges of $19.0 million, ($11.8 million after tax), or $0.18 on a basic earnings per share basis in 2001. These charges were comprised of $10.9 million for employee severance, related benefits and other employee related costs, $4.0 million for lease termination fees related to duplicate facilities and other facility costs, and $4.1 million for consulting and other fees incurred through December 31, 2001. The restructuring program was completed during 2001, except for the departure of certain employees impacted by the restructuring which occurred during 2002 and the final settlement of the lease obligation which has yet to occur. (See Note 19 for further information on restructuring costs.) Extraordinary Loss In June 2001, the Company sold certain leveraged lease investments with a net book value of $59.1 million at a loss of $12.4 million ($7.7 million after tax), or $0.12 on a basic earnings per share basis. Because of the transaction's significance and because the transaction occurred within two years of the effective date of the merger of Indiana Energy and SIGCORP, which was accounted for as a pooling-of-interests, APB 16 requires the loss on disposition of these investments to be treated as extraordinary. Proceeds from the sale of $46.7 million were used to retire short-term borrowings. Cumulative Effect of Change in Accounting Principle Resulting from the adoption of SFAS 133, certain contracts in the power marketing operations and gas marketing operations that are periodically settled net were required to be recorded at market value. Previously, the Company accounted for these contracts on settlement. The cumulative impact of the adoption of SFAS 133 resulting from marking these contracts to market on January 1, 2001 was an earnings gain of approximately $1.8 million ($1.1 million after tax), or $0.02 on a basic earnings per share basis, recorded as a cumulative effect of change in accounting principle in the Consolidated Statements of Income. The majority of this gain results from the Company's power marketing operations. Gain on Restructuring of a Nonregulated Investment In January 2000, the Company restructured its investment in SIGECOM, LLC (SIGECOM). Affiliates of The Blackstone Group acquired a majority ownership interest in Utilicom. In connection with The Blackstone Group investment, the Company exchanged its 49% preferred equity interest in SIGECOM for $16.5 million of convertible subordinated debt of Utilicom Networks LLC and an 18.9% common equity interest in SIGECOM Holdings, Inc, which was valued at $6.5 million. The carrying value of the Company's 49% preferred equity interest was $15.0 million prior to the exchange. The Company received consideration in the exchange based upon an investment bank analysis of the fair value of SIGECOM at the transaction date. The investment restructuring resulted in a pre-tax gain of $8.0 million ($4.9 million after tax), or $0.08 on a basic earnings per share basis, which is classified in equity in earnings of unconsolidated affiliates in the Consolidated Statements of Income. Refer to Note 4 for more information on the Company's investment in Utilicom-related entities. Results of Operations by Business Segment Following is a more detailed discussion of the results of operations of the Company's regulated and nonregulated businesses. The detailed results of operations for the regulated businesses and nonregulated businesses are discussed and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company's Consolidated Statements of Income. The operations of the Corporate and Other business segment, which include primarily information technology services, are not significant. Results of Operations of the Regulated Businesses The Company's regulated operations are comprised of its Gas Utility Services and Electric Utility Services segments. The Gas Utility Services segment includes the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas distribution business and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and west central Ohio. The Electric Utility Services segment includes the operations of SIGECO's electric transmission and distribution services, which provides electricity primarily to southwestern Indiana, and SIGECO's power generating and power marketing operations. The results of regulated operations before certain intersegment eliminations and reclassifications for the years ended December 31, 2002, 2001, and 2000 follows: In millions, except per share amounts 2002 2001 2000 - --------------------------------------------------------------------------- OPERATING REVENUES (As Restated) -------------------- Gas revenues $ 909.0 $ 1,019.6 $ 820.4 Electric revenues 608.1 381.2 334.4 - --------------------------------------------------------------------------- Total operating revenues 1,517.1 1,400.8 1,154.8 - --------------------------------------------------------------------------- COST OF OPERATING REVENUES Cost of gas 571.8 708.9 552.5 Fuel for electric generation 81.6 74.4 75.7 Purchased electric energy 296.3 86.9 36.4 - --------------------------------------------------------------------------- Total cost of operating revenues 949.7 870.2 664.6 - --------------------------------------------------------------------------- TOTAL OPERATING MARGIN 567.4 530.6 490.2 OPERATING EXPENSES Other operating 220.6 241.1 209.0 Merger & integration costs - 2.8 32.7 Restructuring costs - 15.0 - Depreciation & amortization 96.8 97.2 82.4 Taxes other than income taxes 50.8 51.2 36.2 - --------------------------------------------------------------------------- Total expenses 368.2 407.3 360.3 - --------------------------------------------------------------------------- OPERATING INCOME 199.2 123.3 129.9 OTHER INCOME Other - net 6.9 5.5 4.7 Equity in earnings of unconsolidated affiliates (1.8) (0.5) - - --------------------------------------------------------------------------- Total other income 5.1 5.0 4.7 - --------------------------------------------------------------------------- Interest expense 66.1 70.1 46.1 - --------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 138.2 58.2 88.5 - --------------------------------------------------------------------------- Income tax 44.6 18.4 35.0 Preferred dividend requirement of subsidiary - 0.8 1.0 - --------------------------------------------------------------------------- Income before cumulative effect of change in accounting principle 93.6 39.0 52.5 Cumulative effect of change in accounting principle - net of tax - 1.1 - - --------------------------------------------------------------------------- NET INCOME $ 93.6 $ 40.1 $ 52.5 =========================================================================== BASIC EARNINGS PER SHARE $ 1.39 $ 0.60 $ 0.85 =========================================================================== Utility operations contributed net income of $93.6 million, or $1.39 per share, for the year ended December 31, 2002 compared to $40.1 million, or $0.60 per share, in 2001. The year ended December 31, 2001 included nonrecurring merger, integration, and restructuring costs and other nonrecurring items totaling $15.9 million after tax, or $0.24 per share. In addition to the nonrecurring 2001 items, the increase of $53.5 million, or $0.79 per share, was primarily the result of improved margins and lower operating expense. These resulted from favorable weather and a return to lower gas prices and the related reduction in costs incurred in 2001. Weather increased utility earnings by an estimated $11 million. For 2001 compared to 2000, net income decreased $12.4 million, or $0.25 per share. The year ended December 31, 2000 included nonrecurring merger and integration costs totaling $31.6 million, or $0.51 per share. The decrease is due to extraordinarily high gas costs early in 2001 that unfavorably impacted margins and operating costs, including uncollectible accounts expense, interest, and excise taxes; and heating weather that was 9% warmer than the prior year. Significant Fluctuations Utility Margin Gas Utility Margin Gas Utility margin for the year ended December 31, 2002 of $337.2 million increased $26.5 million, or 9%. The increase is primarily due to weather 7% cooler for the year and 31% cooler in the fourth quarter. Rate recovery of excise taxes in Ohio effective July 1, 2001, an increase in the Percent of Income Payment Plan rider affecting Ohio customers, decreased gas costs, and customer growth of over 1% also contributed. It is estimated that of the increase in gas utility margin weather contributed $10 million, various rate recovery riders in Ohio contributed $7 million, and other items, including the impact of lower gas costs and customer growth, contributed $9 million. The effects of cooler weather resulted in an overall 4% increase in total throughput to 207.7 MMDth in 2002 from 199.3 MMDth in 2001. Total throughput in 2000 was 181.2 MMDth, which includes two months of throughput from the Ohio operations. Gas Utility margin for the year ended December 31, 2001 of $310.7 million increased $42.8 million, compared to 2000. Excluding the Ohio operations, gas margin decreased by $15.7 million, or 6%. The primary factors contributing to this decrease were weather that was 9% warmer than the prior year and the unfavorable impact resulting from extraordinarily high gas costs early in 2001, coupled with the effects of a weakened economy. These decreases were offset somewhat by customer growth of nearly 1% compared to 2000. Cost of gas sold was $571.8 million in 2002, $708.9 million in 2001, and $552.5 million in 2000. Cost of gas sold decreased $137.1 million, or 19%, during 2002 compared to 2001, primarily due to a return to lower gas prices somewhat offset by an increase in retail volumes sold. Of the change in 2001 compared to 2000, the Ohio operations contributed $179.4 million of the increase. Excluding the Ohio operations, cost of gas sold decreased $23.0 million, or 4%, in 2001. The decrease is primarily due to lower volumes sold due to the warmer weather and a weakened economy, offset by an increase in gas prices. The total average cost per dekatherm of gas purchased was $4.57 in 2002, $5.83 in 2001, and $5.60 in 2000. The price changes are due primarily to changing commodity costs in the marketplace. Electric Utility Margin Electric Utility margin by customer type and non-firm wholesale margin separated between realized margin and mark-to-market gains and losses follows: Year ended December 31, - ---------------------------------------------------------------------------- In millions 2002 2001 2000 - ---------------------------------------------------------------------------- Retail & firm wholesale $ 215.3 $ 200.0 $ 201.2 Non-firm wholesale 14.9 19.9 21.1 - ---------------------------------------------------------------------------- Total margin $ 230.2 $ 219.9 $ 222.3 ============================================================================ Non-firm wholesale margin: Realized margin $ 18.5 $ 18.4 $ 21.1 Mark-to-market gains (losses) (3.6) 1.5 - Electric Utility margin for the year ended December 31, 2002 increased $10.3 million, or 5%, when compared to 2001. The increases result primarily from the effect on retail sales of cooling weather considerably warmer than the prior year. Weather in 2002 was 27% warmer when compared to 2001 and 23% warmer than normal. In addition to weather, 2002 was positively affected by increased industrial and firm wholesale volumes and a cash return on NOx compliance expenditures as the expenditures are made pursuant to a rate recovery rider approved by the IURC in August 2001. As a result of warmer weather and increased volumes sold, retail and firm wholesale volumes sold increased from 5.8 GWh in 2001 to 6.2 GWh in 2002. Volumes sold in 2000 were 5.9 GWh. It is estimated that of the increase in electric utility margin weather contributed $7 million, and the increased industrial and firm wholesale volumes and NOx recovery rider contributed $8 million. The current year increase in margin from retail sales was partially offset by $5 million in lower margins earned in the wholesale energy market. Electric Utility margin for the year ended December 31, 2001 decreased $2.4 million, or 1%, compared to 2000 primarily from decreased sales to firm wholesale customers and decreased margin on non-firm wholesale activity. The decreases were partially offset by a 3% increase in residential and commercial sales due to cooling weather 7% warmer than the prior year and a 3% increase in the number of residential and commercial customers. Periodically, generation capacity is in excess of that needed to serve retail and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. The contracts entered into are primarily short-term purchase and sale transactions that expose the Company to limited market risk. While volumes both sold and purchased in the wholesale market have increased during 2002, margins softened as a result of reduced price volatility. As a result of increased activity offset by reduced price volatility, margin from power marketing activities decreased $5.0 million during 2002 and $1.2 million during 2001. In 2002, volumes sold into the wholesale market were 10.7 GWh compared to 3.4 GWh in 2001 and 1.6 GWh in 2000. Volumes purchased from the wholesale market, some of which were utilized to serve retail and firm wholesale customers, were 10.3 GWh in 2002 compared to 2.9 GWh in 2001 and 1.2 GWh in 2000. Utility Operating Expenses Utility Other Operating Utility other operating expenses decreased $20.5 million for the year ended December 31, 2002 when compared to 2001. The decrease results primarily from $9.6 million in lower charges for the use of corporate assets which had useful lives shortened as a result of the merger and a return to lower gas prices and the related reduction in costs incurred in 2001. Specific expenses affected by increased gas costs in 2001 were uncollectible accounts expense of $3.4 million and contributions to low income heating assistance programs of $2.0 million. Insurance recovery in 2002 of $2.8 million in maintenance costs incurred in 2001 was the primary component of the remaining decrease. Excluding $33.2 million in additional expenses related to the Ohio operations, utility other operating expenses for the year ended December 31, 2001 decreased $1.1 million compared to 2000. The 2001 decrease results primarily from prior merger synergies, offset by higher expenses resulting from increased gas costs. Utility Depreciation & Amortization Utility depreciation and amortization decreased $0.4 million for the year ended December 31, 2002 when compared to 2001. The decrease results from the discontinuance of goodwill amortization as required by SFAS 142, which approximated $4.9 million in 2001, offset somewhat by depreciation of plant additions. Utility depreciation and amortization increased $14.8 million in 2001 when compared to 2000. The increase is due to the inclusion of the Ohio operations and depreciation of normal utility plant additions at Indiana Gas and SIGECO. For the year ended December 31, 2001, the increase in utility depreciation and amortization related to the Ohio operations was $12.9 million, including amortization of goodwill of $4.9 million. Utility Taxes Other Than Income Taxes Utility taxes other than income taxes decreased $0.4 million in 2002 compared to 2001 as a result of lower revenues subject to gross receipts tax and increased $15.0 million in 2001 compared to 2000. The year ended December 31, 2001 includes $15.3 million of additional expense related to the Ohio operations, primarily state excise tax. Utility Other Income - Net Other- net Utility other income, net increased $1.4 million in 2002 when compared to 2001 and amounts in 2001 were comparable to 2000. The increase in 2002 is primarily attributable to gains recognized from the sale of excess emission allowances. Equity in Earnings of Unconsolidated Affiliates Equity in earnings of unconsolidated affiliates decreased $1.3 million in 2002 and $0.5 million in 2001 principally due to increased losses and increased ownership in a company that manufactures autoclaved aerated concrete products from fly ash. Utility Interest Expense Utility interest expense decreased $4.0 million in 2002 compared to 2001. The decrease is attributable to lower outstanding borrowings during 2002 and lower average interest rates on adjustable rate debt. Utility interest expense increased $24.0 million during the 2001 compared to 2000. The increase is due primarily to interest related to financing the acquisition of the Ohio operations and increased working capital requirements resulting from higher natural gas prices. Utility Income Tax Federal and state income taxes related to utility operations increased $26.2 million for the year ended December 31, 2002 when compared to 2001. The increase results principally from higher pre-tax earnings. The effective tax rate increased from 31.6% in 2001 to 32.3% in 2002 due to amortization of investment tax credits and higher pre-tax income. Federal and state income taxes related to utility operations decreased $16.6 million in 2001 when compared to 2000. The 2001 decrease is due to lower pre-tax earnings. The effective tax rate decreased from 39.5% in 2000 to 31.6% in 2001. This decrease results primarily from the nondeductibility of certain merger and integration costs incurred in 2000 and amortization of investment tax credits. Competition The utility industry has been undergoing dramatic structural change for several years, resulting in increasing competitive pressures faced by electric and gas utility companies. Increased competition may create greater risks to the stability of utility earnings generally and may in the future reduce earnings from retail electric and gas sales. Currently, several states, including Ohio, have passed legislation allowing electricity customers to choose their electricity supplier in a competitive electricity market and several other states are considering such legislation. At the present time, Indiana has not adopted such legislation. Ohio regulation allows gas customers to choose their commodity supplier. The Company implemented a choice program for its gas customers in Ohio in January 2003. Indiana has not adopted any regulation requiring gas choice; however, the Company operates under approved tariffs permitting large volume customers to choose their commodity supplier. Other Operating Matters Midwest Independent System Operator The FERC approved the Midwest Independent System Operator (MISO) as the nation's first regional transmission organization. Regional transmission organizations place public utility transmission facilities in a region under common control. The FERC has made regional transmission organizations a top priority to boost competition and to provide more reliable power at lower rates. The Carmel, Indiana, based MISO began some operations in December 2001 with control of 73,000 miles of transmission lines carrying up to 81,000 MW. More than 20 states are included in the MISO from the Midwest and Plains states, to Texas, Arkansas, and part of the Southeast. In December 2001, the IURC approved the Company's request for authority to transfer operational control over its electric transmission facilities to the MISO. That transfer occurred on February 1, 2002. Issues pertaining to certain of MISO's tariff charges for its services remain to be determined by the FERC. Given the outstanding tariff issues, as well as the potential for additional growth in MISO participation, the Company is unable to determine the future impact MISO participation may have on its operations. Pursuant to an order from the IURC, certain MISO costs are deferred for future recovery. As a result of MISO's operational control over much of the Midwestern electric transmission grid, including SIGECO's transmission facilities, SIGECO's continued ability to import power, when necessary, may be impacted. Given the nature of MISO's policies regarding use of transmission facilities, as well as ongoing FERC initiatives, it is difficult to predict the impact on operational reliability. The potential need to expend capital for improvements to the transmission system, both to SIGECO's facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant. Environmental Matters The Company is subject to federal, state, and local regulations with respect to environmental matters, principally air, solid waste, and water quality. Pursuant to environmental regulations, the Company is required to obtain operating permits for the electric generating plants that it owns or operates and construction permits for any new plants it might propose to build. Regulations concerning air quality establish standards with respect to both ambient air quality and emissions from electric generating facilities, including particulate matter, sulfur dioxide (SO2), and nitrogen oxides (NOx). Regulations concerning water quality establish standards relating to intake and discharge of water from electric generating facilities, including water used for cooling purposes in electric generating facilities. Because of the scope and complexity of these regulations, the Company is unable to predict the ultimate effect of such regulations on its future operations, nor is it possible to predict what other regulations may be adopted in the future. The Company intends to comply with all applicable governmental regulations, but will contest any regulation it deems to be unreasonable or impossible to comply with. Clean Air Act NOx SIP Call Matter The Clean Air Act (the Act) requires each state to adopt a State Implementation Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS) for a number of pollutants, including ozone. If the USEPA finds a state's SIP inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its SIP (a SIP Call). In October 1998, the USEPA issued a final rule "Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed. Reg. 57355). This ruling found that the SIP's of certain states, including Indiana, were substantially inadequate since they allowed for NOx emissions in amounts that contributed to non-attainment with the ozone NAAQS in downwind states. The USEPA required each state to revise its SIP to provide for further NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx emissions from Indiana. In June 2001, the Indiana Air Pollution Control Board adopted final rules to achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by May 31, 2004 (the compliance date). This is a 65% reduction from emission levels existing in 1999 and 1998. The Company has initiated steps toward compliance with the revised regulations. These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to be the most effective method of reducing NOx emissions where high removal efficiencies are required. On August 28, 2001, the IURC issued an order that (1) approved the Company's proposed project to achieve environmental compliance by investing in clean coal technology, (2) approved the Company's initial cost estimate of $198 million for the construction, subject to periodic review of the actual costs incurred, and (3) approved a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months a return on its capital costs for the project, at its overall cost of capital, including a return on equity. The first rider adjustment for ongoing cost recovery was approved by the IURC on February 6, 2002. Based on the level of system-wide emissions reductions required and the control technology utilized to achieve the reductions, the current estimated clean coal technology construction cost ranges from $240 million to $250 million and is expected to be expended during the 2001-2006 period. Through December 31, 2002, $70.0 million has been expended. On June 5, 2002, the Company filed a new proceeding to update the NOx project cost and to obtain approval of a second rider authorizing ongoing recovery of depreciation and operating costs related to the clean coal technology. After the equipment is installed and operational, related annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million. Such expenses would commence in 2004 when the technology becomes operational. On January 3, 2003, the IURC approved a settlement that authorizes total capital cost investment for this project up to $244 million (excluding AFUDC) and recovery on those capital costs, as well as the recovery of future operating costs, including depreciation and purchased emission allowances, through a rider mechanism. The settlement establishes a fixed return of 8 percent on the capital investment, which approximates the return authorized in the Company's last electric rate case in 1995. The Company expects to achieve timely compliance as a result of the project. Construction of the first SCR at Culley is nearing completion on schedule, and installation of SCR technology as planned is expected to reduce the Company's overall NOx emissions to levels compliant with Indiana's NOx emissions budget allotted by the USEPA. Therefore, the Company has recorded no accrual for potential penalties that may result from noncompliance. Culley Generating Station Litigation In the late 1990's, the USEPA initiated an investigation under Section 114 of the Act of SIGECO's coal-fired electric generating units in commercial operation by 1977 to determine compliance with environmental permitting requirements related to repairs, maintenance, modifications, and operations changes. The focus of the investigation was to determine whether new source review permitting requirements were triggered by such plant modifications, and whether the best available control technology was, or should have been used. Numerous electric utilities were, and are currently, being investigated by the USEPA under an industry-wide review for compliance. In July 1999, SIGECO received a letter from the Office of Enforcement and Compliance Assurance of the USEPA discussing the industry-wide investigation, vaguely referring to an investigation of SIGECO and inviting SIGECO to participate in a discussion of the issues. No specifics were noted; furthermore, the letter stated that the communication was not intended to serve as a notice of violation. Subsequent meetings were conducted in September and October 1999 with the USEPA and targeted utilities, including SIGECO, regarding potential remedies to the USEPA's general allegations. On November 3, 1999, the USEPA filed a lawsuit against seven utilities, including SIGECO. SIGECO's suit is pending in the U.S. District Court for the Southern District of Indiana. The USEPA alleges that, beginning in 1992, SIGECO violated the Act by (1) making modifications to its Culley Generating Station in Yankeetown, Indiana without obtaining required permits (2) making major modifications to the Culley Generating Station without installing the best available emission control technology and (3) failing to notify the USEPA of the modifications. In addition, the lawsuit alleges that the modifications to the Culley Generating Station required SIGECO to begin complying with federal new source performance standards at its Culley Unit 3. SIGECO believes it performed only maintenance, repair, and replacement activities at the Culley Generating Station, as allowed under the Act. Because proper maintenance does not require permits, application of the best available control technology, notice to the USEPA, or compliance with new source performance standards, SIGECO believes that the lawsuit is without merit, and intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA has voluntarily dismissed a majority of the claims brought in its original complaint. In its original complaint, USEPA alleged significant emissions increases of three pollutants for each of four maintenance projects. Currently, USEPA is alleging only significant emission increases of a single pollutant at three of the four maintenance projects cited in the original complaint. The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per violation. However, on July 29, 2002, the Court ruled that USEPA could not seek civil penalties for two of the three remaining projects at issue in the litigation, significantly reducing potential civil penalty exposure. The lawsuit also seeks a court order requiring SIGECO to install the best available emissions technology at the Culley Generating Station. If the USEPA were successful in obtaining an order, SIGECO estimates that in response it could incur capital costs of approximately $20 million to $40 million to comply with the order. Trial is currently set to begin July 14, 2003. The USEPA has also issued an administrative notice of violation to SIGECO making the same allegations, but alleging that violations began in 1977. While it is possible that SIGECO could be subjected to criminal penalties if the Culley Generating Station continues to operate without complying with the permitting requirements of new source review and the allegations are determined by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA and the electric utility industry have a bonafide dispute over the proper interpretation of the Act. Accordingly, the Company has recorded no accrual, and the plant continues to operate while the matter is being decided. Information Request On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested, and no further action has occurred. Manufactured Gas Plants In the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites. Indiana Gas has identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program and is currently conducting some level of remedial activities including groundwater monitoring at certain sites where deemed appropriate and will continue remedial activities at the sites as appropriate and necessary. In conjunction with data compiled by environmental consultants, Indiana Gas has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million. The estimated accrued costs are limited to Indiana Gas' proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas' share of response costs at these 19 sites to between 20% and 50%. With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million. Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen. In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled in the IDEM's Voluntary Remediation Program. In response, SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990's. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have recently been initiated by the Company to confirm that the sites continue to pose no such risk. Rate and Regulatory Matters Gas and electric operations with regard to retail rates and charges, terms of service, accounting matters, issuance of securities, and certain other operational matters specific to its Indiana customers are regulated by IURC. The retail gas operations of the Ohio operations are subject to regulation by the PUCO. Changes in prices for fuel for electric generation and purchased power are determined primarily by energy markets. Gas Costs Proceedings Adjustments to rates and charges related to the cost of gas charged to Indiana customers are made through gas cost adjustment (GCA) procedures established by Indiana law and administered by the IURC. Similar adjustments to the cost of gas charged to Ohio customers are made through gas cost recovery (GCR) procedures established by Ohio law and administered by the PUCO. GCA and GCR procedures involve scheduled quarterly filings and IURC and PUCO hearings to establish the amount of price adjustments for a designated future quarter. The procedures also provide for inclusion in later quarters any variances between the estimated cost of gas and actual costs incurred. This reconciliation process with regard to changes in the cost of gas sold closely matches revenues to expenses. The IURC has also applied the statute authorizing GCA procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. Recovery of gas costs is not allowed to the extent that net operating income for the longer of (1) a 60-month period, including the twelve-month period provided in a gas cost adjustment filing, or (2) the date of the last order establishing base rates and charges exceeds the total net operating income authorized by the IURC. For the recent past, the earnings test has not affected the Company's ability to recover gas costs, and the Company does not anticipate the earnings test will restrict the recovery of gas costs in the near future. Rate structures for gas delivery operations do not include weather normalization-type clauses that authorize the utility to recover gross margin on sales established in its last general rate case, regardless of actual weather patterns. Commodity prices for natural gas purchases were significantly higher during the 2000 - 2001 heating season, primarily due to colder temperatures, increased demand and tighter supplies. Subject to compliance with applicable state laws, the Company's utility subsidiaries are allowed full recovery of such changes in purchased gas costs from their retail customers through these commission-approved gas cost adjustment mechanisms, and margin on gas sales should not be impacted. However, in 2001, the Company's utility subsidiaries experienced higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas and some level of price sensitive reduction in volumes sold. In March 2001, Indiana Gas and SIGECO reached agreement with the OUCC and the Citizens Action Coalition of Indiana, Inc. (CAC) regarding the matters raised by an IURC Order that disallowed $3.8 million of Indiana Gas' gas procurement costs for the 2000 - 2001 heating season which was recognized during the year ended December 31, 2000. As part of the agreement, the companies agreed to contribute an additional $1.7 million to assist qualified low income gas customers, and Indiana Gas agreed to credit $3.3 million of the $3.8 million disallowed amount to its customers' April 2001 utility bills in exchange for both the OUCC and the CAC dropping their appeals of the IURC Order. In April 2001, the IURC issued an order approving the settlement. Substantially all of the financial assistance for low income gas customers was distributed in 2001. For additional information on regulatory matters affecting the utilities, refer to Nonregulated Section's discussion of transactions with ProLiance. Fuel & Purchased Power Costs Adjustments to rates and charges related to the cost of fuel and the net energy cost of purchased power charged to Indiana customers are made through fuel cost adjustment procedures established by Indiana law and administered by the IURC. Fuel cost adjustment procedures involve scheduled quarterly filings and IURC hearings to establish the amount of price adjustments for future quarters. The procedures also provide for inclusion in a later quarter of any variances between the estimated cost of fuel and purchased power and actual costs incurred. The order provides that any over-or-under-recovery caused by variances between estimated and actual cost in a given quarter will be included in the second succeeding quarter's adjustment factor. This continuous reconciliation of estimated incremental fuel costs billed with actual incremental fuel costs incurred closely matches revenues to expenses. An earnings test similar to the test restricting gas cost recovery is the principal restriction to recovery of fuel cost increases. This earnings test has not affected the Company's ability to recover fuel costs, and the Company does not anticipate the earnings test will restrict the recovery of fuel costs in the near future. As a result of an appeal of a generic order issued by the IURC in August 1999 regarding guidelines for the recovery of purchased power costs, SIGECO entered into a settlement agreement with the OUCC that provides certain terms with respect to the recoverability of such costs. The settlement, originally approved by the IURC in August 2000, has been extended by agreement through March 2003, and discussions regarding further extension of the settlement term are ongoing. Under the settlement, SIGECO can recover the entire cost of purchased power up to an established benchmark, and during forced outages, SIGECO will bear a limited share of its purchased power costs regardless of the market costs at that time. Based on this agreement, SIGECO believes it has limited its exposure to unrecoverable purchased power costs. Results of Operations of the Nonregulated Businesses The Company is involved in nonregulated activities in four primary business areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure Services, and Broadband. Energy Marketing and Services markets natural gas and provides energy management, including energy performance contracting services. Coal Mining mines and sells coal to the Company's utility operations and to other parties and generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. Broadband invests in broadband communication services such as analog and digital cable television, high-speed Internet and data services, and advanced local and long distance phone services. In addition, the nonregulated group has investments in other businesses that invest in energy-related opportunities and provides utility services, municipal broadband consulting, retail, and real estate and leveraged leases. The results of nonregulated operations for the years ended December 31, 2002, 2001, and 2000 follows: In millions, except per share amounts 2002 2001 2000 - ------------------------------------------------------------------------- (As Restated) ---------------- Energy services & other revenues $ 287.2 $ 681.0 $ 478.0 Cost of energy services & other revenues 249.4 640.9 453.2 - ------------------------------------------------------------------------- TOTAL OPERATING MARGIN 37.8 40.1 24.8 Intersegment revenues, net of costs 3.0 2.6 1.9 Expenses: Operating expenses 36.1 36.3 20.3 Merger & integration costs - - 1.6 Restructuring costs - 3.5 - - ------------------------------------------------------------------------- Total expenses 36.1 39.8 21.9 - ------------------------------------------------------------------------- OPERATING INCOME 4.7 2.9 4.8 Other income: Equity in earnings of unconsolidated affiliates 10.9 13.9 9.8 Other - net 6.1 11.4 18.5 - ------------------------------------------------------------------------- Total other income 17.0 25.3 28.3 - ------------------------------------------------------------------------- Interest expense 9.1 12.5 9.6 - ------------------------------------------------------------------------- INCOME BEFORE TAXES 12.6 15.7 23.5 Income tax (6.9) (4.7) 0.6 Minority interest 0.5 0.6 1.1 - ------------------------------------------------------------------------- Income before extraordinary loss 19.0 19.8 21.8 Extraordinary loss - net of tax - (7.7) - - ------------------------------------------------------------------------- NET INCOME $ 19.0 $ 12.1 $ 21.8 ========================================================================= BASIC EARNINGS PER SHARE $ 0.28 $ 0.18 $ 0.36 ========================================================================= NET INCOME ATTRIBUTED TO: Energy Marketing & Services $ 15.0 $ 11.3 $ 7.2 Coal Mining 12.2 13.6 4.6 Utility Infrastructure (1.2) (0.6) 0.2 Broadband 0.4 (0.1) 4.4 Other Businesses (7.4) (12.1) 5.4 For the year ended December 31, 2002, earnings from nonregulated operations increased $6.9 million, or $0.10 per share, when compared to 2001. The increase is primarily due to increased earnings from Energy Marketing and Services and a smaller loss incurred by the Company's broadband consulting operations which are part of the Other Businesses Group. The year ended December 31, 2001 included $2.2 million after tax, or $0.04 per share, in nonrecurring restructuring costs and $7.7 million after tax, or $0.12 per share, related to an extraordinary loss from the divestiture of certain assets. In addition, 2001 benefited from gains recognized upon sale of investments by an unconsolidated affiliate in the first and third quarters, and 2002 was negatively affected by a change in Indiana corporate income tax laws enacted in June 2002, which required the recalculation of deferred tax obligations and earnings from leveraged lease investments at the date of enactment of the law. For 2001 compared to 2000, net income decreased $9.7 million due primarily to nonrecurring items incurred in 2001 and 2000. Nonrecurring items in 2000 added earnings of $3.9 million, or $0.06 per share, and included a gain from restructuring the Company's investment in SIGECOM, offset by merger and integration costs. Before nonrecurring items, 2001 earnings increased $4.1 million primarily due to expanded natural gas marketing and coal mining operations, partially offset by losses incurred by the Company's broadband consulting operations. Energy Marketing & Services Energy Marketing and Services includes the Company's investment in ProLiance, a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas). ProLiance provides natural gas and related services to Indiana Gas, the Ohio operations, Citizens Gas, and others and also began providing service to SIGECO and Vectren Retail, LLC (the Company's retail gas marketer) in 2002. ProLiance's primary business is optimizing the gas portfolios of utilities and providing services to large end use customers. In addition, Energy Marketing and Services includes the operations of Energy Systems Group, LLC (ESG), which provides energy performance contracting and facility upgrades through its design and installation of energy-efficient equipment. ESG is a consolidated venture between the Company and Citizens Gas, with the Company owning two-thirds. ESG had no significant impact on the Company's financial results in 2002, 2001, or 2000. In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP Energy Services, LLC (SES) with ProLiance was completed. SES provided natural gas and related services to SIGECO and others prior to the integration. In exchange for the contribution of SES' net assets totaling $19.2 million, including cash of $2.0 million, Vectren's allocable share of ProLiance's profits and losses increased from 52.5% to 61%, consistent with Vectren's new ownership percentage. In March 2001 Vectren's allocable share of profits and losses increased from 50% to 52.5% when ProLiance began managing the Ohio operations' gas portfolio. Governance and voting rights remain at 50% for each member. Since governance of ProLiance remains equal between the members, Vectren continues to account for its investment in ProLiance using the equity method of accounting. Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to June 1, 2002, SES' operating results, now part of ProLiance, are reflected in equity in earnings of unconsolidated affiliates. SES' revenues and expenses were the primary component of nonregulated revenues and cost of revenues. Therefore, the integration significantly decreased revenues and costs of revenues over $400 million in 2002 compared to 2001. The Company's operating expenses also decreased $4.8 million in 2002 as a result of the integration. The transfer of net assets was accounted for at book value consistent with joint venture accounting and did not result in any gain or loss. Pre-tax income of $19.1 million, $12.8 million and $5.4 million was recognized as ProLiance's contribution to earnings for the years ended December 31, 2002, 2001, and 2000, respectively. Pre-tax earnings have increased primarily as a result of increased operations at ProLiance and the Company's increased ownership. Earnings recognized from ProLiance are included in equity in earnings of unconsolidated affiliates. In 2001 compared to 2000, the significant increase in the Company's nonregulated revenues and costs of revenues was primarily attributable to SES' operations reflecting higher prices for natural gas and increased volumes. SES' increased activity was also a contributing factor to the increase in 2001 margin and operating expenses when compared to 2000. Regulatory Matters The sale of gas and provision of other services to Indiana Gas and SIGECO by ProLiance is subject to regulatory review through the quarterly gas cost adjustment (GCA) process administered by the IURC. The sale of gas and provision of other services to the Ohio operations by ProLiance is subject to regulatory review through the quarterly gas cost recovery (GCR) and audit process administered by the PUCO. Specific to the sale of gas and provision of other services to Indiana Gas by ProLiance, on September 12, 1997, the IURC issued a decision finding the gas supply and portfolio administration agreements between ProLiance and Indiana Gas and ProLiance and Citizens Gas to be consistent with the public interest and that ProLiance is not subject to regulation by the IURC as a public utility. However, with respect to the pricing of gas commodity purchased from ProLiance, the price paid by ProLiance to the utilities for the prospect of using pipeline entitlements if and when they are not required to serve the utilities' firm customers, and the pricing of fees paid by the utilities to ProLiance for portfolio administration services, the IURC concluded that additional review in the GCA process would be appropriate and directed that these matters be considered further in a consolidated GCA proceeding involving Indiana Gas and Citizens Gas. On June 4, 2002, Indiana Gas and Citizens Gas, together with the OUCC and other consumer parties, entered into and filed with the IURC a settlement setting forth the terms for resolution of all pending regulatory issues related to ProLiance, including the three pricing issues. On July 23, 2002, the IURC approved the settlement filed by the parties. The GCA proceeding has been concluded and new supply agreements between Indiana Gas, SIGECO, Citizens Gas, and ProLiance have been approved and extended through March 31, 2007. ProLiance will also have the opportunity, if it so elects, to participate in a "request for proposal" process for service to the utilities after March 31, 2007. For past services provided to Indiana Gas by ProLiance, the Company made refunds to Indiana Gas' retail customers pursuant to the settlement totaling $6.4 million and reimbursed other costs to parties involved in the settlement totaling $1.1 million. Payments were made in the fourth quarter of 2002. At December 31, 2001, the Company had established a reserve specific to this GCA proceeding totaling $5.2 million which was recorded throughout the GCA proceeding as a reduction of ProLiance's contribution to the Company's earnings. The amount of the settlement in excess of that accrued prior to 2002 totaling $2.3 million was reflected as a reduction of ProLiance's contribution to earnings in 2002. In addition to the above, the IURC order also provides that: o A portion of the utilities' natural gas will be purchased through a gas cost incentive mechanism that shares price risk and reward between the utilities and customers; o Beginning in 2004, ProLiance will provide the utilities with an interstate pipeline transport and storage service price discount, thus providing additional savings to customers; o As ProLiance continues to provide the utilities with its supply services, Citizens Gas and Vectren will together annually provide an additional $2 million per year in customer benefits in 2003, 2004, and 2005. Coal Mining Coal Mining provides the mining and sale of coal to the Company's utility operations and to other third parties through its wholly owned subsidiary Vectren Fuels, Inc (Fuels). The group also generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels through its investment in Pace Carbon Synfuels, LP (Pace Carbon). Pace Carbon is an unconsolidated affiliate accounted for using the equity method. Earnings from Fuels were $6.2 million in 2002, $9.3 million in 2001, and $2.5 million in 2000. In 2002 compared to 2001, net income and operating income decreased $3.3 million and $4.9 million, respectively, as a result of lower market prices on third party coal sales and a somewhat lower yield per ton mined in 2002. In 2001 compared to 2000, net income and operating income increased $7.0 million and $11.1 million, respectively, as a result of the Company's second mine starting operations in mid-2001. The new mine was also a contributing factor to increased operating expenses in 2002 and 2001. Fuels' operating expenses increased $0.8 million in 2002 and $6.9 million in 2001. The investment in Pace Carbon resulted in losses reflected in equity in earnings of unconsolidated affiliates totaling $6.8 million, $4.5 million, and $2.4 million in 2002, 2001, and 2000, respectively. Losses have increased as a result of increased production of synthetic fuels and higher production costs. The production of synthetic fuel generates IRS Code Section 29 investment tax credits that are reflected in income taxes. These credits have also increased in recent years consistent with increased synthetic fuel production. Net income, including the losses, tax benefits, and tax credits, generated from the investment in Pace Carbon totaled $6.0 million in 2002, $4.3 million in 2001, and $2.1 million in 2000. Utility Infrastructure Services Utility Infrastructure Services provides underground construction and repair of utility infrastructure services to the Company and to other gas, water, electric, and telecommunications companies as well as facilities locating and meter reading services through its investment in Reliant Services, LLC (Reliant). Reliant is a 50% owned strategic alliance with an affiliate of Cinergy Corp. and is accounted for using the equity method of accounting. The investment in Reliant had no significant impact on the Company's results in 2002, 2001, or 2000. Broadband Broadband invests in broadband communication services such as cable television, high-speed Internet, and advanced local and long distance phone services. The Company has a minority interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom). Utilicom is a provider of bundled communication services focusing on last mile delivery to residential and commercial customers. The Company also has a minority interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to the greater Evansville, Indiana, area. The equity investments in Utilicom and Holdings are accounted for using the cost method of accounting. As a result, Broadband had no significant impact on the Company's financial results with the exception of the one-time gain recorded in 2000 upon the restructuring of the Company's investment in SIGECOM previously discussed. The $4.9 million gain is included in equity in earnings of unconsolidated affiliates. Utilicom also plans to provide broadband services to the greater Indianapolis, Indiana, and Dayton, Ohio, markets. However, the funding of these projects has been delayed due to the continued difficult environment within the telecommunication capital markets, which has prevented Utilicom from obtaining debt financing on terms it considers acceptable. While the existing investors remain interested in the Indianapolis and Dayton projects, the Company is not required to make further investments and does not intend to proceed unless commitments are obtained to fully fund these projects. Franchising agreements have been extended in both locations. Other Businesses The Other Businesses Group includes a variety of wholly owned operations and investments. The significant activities that affected the nonregulated results of operations during 2002, 2001, and 2000 are the wholly owned operations of Vectren Communication Services, Inc. (VCS), Vectren Retail LLC (Vectren Retail), and Southern Indiana Properties, Inc.(SIPI) and the Company's investment in the Haddington partnerships (Haddington), which are accounted for using the equity method of accounting. VCS is a wholly owned broadband consulting company that incurred charges in 2002 and 2001 related to the settlement of construction contracts and the reorganization of its operations, allowing it to focus on consulting services. As a result, VCS incurred net losses of $2.8 million in 2002 and $8.0 million in 2001 compared to net income of $0.2 million in 2000. The majority of the costs incurred in 2001 and 2002 are included in cost of energy services and other revenues and are therefore a component of the change in margin in 2002 compared to 2001 and 2001 compared to 2000. Vectren Retail provides natural gas and other related products and services primarily in Ohio serving customers opting for choice among energy providers. Vectren Retail began operations in 2001 and has incurred startup costs which increased operating expenses $1.5 million in 2002 and $0.9 million in 2001. Due to increased activity, these operations added margin of $1.3 million in 2002 compared to 2001. SIPI has various investments in leveraged leases, notes receivable, and unconsolidated affiliates. The Company divested of notes receivable and leveraged lease investments in the second and fourth quarters of 2001. These divestitures resulted in the $7.7 million extraordinary loss previously discussed and less leveraged lease and interest income in 2002 compared to 2001 and in 2001 compared to 2000. The decrease in leveraged lease and interest income is the primary contributing factor to the change in other-net in 2002 and 2001. The dispositions of these assets generated cash flow of approximately $67 million. The Haddington partnerships are equity method investments that invest in energy-related opportunities. During 2001, these partnerships sold investments resulting in gains reflected by the Company totaling $6.2 million. Such gains are included in equity in earnings of unconsolidated affiliates. The most significant portion of these earnings was derived from Haddington's sale of Bear Paw Investments, LLC (Bear Paw). In March 2001, Haddington sold its investment in Bear Paw in exchange for a combination of cash and securities. The cost of Haddington's Bear Paw investment approximated $5.1 million, and the net proceeds received totaled $18.1 million, resulting in a gain of $13.0 million. The Company recognized its portion of the pre-tax gain totaling $3.9 million in March 2001. Later in 2001 as the securities received were sold, the Company recognized its portion of the additional earnings totaling $1.0 million. Critical Accounting Policies Management is required to make judgements, assumptions, and estimates that affect the amounts reported in the consolidated financial statements and the related disclosures that conform to accounting principles generally accepted in the United States. Note 2 to the consolidated financial statements describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Certain estimates used in the financial statements are subjective and use variables that require judgement. These include the estimates to perform goodwill and other asset impairments tests and to determine pension and postretirement benefit obligations. The Company makes other estimates in the course of accounting for unbilled revenue and the effects of regulation that are critical to the Company's financial results but that are less likely to be impacted by near term changes. Other estimates that significantly affect the Company's results, but are not necessarily critical to operations, include depreciation of utility and non-utility plant, the valuation of derivative contracts, and the allowance for doubtful accounts, among others. Actual results could differ from these estimates. Impairment Review of Investments The Company has investments in notes receivable, entities accounted for using the cost method of accounting, and entities accounted for using the equity method of accounting. On a periodic basis and when events occur that may cause one of these investments to be impaired, the Company performs an impairment analysis. An impairment analysis of notes receivable usually involves the comparison of the investment's estimated free cash flows to the stated terms of the note, or for notes that are collateral dependent, a comparison of the collateral's fair value to the carrying amount of the note. An impairment analysis of cost method and equity method investments involves comparison of the investment's estimated fair value to its carrying amount. Fair value is estimated using market comparisons, appraisals, and/or discounted cash flow analyses. Calculating free cash flows and fair value using the above methods is subjective and requires significant judgement in growth assumptions, longevity of cash flows, and discount rates (for fair value calculations). During 2002, the Company performed an impairment analysis on its Utilicom-related investments. The Company used market comparisons to estimate fair value for the cost method portion of the Utilicom investment and a free cash flow analysis to estimate fair value for the note receivable portion of the Utilicom investment. No impairment charge was recorded as a result of these tests. However, a 10% decrease in the fair value that was estimated using market comparables would have resulted in a $0.3 million impairment charge to the cost method investment. A 10% decrease in the cash flow growth assumption utilized to calculate Utilicom's free cash flows would have resulted in no impairment charge to the notes receivable. Impairment tests on other investments were also conducted using appraisals and discounted cash flow models to estimate fair value. No impairment charges resulted from these analyses. For the other impairment tests performed during 2002, a 10% adverse change in the calculated or appraised fair value of collateral or a 100 basis point adverse change in the discount rate used to estimate fair value would have resulted in a $2.6 million impairment charge. Goodwill Pursuant to SFAS No. 142, the Company performed an initial impairment analysis of its goodwill, all of which resides in the Gas Utility Services operating segment. Also consistent with SFAS 142, goodwill is tested for impairment annually at the beginning of the year and more frequently if events or circumstances indicate that an impairment loss has been incurred. Impairment tests are performed at the reporting unit level which the Company has determined to be consistent with its Gas Utility Services operating segment as identified in Note 18 to the consolidated financial statements. An impairment test performed in accordance with SFAS 142 requires that a reporting unit's fair value be estimated. The Company used a discounted cash flow model to estimate the fair value of its Gas Utility Services operating segment, and that estimated fair value was compared to its carrying amount, including goodwill. The estimated fair value was in excess of the carrying amount and therefore resulted in no impairment. Estimating fair value using a discounted cash flow model is subjective and requires significant judgement in applying a discount rate, growth assumptions, company expense allocations, and longevity of cash flows. A 100 basis point increase in the discount rate utilized to calculate the Gas Utility Services segment's fair value also results in no impairment charge. Pension and Other Postretirement Obligations The Company estimates the expected return on plan assets, discount rate, rate of compensation increase, and future health care costs, among other things, and relies on actuarial estimates to assess the future potential liability and funding requirements of the Company's pension and postretirement plans. The Company annually measures its obligations on September 30. The Company used the following weighted average assumptions to develop 2002 annual costs and the ending benefit obligations recognized in the consolidated financial statements: a discount rate of 6.75%, an expected return on plan assets before expenses of 9.00%, a rate of compensation increase of 4.25%, and a health care cost trend rate of 10% in 2002 declining to 5% in 2006. During 2002, the Company reduced the discount rate and rate of compensation increase by 50 basis points from those assumptions used in 2001 due to the general decline in interest rates and other market conditions that occurred in 2002. Future changes in health care costs, work force demographics, interest rates, or plan changes could significantly affect the estimated cost of these future benefits. For the year ended December 31, 2002, a 1% adverse change in the assumed health care cost trend rate for the postretirement health care plans would have decreased pre-tax income by approximately $0.4 million and would have increased the postretirement liability by approximately $5.6 million. Unbilled Revenues To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period. The Company uses actual units billed during the month to allocate unbilled units. Those allocated units are multiplied by rates in effect during the month to calculate unbilled revenue at balance sheet dates. While certain estimates are used in the calculation of unbilled revenue, these estimates are not subject to near term changes. Regulation At each reporting date, the Company reviews current regulatory trends in the markets in which it operates. This review involves judgement and is critical in assessing the recoverability of regulatory assets as well as the ability to continue to account for its activities based on the criteria set forth in SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). Based on the Company's current review, it believes its regulatory assets are probable of recovery. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets. In the unlikely event of a change in the current regulatory environment, such write-offs and impairment charges could be significant. Impact of Recently Issued Accounting Guidance on Future Operations EITF 02-03 In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-03) that gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 should be shown net in the income statement, whether or not settled physically, if the derivative instruments are held for "trading purposes." The consensus rescinded EITF Issue 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10) as well as other decisions reached on energy trading contracts at the EITF's June 2002 meeting. The Company's non-firm wholesale power marketing operations enter into contracts that are derivatives as defined by SFAS 133, but these operations do not meet the definition of energy trading activities based upon the provisions in EITF 98-10. Currently, the Company uses a gross presentation to report the results of these operations as described in Note 16 of the consolidated financial statements. The Company has re-evaluated its portfolio of derivative contracts and has determined gross presentation remains appropriate. SFAS 143 In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Any costs of removal recorded in accumulated depreciation pursuant to regulatory authority will require disclosure in future periods. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company's results of operations or financial condition. FASB Interpretation (FIN) 45 In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a guarantor's accounting for and disclosure of certain guarantees issued and outstanding and that a guarantor is required to recognize, at the inception of a guarantee, a liability for the obligations it has undertaken. The objective of the initial measurement of that liability is the fair value of the guarantee at its inception. The initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The incremental disclosure requirements are included in the consolidated financial statements included in Item 8, Note 13. Although management is still evaluating the impact of FIN 45 on its financial position and results of operations, the adoption is not expected to have a material effect. FIN 46 In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 addresses consolidation by business enterprises of variable interest entities and significantly changes the consolidation requirements for those entities. FIN 46 is intended to achieve more consistent application of consolidation policies to variable interest entities and, thus improves comparability between enterprises engaged in similar activities when those activities are conducted through variable interest entities. FIN 46 applies to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date. FIN 46 applies to the Company's third quarter for variable interest entities in which the Company holds a variable interest acquired before February 1, 2003. Although management is still evaluating the impact of FIN 46 on its financial position and results of operations, the adoption is not expected to have a material effect. Financial Condition Within Vectren's consolidated group, VUHI funds short-term and long-term financing needs of the regulated operations, and Vectren Capital Corp (Cap Corp) funds short-term and long-term financing needs of the nonregulated and corporate operations. Vectren Corporation guarantees Cap Corp's debt, but does not guarantee VUHI's debt. VUHI's currently outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. Prior to VUHI's formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have debt outstanding funded solely by their operations. Regulated operations have historically funded the Company's common stock dividends. Nonregulated operations have demonstrated sustained profitability, and the ability to generate cash flows. These cash flows are ordinarily reinvested in other nonregulated ventures. In the future, nonregulated cash flows could be used to fund a small portion of the Company's dividend requirement. In November 2002, Moody's Investors Service (Moody's) downgraded the senior unsecured debt of VUHI, Indiana Gas, and SIGECO (from A2 to Baa1) as well as SIGECO's senior secured debt (from A1 to A3) and SIGECO's pollution control revenue bonds (from VMIG 1 to VMIG 2). In addition, VUHI's commercial paper program was also downgraded (from P-1 to P-2). The reasons cited for the downgrades included weaker credit and fixed charge coverage measures compared to A2 peers, resulting from the prior integration and restructuring costs and warm winter of 2001 and 2002; and lack of weather normalization-type clauses that authorize the utilities to recover gross margin on sales regardless of actual weather patterns. VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at December 31, 2002 are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor's) and Moody's, respectively. SIGECO's credit ratings on outstanding senior unsecured debt at December 31, 2002 are BBB+/Baa1. SIGECO's credit ratings on outstanding secured debt at December 31, 2002 are A-/A3. VUHI's commercial paper has a credit rating of A-2/P-2. Cap Corp's senior unsecured debt is rated BBB+/Baa2. Moody's current outlook is stable while Standard and Poor's current outlook is negative. The ratings of Standard and Poor's and Moody's are categorized as investment grade. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor's and Moody's lowest level investment grade rating is BBB- and Baa3, respectively. The Company's consolidated equity capitalization objective is 40-50% of total capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, and seasonal factors that affect the Company's operation. The Company's equity component was 46% and 45% of total capitalization, including current maturities of long-term debt and long-term debt subject to tender, at December 31, 2002 and 2001, respectively. The Company expects the majority of its capital expenditures, investments, and debt security redemptions to be provided by internally generated funds. However, additional permanent financing may be required due to significant capital expenditures for NOx compliance equipment at SIGECO and plans to further strengthen the Company's capital structure and the capital structures of VUHI and its utility subsidiaries. These plans may include the issuance of new equity and debt and the calling of certain long-term debt at SIGECO and Indiana Gas. Specific to the NOx compliance project, the Company is authorized an 8 percent return on its capital investments through approved rider mechanisms. Sources & Uses of Liquidity Operating Cash Flow The Company's primary historical source of liquidity to fund working capital requirements has been cash generated from operations. Cash flow from operating activities increased during the year ended December 31, 2002 compared to 2001 by $104.2 million and increased $141.5 million in 2001 compared to 2000. The primary reasons for the increases are favorable changes in working capital accounts due to a return to lower gas prices and increased earnings before non-cash charges. Financing Cash Flow Although working capital requirements are generally funded by cash flow from operations, the Company uses short-term borrowings to supplement working capital needs when accounts receivable balances are at their highest and gas storage is refilled. Additionally short-term borrowings are required for capital projects and investments until they are permanently financed. Cash flow required for financing activities of $57.6 million for the year ended December 31, 2002 includes an increase in borrowings outstanding over 2001 of $13.8 million and increased common stock dividends compared to 2001. Borrowings have increased due to financing a portion of capital expenditures for NOx compliance temporarily with short-term borrowings. Cash flow required for financing activities of $2.7 million for the year ended December 31, 2001 includes $59.5 million of reductions in borrowings and preferred stock and $69.5 million in common stock dividends, offset by the issuance of $129.4 million of common stock. During 2001, $473.4 million of net proceeds from equity and debt issuances were utilized to pay down short-term borrowings. Financing the Ohio Operations Purchase On October 31, 2000, the acquisition of the Ohio operations was completed for a purchase price of approximately $471 million. Commercial paper and $150.0 million in floating rate notes were issued to fund the purchase. During 2001, the Company refinanced these interim borrowing arrangements with permanent financing in the form of new equity and long-term debt, as described below. In January 2001, the Company filed a registration statement with the Securities and Exchange Commission with respect to a public offering of 5.5 million shares of new common stock. In February 2001, the registration became effective, and an agreement was reached to sell approximately 6.3 million shares (the original 5.5 million shares, plus an over-allotment option of 0.8 million shares) to a group of underwriters. The net proceeds from the sale of common stock totaled $129.4 million. In September 2001, VUHI filed a shelf registration statement with the Securities and Exchange Commission for $350.0 million aggregate principal amount of unsecured senior notes. In October 2001, VUHI issued senior unsecured notes with an aggregate principal amount of $100.0 million and an interest rate of 7.25% (the October Notes), and in December 2001, issued the remaining aggregate principal amount of $250.0 million at an interest rate of 6.625% (the December Notes). The December Notes were priced at 99.302% to yield 6.69% to maturity. These issues have no sinking fund requirements, and interest payments are due quarterly for the October Notes and semi-annually for the December Notes. The October Notes are due October 2031, but may be called by the Company, in whole or in part, at any time after October 2006 at 100% of the principal amount plus any accrued interest thereon. The December Notes are due December 2011, but may be called by the Company, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 25 basis points. Both issues are guaranteed by VUHI's three operating utility companies: SIGECO, Indiana Gas, and VEDO. These guarantees of VUHI's debt are full and unconditional and joint and several. The net proceeds from the sale of the senior notes and settlement of hedging arrangements totaled $344.0 million Other Financing Transactions In September 2001, the Company notified holders of SIGECO's 4.80%, 4.75%, and 6.50% preferred stock of its intention to redeem the shares. The 4.80% preferred stock was redeemed at $110.00 per share, plus $1.35 per share in accrued and unpaid dividends. Prior to the redemption, there were 85,519 shares outstanding. The 4.75% preferred stock was redeemed at $101.00 per share, plus $0.97 per share in accrued and unpaid dividends. Prior to the redemption, there were 3,000 shares outstanding. The 6.50% preferred stock was redeemed at $104.23 per share, plus $0.73 per share in accrued and unpaid dividends. Prior to the redemption, there were 75,000 shares outstanding. The total redemption price was $17.7 million. In December 2000, Cap Corp issued $78.0 million of private placement unsecured senior notes to three institutional investors. The issues and terms are $38.0 million at 7.67%, due December 2005; $17.5 million at 7.83%, due December 2007; and $22.5 million at 7.98%, due December 2010. These notes are guaranteed by Vectren Corporation. The issues have no sinking fund requirements. The net proceeds totaling $77.4 million were used to repay outstanding short-term borrowings. In December 2000, Indiana Gas issued $20.0 million of 15-Year Insured Quarterly (IQ) Notes at an interest rate of 7.15% and $50.0 million of 30-Year IQ Notes at an interest rate of 7.45%. Indiana Gas has the option to redeem the 15-Year IQ Notes, in whole or in part, from time to time on or after December 15, 2004 and the option to redeem the 30-Year IQ Notes in whole or in part, from time to time on or after December 15, 2005. The IQ notes have no sinking fund requirements. The net proceeds totaling $67.9 million were used to repay outstanding commercial paper. Investing Cash Flow Cash required for investing activities of $234.6 million for the year ended December 31, 2002 includes $218.7 million of requirements for capital expenditures. Investing activities for 2001 were $175.6 million. The $59.0 million increase occurring in 2002 is principally the result of the sale of leveraged lease and notes receivable investments in 2001. Cash required for investing activities for the year ended December 31, 2001 includes $239.7 million of requirements for capital expenditures offset by $53.8 million of proceeds from the sale of leveraged leases. Investing activities for the years ended December 31, 2000 were $687.5 million. The $511.9 million decrease occurring in 2001 is principally the result of the acquisition of the Ohio operations and proceeds received from the sale of assets in 2001. Available Sources of Liquidity At December 31, 2002, the Company has $510.0 million of short-term borrowing capacity, including $330.0 million for its regulated operations and $180.0 million for its wholly owned nonregulated and corporate operations, of which approximately $90.9 million is available for regulated operations and $17.0 million is available for wholly owned nonregulated and corporate operations. The availability of short-term borrowing is reduced by outstanding letters of credit totaling $5.2 million, collateralizing nonregulated activities. Subsequent to December 31, 2002, the Company increased its regulated capacity $145.0 million to $475.0 million. Effective January 1, 2003, the Company transferred certain assets that primarily support the regulated operations from other wholly owned subsidiaries to VUHI. This transfer of assets will take advantage of the greater borrowing capacity available to the regulated segment and will make the nonregulated and corporate capacity available for those operations. Prior to 2001, the Company purchased shares from the open market to satisfy issuances of common stock pursuant to its dividend reinvestment plan and stock option plans. In 2001, the Company began issuing new shares to satisfy exercised stock options and beginning in 2003 will issue new shares to satisfy dividend reinvestment plan requirements. Management estimates these new equity issues will add approximately $5 million per year in additional liquidity. Potential & Future Uses of Liquidity The following is a summary of certain obligations and commitments at December 31, 2002:
- ---------------------------------------------------------------------------------------- (In millions) 2003 2004 2005 2006 2007 Thereafter - ---------------------------------------------------------------------------------------- Short-term debt $ 399.5 $ - $ - $ - $ - $ - Long-term debt (1) 16.0 15.0 38.0 - 24.0 908.1 Long-term debt to be called (2) 23.8 - - - - - Operating leases (3) 6.8 6.3 5.0 4.5 4.0 4.7 Firm natural gas purchase commitments 89.5 21.3 3.6 - - - - ---------------------------------------------------------------------------------------- Total $ 535.6 $ 42.6 $ 46.6 $ 4.5 $ 28.0 $ 912.8 ========================================================================================
(1) Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. These provisions allow holders to put debt back to the Company at face value or the Company to call debt at face value or at a premium. Long-term debt subject to tender during the years following 2002 (in millions) is $26.6 in 2003, $13.5 in 2004, $10.0 in 2005, $53.7 in 2006, $20.0 in 2007 and $120.0 thereafter. (2) On January 15, 2003, the Company called the remaining $23.8 million of Indiana Gas' 9.375% private placement notes originally due in 2021. Since the proceeds to repay the notes were generated from short-term borrowings, these notes are classified in current maturities of long-term debt at December 31, 2002. (3) Included in rental commitments is a synthetic lease involving a transportation asset. A synthetic lease allows the Company to keep certain assets and corresponding debt off balance sheet while keeping the asset on the balance sheet for tax purposes. If the Company were to consolidate the special purpose entity that owns the asset, the Company would record additional assets and debt both totaling approximately $4.5 million. Planned Capital Expenditures & Investments Capital expenditures and investments in nonregulated unconsolidated affiliates for the five-year period 2003 - 2007 are estimated as follows: In millions 2003 2004 2005 2006 2007 - ---------------------------------------------------------------------------- Capital expenditures Regulated (1) $ 204.8 $ 236.5 $ 184.9 $ 145.1 $ 135.4 Nonregulated 7.8 6.5 5.7 6.9 7.3 Corporate & other 22.3 27.8 10.5 16.4 11.3 - ---------------------------------------------------------------------------- Total capital expenditures $ 234.9 $ 270.8 $ 201.1 $ 168.4 $ 154.0 ============================================================================ Investments in unconsolidated affiliates $ 14.6 $ 15.9 $ 18.8 $ 11.0 $ 12.2 ============================================================================ (1) Includes expenditures for NOx compliance of approximately $83.0 million in 2003, $79.0 million in 2004, $23.7 million in 2005, and $4.6 million in 2006. Ratings Triggers At December 31, 2002, $113.0 million of Cap Corp's senior unsecured notes were subject to cross-default and ratings trigger provisions that would provide that the full balance outstanding is subject to prepayment if the ratings of Indiana Gas or SIGECO declined to BBB/Baa2. In addition, accrued interest and a make whole amount based on the discounted value of the remaining payments due on the notes would also become payable. Ratings triggers on Cap Corp's bank loans and VUHI's commercial paper back up facility existing at December 31, 2001 were removed as facilities were renewed during 2002. As previously discussed under Financial Condition above, Indiana Gas and SIGECO ratings were downgraded to Baa1 by Moody's and remain at one level above the ratings trigger. Effective January 1, 2003, the Company transferred assets which primarily related to its regulated operations to VUHI in order to make approximately $60 million of additional nonregulated and corporate capacity available and is currently exploring expanding unutilized capacity under its nonregulated short-term borrowing facilities for additional liquidity protection. Guarantees and Letters of Credit The Company is party to financial guarantees with off-balance sheet risk. These guarantees may include posted letters of credit, debt and leasing guarantees, performance guarantees, and energy saving guarantees and may periodically include the debt of and performance obligations of unconsolidated affiliates. The Company estimates these guarantees totaled approximately $117 million at December 31, 2002, including outstanding letters of credit. The Company's most significant guarantee approximating $60 million represents two-thirds of Energy Systems Group, LLC's (ESG) surety bonds, performance guarantees, and energy savings guarantees. ESG is a two-thirds owned consolidated subsidiary. The guarantees relate to amounts due to various insurance companies for surety bonds should ESG default on obligations to complete construction, pay vendors or subcontractors, or to achieve energy guarantees. Through December 31, 2002, the Company has not been called upon to satisfy any obligations pursuant to its guarantees. Vectren guarantees the outstanding long-term and short-term debt of Cap Corp, which totaled $113.0 million and $157.8 million, respectively, at December 31, 2002. VUHI's currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. VUHI's long-term and short-term debt outstanding at December 31, 2002 totaled $350.0 million and $239.1 million, respectively. Pension and Postretirement Funding Obligations The Company has not made significant contributions to its qualified pension plans in recent years. Due to poor market performance during 2000-2002, it will be necessary for the Company to make contributions to benefits plans in the coming years. Management currently estimates that the qualified pension plans will require Company contributions of less than $1 million in 2003 and between $5 million and $10 million in 2004 and 2005. Forward-Looking Information A "safe harbor" for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Certain matters described in Management's Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements. Such statements are based on management's beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words "believe," "anticipate," "endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal," and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements included, among others, the following: o Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas supply costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints. o Increased competition in the energy environment including effects of industry restructuring and unbundling. o Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases. o Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board; the Securities and Exchange Commission; the Federal Energy Regulatory Commission; state public utility commissions; state entities which regulate electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight. o Economic conditions including the effects of an economic downturn, inflation rates, and monetary fluctuations. o Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks. o The performance of projects undertaken by the Company's nonregulated businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the realization of Section 29 income tax credits and the Company's coal mining, gas marketing, and broadband strategies. o Direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit rating, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries. o Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages. o Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures. o Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters, including, but not limited to, those described in Management's Discussion and Analysis of Results of Operations and Financial Condition. o Changes in federal, state or local legislature requirements, such as changes in tax laws or rates, environmental laws and regulations. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements. ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit. These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program. The Company's risk management program includes, among other things, the use of derivatives to mitigate risk. The Company also executes derivative contracts in the normal course of operations while buying and selling commodities and other fungible goods to be used in operations and while optimizing generation assets. The Company does not execute derivative contracts for speculative or trading purposes. Commodity Price Risk The Company's regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations, which subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Electric sales and purchases in the wholesale power market and other commodity-related operations are exposed to commodity price risk associated with fluctuating electric power, natural gas, coal, and other commodity prices. Other commodity operations include sales of electricity to certain municipalities and large industrial customers and nonregulated retail gas marketing and coal mining operations. The Company's non-firm wholesale power marketing operations manage the utilization of its available electric generating capacity by entering into forward and option contracts that commit the Company to purchase and sell electricity in the future. Commodity price risk results from forward positions that commit the Company to deliver electricity. The Company mitigates price risk exposure with planned unutilized generation capability and offsetting forward purchase contracts. The Company's other commodity-related operations involve the purchase and sale of commodities, including electricity, natural gas, and coal, to meet customer demands and operational needs. These operations also enter into forward and option contracts that commit the Company to purchase and sell commodities in the future. Price risk from forward positions that commit the Company to deliver commodities is mitigated using stored inventory, insurance contracts, and offsetting forward purchase contracts. In addition, price risk also results from forward contracts to purchase commodities to fulfill forecasted sales transactions that may, or may not, occur. Open positions in terms of price, volume, and specified delivery points may occur and are managed using methods described above and frequent management reporting. Market risk is measured by management as the potential impact on pre-tax earnings resulting from a 10% adverse change in the forward price of commodity prices on outstanding market sensitive financial instruments (all contracts not expected to be settled by physical receipt or delivery). For the years ended December 31, 2002 and 2001, a 10% adverse change in commodity forward prices on market sensitive financial instruments would have decreased pre-tax earnings by approximately $1.5 million and $2.0 million, respectively. Commodity Price Risk from Unconsolidated Affiliate ProLiance, a nonregulated energy marketing affiliate, engages in energy hedging activities to manage pricing decisions, minimize the risk of price volatility, and minimize price risk exposure in the energy markets. ProLiance's market exposure arises from storage inventory, imbalances, and fixed-price forward purchase and sale contracts, which are entered into to support its operating activities. Currently, ProLiance buys and sells physical commodities and utilizes financial instruments to hedge its market exposure. However, net open positions in terms of price, volume and specified delivery point do occur. ProLiance manages open positions with policies which limit its exposure to market risk and require reporting potential financial exposure to its management and its members. As a result of ProLiance's risk management policies, management believes that ProLiance's exposure to market risk will not result in material earnings or cash flow loss to the Company. Interest Rate Risk The Company is exposed to interest rate risk associated with its adjustable rate borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on operations. The Company tries to limit the amount of adjustable rate borrowing arrangements exposed to short-term interest rate volatility to a maximum of 25% of total debt. However, there are times when this targeted level of interest rate exposure may be exceeded. At December 31, 2002, such obligations represented 30% of the Company's total debt portfolio. To manage this exposure, the Company may periodically use derivative financial instruments to reduce earnings fluctuations caused by interest rate volatility. Market risk is estimated as the potential impact resulting from fluctuations in interest rates on adjustable rate borrowing arrangements exposed to short-term interest rate volatility including bank notes, lines of credit, commercial paper, and certain adjustable rate long-term debt instruments. At December 31, 2002 and 2001, the combined borrowings under these facilities totaled $419.4 million and $403.0 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2002 and 2001, an increase of 100 basis points (1%) in the rates would have increased interest expense by $3.1 million and $6.2 million, respectively. Of the 2001 exposure, approximately $1.5 million would have been offset by an interest rate swap designated to hedge such exposure. Other Risks By using forward purchase contracts and derivative financial instruments to manage risk, the Company exposes itself to counter-party credit risk and market risk. The Company manages exposure to counter-party credit risk by entering into contracts with companies that can be reasonably expected to fully perform under the terms of the contract. Counter-party credit risk is monitored regularly and positions are adjusted appropriately to manage risk. Further, tools such as netting arrangements and requests for collateral are also used to manage credit risk. Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices or interest rates. The Company attempts to manage exposure to market risk associated with commodity contracts and interest rates by establishing parameters and monitoring those parameters that limit the types and degree of market risk that may be undertaken. The Company's customer receivables from gas and electric sales and gas transportation services are primarily derived from a diversified base of residential, commercial, and industrial customers located in Indiana and west central Ohio. The Company manages credit risk associated with its receivables by continually reviewing creditworthiness and requests cash deposits or refunds cash deposits based on that review. Credit risk associated with certain investments is also managed by a review of creditworthiness and receipt of collateral. Although the Company's regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements; increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas; and some level of price sensitive reduction in volumes sold. ITEM 8. Financial Statements and Supplementary Data MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of Vectren Corporation is responsible for the preparation of the consolidated financial statements and the related financial data contained in this report. The financial statements are prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities. The integrity and objectivity of the data in this report, including required estimates and judgments, is the responsibility of management. Management maintains a system of internal control and utilizes an internal auditing program to provide reasonable assurance of compliance with Company policies and procedures and the safeguard of assets. The board of directors pursues its responsibility for these financial statements through its audit committee, which meets periodically with management, the internal auditors and the independent auditors, to assure that each is carrying out its responsibilities. Both the internal auditors and the independent auditors meet with the audit committee of Vectren Corporation's board of directors, with and without management representatives present, to discuss the scope and results of their audits, their comments on the adequacy of internal accounting control and the quality of financial reporting. /S/ Niel C. Ellerbrook Niel C. Ellerbrook Chairman & Chief Executive Officer February 26, 2003. INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Vectren Corporation: We have audited the accompanying consolidated balance sheets of Vectren Corporation and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2002. Our audits also included the financial statement schedules listed in the Table of Contents at Item 15. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, such consolidated financial statements present fairly, in all material respects, the financial position of Vectren Corporation and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. As discussed in Note 2, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards ("SFAS") 142, "Goodwill and Other Intangibles." As discussed in Note 16, effective, January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. As discussed in Note 3, the accompanying 2001 and 2000 financial statements have been restated. /S/ DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Indianapolis, Indiana February 26, 2003 VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (In millions) At December 31, - ----------------------------------------------------------------------------- 2002 2001 - ----------------------------------------------------------------------------- (As Restated, ASSETS See Note 3) Current Assets Cash & cash equivalents $ 25.1 $ 25.0 Accounts receivable-less reserves of $5.5 & $5.3, respectively 154.4 208.3 Accrued unbilled revenues 116.1 76.7 Inventories 62.8 70.9 Recoverable fuel & natural gas costs 22.1 70.2 Prepayments & other current assets 93.0 131.0 - ----------------------------------------------------------------------------- Total current assets 473.5 582.1 - ----------------------------------------------------------------------------- Utility Plant Original cost 3,037.1 2,906.1 Less: accumulated depreciation & amortization 1,389.0 1,308.2 - ----------------------------------------------------------------------------- Net utility plant 1,648.1 1,597.9 - ----------------------------------------------------------------------------- Investments in unconsolidated affiliates 153.3 128.6 Other investments 124.3 99.8 Non-utility property-net 228.0 182.8 Goodwill-net 202.2 201.5 Regulatory assets 75.2 67.8 Other assets 21.9 18.2 - ----------------------------------------------------------------------------- TOTAL ASSETS $ 2,926.5 $ 2,878.7 ============================================================================= The accompanying notes are an integral part of these consolidated financial statements. VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (In millions) At December 31, - -------------------------------------------------------------------------------- 2002 2001 - -------------------------------------------------------------------------------- (As Restated, LIABILITIES & SHAREHOLDERS' EQUITY See Note 3) Current Liabilities Accounts payable $ 101.7 $ 145.2 Accounts payable to affiliated companies 86.4 38.1 Accrued liabilities 119.9 118.5 Short-term borrowings 399.5 383.3 Current maturities of long-term debt 39.8 1.3 Long-term debt subject to tender 26.6 11.5 - -------------------------------------------------------------------------------- Total current liabilities 773.9 697.9 - -------------------------------------------------------------------------------- Long-term Debt-Net of Current Maturities & Debt Subject to Tender 954.2 1,014.0 Deferred Income Taxes & Other Liabilities Deferred income taxes 195.5 216.3 Deferred credits & other liabilities 130.8 109.3 - -------------------------------------------------------------------------------- Total deferred credits & other liabilities 326.3 325.6 - -------------------------------------------------------------------------------- Minority Interest in Subsidiary 1.9 1.4 Commitments & Contingencies (Notes 4, 13-15) Cumulative, Redeemable Preferred Stock of a Subsidiary 0.3 0.5 Common Shareholders' Equity Common stock (no par value) - issued & outstanding 67.9 and 67.7, respectively 350.0 346.1 Retained earnings 530.4 489.1 Accumulated other comprehensive income (10.5) 4.1 - -------------------------------------------------------------------------------- Total common shareholders' equity 869.9 839.3 - -------------------------------------------------------------------------------- TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 2,926.5 $ 2,878.7 ================================================================================ The accompanying notes are an integral part of these consolidated financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (In millions, except per share amounts) Year Ended December 31, - -------------------------------------------------------------------------------------- 2002 2001 2000 - -------------------------------------------------------------------------------------- OPERATING REVENUES (As Restated, See Note 3) ------------------------ Gas utility $ 909.0 $ 1,019.6 $ 820.4 Electric utility 608.1 381.2 334.4 Energy services & other 287.2 681.0 478.0 - -------------------------------------------------------------------------------------- Total operating revenues 1,804.3 2,081.8 1,632.8 - -------------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 571.2 708.9 552.5 Fuel for electric generation 81.6 74.4 75.7 Purchased electric energy 296.3 86.9 36.4 Cost of energy services & other 249.4 640.9 453.2 Other operating 223.0 243.2 198.5 Merger & integration costs - 2.8 41.1 Restructuring costs - 19.0 - Depreciation & amortization 119.6 124.1 105.7 Taxes other than income taxes 51.9 53.7 38.0 - -------------------------------------------------------------------------------------- Total operating expenses 1,593.0 1,953.9 1,501.1 - -------------------------------------------------------------------------------------- OPERATING INCOME 211.3 127.9 131.7 OTHER INCOME Equity in earnings of unconsolidated affiliates 9.1 13.4 9.8 Other - net 11.5 16.7 23.1 - -------------------------------------------------------------------------------------- Total other income 20.6 30.1 32.9 - -------------------------------------------------------------------------------------- Interest expense 78.5 83.2 56.4 - -------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 153.4 74.8 108.2 - -------------------------------------------------------------------------------------- Income taxes 38.9 14.1 34.2 Minority interest in & preferred dividend requirements of subsidiaries 0.5 1.4 2.0 - -------------------------------------------------------------------------------------- INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 114.0 59.3 72.0 - -------------------------------------------------------------------------------------- Extraordinary loss - net of tax - (7.7) - Cumulative effect of change in accounting principle - net of tax - 1.1 - - -------------------------------------------------------------------------------------- NET INCOME $ 114.0 $ 52.7 $ 72.0 ====================================================================================== AVERAGE COMMON SHARES OUTSTANDING 67.6 66.7 61.3 DILUTED COMMON SHARES OUTSTANDING 67.9 66.9 61.4 EARNINGS PER SHARE OF COMMON STOCK: BASIC INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.69 $ 0.89 $ 1.18 Extraordinary loss - net of tax - (0.12) - Cumulative effect of change in accounting principle - net of tax - 0.02 - - -------------------------------------------------------------------------------------- BASIC EARNINGS PER SHARE OF COMMON STOCK $ 1.69 $ 0.79 $ 1.18 ====================================================================================== DILUTED INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.68 $ 0.89 $ 1.17 Extraordinary loss - net of tax - (0.12) - Cumulative effect of change in accounting principle - net of tax - 0.02 - - -------------------------------------------------------------------------------------- DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 1.68 $ 0.79 $ 1.17 ======================================================================================
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In millions) Year Ended December 31, - -------------------------------------------------------------------------------------- 2002 2001 2000 - -------------------------------------------------------------------------------------- (As Restated, CASH FLOWS FROM OPERATING ACTIVITIES See Note 3) ------------------ Net income $ 114.0 $ 52.7 $ 72.0 Adjustments to reconcile net income to cash from operating activities: Depreciation & amortization 119.6 124.1 105.7 Deferred income taxes & investment tax credits (28.5) 12.4 (5.8) Equity in earnings of unconsolidated affiliates (9.1) (13.4) (9.8) Net unrealized loss (gain) on derivative instruments, including cumulative effect of change in accounting principle 3.6 (3.3) - Extraordinary loss on sale of leveraged leases - net of tax - 7.7 - Pension and postretirement expense 13.2 8.5 9.8 Other non-cash charges- net 7.5 13.1 (0.4) Changes in working capital accounts: Accounts receivable & accrued unbilled revenue (42.0) 135.5 (255.8) Inventories 0.4 24.2 17.8 Recoverable fuel & natural gas costs 48.1 25.9 (82.3) Prepayments & other current assets 31.2 (70.3) (3.4) Accounts payable, including to affiliated companies 40.7 (120.6) 208.2 Accrued liabilities 11.7 (7.0) (2.4) Changes in noncurrent assets (6.0) 4.6 1.2 Changes in noncurrent liabilities (12.1) (6.0) (8.2) - -------------------------------------------------------------------------------------- Net cash flows from operating activities 292.3 188.1 46.6 - -------------------------------------------------------------------------------------- CASH FLOWS (REQUIRED FOR) FROM FINANCING ACTIVITIES Proceeds from: Long-term debt - net of issuance costs - 344.0 145.3 Common stock - net of issuance costs - 129.4 - Short-term notes payable - - 150.0 Requirements for: Dividends on common stock (72.3) (69.5) (60.0) Retirement of long-term debt (6.5) (7.6) (3.3) Redemption of preferred stock of subsidiary (0.2) (17.7) (2.0) Retirement of short-term notes payable - (150.0) - Dividends on preferred stock of subsidiary - (0.8) (1.0) Net change in short-term borrowings 20.3 (228.2) 402.3 Proceeds (payments) from exercise of stock options & other 1.1 (2.3) 7.4 - -------------------------------------------------------------------------------------- Net cash flows (required for) from financing activitiesS (57.6) (2.7) 638.7 - -------------------------------------------------------------------------------------- CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES Proceeds from: Unconsolidated affiliate distributions 7.4 22.5 7.0 Sale of leveraged lease investments - 53.8 - Notes receivable & other collections 3.9 16.6 9.0 Requirements for: Capital expenditures, excluding AFUDC-equity (218.7) (239.7) (164.3) Unconsolidated affiliate investments (12.5) (22.7) (29.4) Acquisition of Ohio operations - (2.2) (469.2) Notes receivable & other investments (14.7) (3.9) (40.6) - -------------------------------------------------------------------------------------- Net cash flows (required for) investing activities (234.6) (175.6) (687.5) - -------------------------------------------------------------------------------------- Net increase (decrease) in cash & cash equivalents 0.1 9.8 (2.2) Cash & cash equivalents at beginning of period 25.0 15.2 17.4 - -------------------------------------------------------------------------------------- Cash & cash equivalents at end of period $ 25.1 $ 25.0 $ 15.2 ======================================================================================
The accompanying notes are an integral part of these consolidated financial statements.
VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (In millions, except per share amounts) Common Stock ------------------------- Accumulated Restricted Other Stock Retained Comprehensive Shares Amount Grants Earnings Income (Loss) Total - ---------------------------------------------------------------------------------------------------- Balance at January 1, 2000, As Reported 61.3 $ 217.5 $ (1.5) $ 493.9 $ (0.1) $ 709.8 Restatement adjustment 1.7 1.7 - ---------------------------------------------------------------------------------------------------- Balance at January 1, 2000, As Restated 61.3 217.5 (1.5) 495.6 (0.1) 711.5 - ---------------------------------------------------------------------------------------------------- Comprehensive income: Net income 72.0 72.0 Minimum pension liability adjustments & other - net of tax 0.1 0.1 Comprehensive income of unconsolidated affiliates - net of tax 7.5 7.5 - ---------------------------------------------------------------------------------------------------- Total comprehensive income (As Restated) 79.6 - ---------------------------------------------------------------------------------------------------- Common stock dividends ($0.98 per share) (60.0) (60.0) Other 0.1 1.8 0.5 2.3 - ---------------------------------------------------------------------------------------------------- Balance at December 31, 2000, As Restated 61.4 219.3 (1.5) 508.1 7.5 733.4 - ---------------------------------------------------------------------------------------------------- Comprehensive income: Net income (As Restated, See Note 3) 52.7 52.7 Minimum pension liability adjustments & other - net of tax (1.8) (1.8) Comprehensive income of unconsolidated affiliates - net of tax (1.6) (1.6) - ---------------------------------------------------------------------------------------------------- Total comprehensive income, (As Restated) 49.3 - ---------------------------------------------------------------------------------------------------- Common stock: Issuance - net of $5.1 issuance costs 6.3 129.4 129.4 Dividends ($1.03 per share) (69.5) (69.5) Other (0.1) (1.0) (2.2) (3.3) - ---------------------------------------------------------------------------------------------------- Balance at December 31, 2001, As Restated 67.7 348.6 (2.5) 489.1 4.1 839.3 - ---------------------------------------------------------------------------------------------------- Comprehensive income: Net income 114.0 114.0 Minimum pension liability adjustments & other - net of tax (9.3) (9.3) Comprehensive income of unconsolidated affiliates - net of tax (5.3) (5.3) - ---------------------------------------------------------------------------------------------------- Total comprehensive income 99.4 - ---------------------------------------------------------------------------------------------------- Common stock dividends ($1.07 per share) (72.3) (72.3) Other 0.2 3.7 0.2 (0.4) 3.5 - ---------------------------------------------------------------------------------------------------- Balance at December 31, 2002 67.9 $ 352.3 $ (2.3) $ 530.4 $(10.5) $ 869.9 ====================================================================================================
The accompanying notes are an integral part of these consolidated financial statements. VECTREN CORPORATION AND SUBSIDIARY COMPANIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Nature of Operations Overview Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company was organized on June 10, 1999 solely for the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with APB Opinion No. 16 "Business Combinations" (APB 16). The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI), serves as the intermediate holding company for its three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations. Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935. Indiana Gas provides natural gas distribution and transportation services to a diversified customer base in 49 of Indiana's 92 counties. SIGECO provides electric generation, transmission, and distribution services to 8 counties in southwestern Indiana, including counties surrounding Evansville, and participates in the wholesale power market. SIGECO also provides natural gas distribution and transportation services to 10 counties in southwestern Indiana, including counties surrounding Evansville. The Ohio operations provide natural gas distribution and transportation services to 17 counties in west central Ohio, including counties surrounding Dayton. The Company is also involved in nonregulated activities in four primary business areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure Services, and Broadband. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal to the Company's utility operations and to other parties and generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. Broadband invests in broadband communication services such as analog and digital cable television, high-speed Internet and data services, and advanced local and long distance phone services. In addition, the nonregulated group has other businesses that provide utility services, municipal broadband consulting, and retail products and services and that invest in energy-related opportunities, real estate and leveraged leases. Acquisition of the Natural Gas Distribution Assets of The Dayton Power and Light Company On October 31, 2000, the Company acquired the natural gas distribution assets of The Dayton Power and Light Company for $471 million, including transaction costs. The acquisition has been accounted for as a purchase transaction in accordance with APB 16, and accordingly, the results of operations of the acquired assets are included in the Company's financial results since the date of acquisition. The Company acquired the natural gas distribution assets as a tenancy in common through two separate wholly owned subsidiaries. Vectren Energy Delivery of Ohio, Inc. (VEDO) holds a 53% undivided ownership interest in the assets, and Indiana Gas holds a 47% undivided ownership interest. VEDO is the operator of the assets, and these operations are referred to as "the Ohio operations." The purchase price was allocated to the assets and liabilities acquired based on the fair value of those assets and liabilities as of the acquisition date. Because of the regulatory environment in which the Ohio operations operate, the book value of rate-regulated assets and liabilities is generally considered to be fair value. Goodwill, in the amount of $202.5 million, has been recognized for the excess amount of the purchase price paid over the fair value of the net assets acquired. Had the acquisition of the Ohio operations occurred on January 1, 2000, pro forma operating revenues, net income, and basic and diluted earnings per share for the year ended December 31, 2000 would have been $1,817.2 million, $72.0 million, $1.18, and $1.17, respectively. This pro forma information is not necessarily indicative of the results that actually would have occurred if the transaction had been consummated at the beginning of the periods presented and is not intended to be a projection of future results. 2. Summary of Significant Accounting Policies A. Principles of Consolidation The accompanying consolidated financial statements for the period prior to March 31, 2000 reflect the results of the Company on a historical basis as restated for the effects of the pooling-of-interests transaction completed on March 31, 2000 between Indiana Energy and SIGCORP. The consolidated financial statements include the accounts of the Company and its wholly owned and majority owned subsidiaries, after elimination of intercompany transactions. For the three months ended March 31, 2000, operating revenues and net income contributed by the predecessor companies were $172.0 million and $22.1 million, respectively, by Indiana Energy and $187.4 million and $19.3 million, respectively, by SIGCORP. B. Cash & Cash Equivalents All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. Cash paid during the periods reported for interest, income taxes, and acquired assets and liabilities follows: Year Ended December 31, - ----------------------------------------------------------------------------- In millions 2002 2001 2000 - ----------------------------------------------------------------------------- Cash paid for Interest $ 67.1 $ 74.9 $ 55.7 Income taxes 16.5 38.0 53.5 - ----------------------------------------------------------------------------- Details of acquisition (Note 1) Book value of assets acquired $ - $ 1.6 $ 275.2 Liabilities assumed - - 7.9 - ----------------------------------------------------------------------------- Net assets acquired $ - $ 1.6 $ 267.3 ============================================================================= C. Inventories Inventories consist of the following: At December 31, - --------------------------------------------------------------------------- In millions 2002 2001 - --------------------------------------------------------------------------- Gas in storage - at LIFO cost $ 25.4 $ 24.4 Materials & supplies 19.7 21.0 Fuel (coal & oil) for electric generation 11.3 10.3 Gas in storage - at average cost 3.2 11.6 Other 3.2 3.6 - --------------------------------------------------------------------------- Total inventories $ 62.8 $ 70.9 =========================================================================== Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2002 and 2001 by approximately $32.7 million and $17.9 million, respectively. Gas in storage of the Indiana regulated operations is stated at LIFO. All other inventories are carried at average cost. D. Utility Plant & Depreciation Utility plant is stated at historical cost, including AFUDC. Depreciation of utility property is provided using the straight-line method over the estimated service lives of the depreciable assets. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows: At and For the Year Ended December 31, - ------------------------------------------------------------------------------- In millions 2002 2001 - ------------------------------ ----------------------- ---------------------- Depreciation Depreciation Rates as a Rates as a Original Percent of Original Percent of Cost Original Cost Cost Original Cost - ------------------------------------------------------------------------------- Gas utility plant $1,622.0 3.8% $1,523.0 3.6% Electric utility plant 1,211.0 3.3% 1,148.9 3.3% Common utility plant 41.6 2.6% 41.3 2.6% Construction work in progress 162.5 - 192.9 - - ------------------------------------------------------------------------------- Total original cost $3,037.1 $2,906.1 =============================================================================== AFUDC represents the cost of borrowed and equity funds used for construction purposes and is charged to construction work in progress during the construction period and is included in other - net in the Consolidated Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows: Year Ended December 31, - --------------------------------------------------------------------------- In millions 2002 2001 2000 - --------------------------------------------------------------------------- AFUDC - borrowed funds $ 3.1 $ 2.1 $ 2.4 AFUDC - equity funds 2.2 2.5 2.6 - --------------------------------------------------------------------------- Total AFUDC capitalized $ 5.3 $ 4.6 $ 5.0 =========================================================================== Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. When property that represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, together with the cost of removal less salvage, is charged to accumulated depreciation. E. Non-utility Property Non-utility property, net of accumulated depreciation and amortization, by operating segment follows: At December 31, - ------------------------------------------------------------------------- In millions 2002 2001 - ------------------------------------------------------------------------- Corporate & Other $ 140.5 $ 103.1 Nonregulated Operations 78.8 73.4 Electric & Gas Utility Services 8.7 6.3 - ------------------------------------------------------------------------- Non-utility property-net $ 228.0 $ 182.8 ========================================================================= The depreciation of non-utility property is charged against income over its estimated useful life (ranging from 5 to 40 years), using the straight-line method of depreciation or units-of-production method of amortization. Repairs and maintenance, which are not considered improvements and do not extend the useful life of the non-utility property, are charged to expense as incurred. When non-utility property is retired, or otherwise disposed of, the asset and accumulated depreciation are removed, and the resulting gain or loss is reflected in income. Non-utility property is presented net of accumulated depreciation and amortization totaling $104.7 million and $83.0 million as of December 31, 2002 and 2001, respectively. For the years ended December 31, 2002, 2001, and 2000, the Company capitalized interest totaling $0.4 million, $1.7 million, and $1.5 million, respectively, on non-utility plant construction projects. F. Impairment Review of Long-Lived Assets Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144), which the Company adopted as required on January 1, 2002. SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 replaced authoritative guidance in SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and certain aspects of APB Opinion No. 30, "Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business." SFAS 144 retains the framework of SFAS 121 and requires the evaluation for impairment involve the comparison of an asset's carrying value to the estimated future cash flows the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset's carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. G. Goodwill Goodwill arising from past business combinations, such as the Company's acquisition of the Ohio operations, is accounted for in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company adopted SFAS 142, as required on January 1, 2002. SFAS 142 changed the accounting for goodwill from an amortization approach to an impairment-only approach. Thus, amortization of goodwill that was not included as an allowable cost for rate-making purposes ceased upon SFAS 142's adoption. Goodwill is to be tested for impairment at a reporting unit level at least annually. The impairment review consists of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Prior to the adoption of SFAS 142, the Company amortized goodwill on a straight-line basis over 40 years. SFAS 142 required an initial impairment review of all goodwill within six months of the adoption date. Results of the initial impairment review were to be treated as a change in accounting principle in accordance with APB Opinion No. 20 "Accounting Changes." As required by SFAS 142, amortization of goodwill relating to the acquisition of the Ohio operations ceased on January 1, 2002. In 2001, net income before extraordinary loss and cumulative effect of change in accounting principle and net income would have been $62.3 million and $55.7 million, respectively, had goodwill not been amortized and in 2000, net income would have been $72.5 million had goodwill not been amortized. The Company's goodwill is included in the Gas Utility Services operating segment. Initial impairment reviews to be performed within six months of adoption of SFAS 142 were completed and resulted in no impairment. The impairment test is performed at the beginning of each year. Following is a reconciliation of reported net income and earnings per share to the adjusted net income disclosed above and related earnings per share for years ended December 31, 2001 and 2000:
Net Income Basic EPS Diluted EPS -------------- -------------- -------------- In millions (except per share amounts) 2001 2000 2001 2000 2001 2000 - ---------------------------------------- -------------- -------------- -------------- As Reported $52.7 $72.0 $0.79 $1.18 $0.79 $1.17 Add: goodwill amortization - net of tax 3.0 0.5 0.05 0.01 0.05 0.01 - ---------------------------------------------------------------------------------------------- As adjusted $55.7 $72.5 $0.84 $1.19 $0.84 $1.18 ==============================================================================================
H. Regulation Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting Ohio customers are subject to regulation by the PUCO. SFAS 71 The Company's accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the rate-making process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. The Company assesses the recoverability of costs recognized as regulatory assets and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets. Regulatory assets consist of the following: At December 31, - ----------------------------------------------------------- In millions 2002 2001 - ----------------------------------------------------------- Demand side management programs $ 32.1 $ 31.7 Unamortized debt issue costs 19.5 21.2 Regulatory income tax asset 15.8 10.3 Other 7.8 4.6 - ----------------------------------------------------------- Total regulatory assets $ 75.2 $ 67.8 =========================================================== As of December 31, 2002, regulatory assets totaling $42.6 million are reflected in rates charged to customers, of which $17.2 million is earning a return. The remaining $32.6 million, which is not yet included in rates, represents primarily electric demand side management (DSM) costs incurred after 1993. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable. At December 31, 2002, the weighted average recovery period of regulatory assets, other than those arising from book - - tax basis differences, included in rates is 16.0 years. Regulatory income tax assets are recovered as deferred tax assets and liabilities discussed in Note 6 become payable or receivable. Refundable or Recoverable Gas Costs, Fuel for Electric Production & Purchased Power All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates typically contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel and the net energy cost of purchased power. Metered electric rates also allow recovery, through a quarterly rate adjustment mechanism, for the margin on electric sales lost due to the implementation of demand side management programs. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel for electric generation is charged to operating expense when consumed. I. Comprehensive Income Comprehensive income is a measure of all changes in equity that result from the transactions or other economic events during the period from non-shareholder transactions. This information is reported in the Consolidated Statements of Common Shareholders' Equity. A summary of the components of and changes in accumulated other comprehensive income for the past three years follows:
2000 2001 2002 --------------------------- --------------- ---------------- Beginning Changes End Changes End Changes End of Year During of Year During of Year During of Year In millions Balance Year Balance Year Balance Year Balance - -------------------------- --------- ------- ------- ------- ------- ------- ------- Unconsolidated affiliates $ - $ 7.5 $ 7.5 $ (1.6) $ 5.9 $ (5.3) $ 0.6 Minimum pension liability adjustments & other (0.01) 0.01 - (1.8) (1.8) (9.3) (11.1) - ----------------------------------------------------------------------------------------- Accumulated other comprehensive income $ (0.1) $ 7.6 $ 7.5 $ (3.4) $ 4.1 $(14.6) $(10.5) =========================================================================================
Accumulated other comprehensive income arising from unconsolidated affiliates is the Company's portion of ProLiance Energy, LLC's and Reliant Services, LLC's accumulated comprehensive income related to its adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS133) and continued use of cash flow hedges, including commodity contracts and interest rate swaps, and the Company's portion of Haddington Energy Partners, LP's accumulated comprehensive income related to unrealized gains and losses of "available for sale securities." (See Note 4 for more information on unconsolidated affiliates.) J. Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period. K. Excise and Gross Receipts Taxes Excise taxes and a portion of gross receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $32.4 million in 2002, $26.6 million in 2001, and $16.6 million in 2000. Excise and gross receipts taxes paid are recorded as a component of taxes other than income taxes. L. Other Significant Policies Included elsewhere in these notes are significant accounting policies related to investments in unconsolidated affiliates (Note 4), income taxes (Note 6), earnings per share (Note 11), and derivatives (Note 16). As more fully described in Note 12, the Company applies the intrinsic method prescribed in APB Opinion 25, "Accounting for Stock Issued to Employees" (APB25) and related interpretations when measuring compensation expense for its stock-based compensation plans. The exercise price of stock options awarded under the Company's stock option plans is equal to the fair market value of the underlying common stock on the date of grant. Accordingly, no compensation expense has been recognized for stock option plans. The Company also maintains restricted stock and phantom stock plans for executives and non-employee directors that result in stock-based compensation expense recognized in reported net income. The amount of expense recorded in net income is consistent with expense that would have been recognized if the Company used the fair value based method prescribed in SFAS No. 123 "Accounting for Stock-Based Compensation" (SFAS 123). Following is the effect on net income and earnings per share as if the fair value based method prescribed in SFAS 123, as amended by SFAS 148 "Accounting for Stock-Based Compensation - Transition and Disclosure" had been applied to the Company's stock- based compensation plans:
Year Ended December 31, - ----------------------------------------------------------------------------------- In millions, except per share amounts 2002 2001 2000 - ----------------------------------------------------------------------------------- Net Income: As reported $ 114.0 $ 52.7 $ 72.0 Add: Stock-based employee compensation included in reported net income- net of tax 1.3 1.7 1.8 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards- net of tax 2.1 2.8 2.2 - ----------------------------------------------------------------------------------- Pro forma $ 113.2 $ 51.6 $ 71.6 =================================================================================== Basic Earnings Per Share: As reported $ 1.69 $ 0.79 $ 1.18 Pro forma 1.68 0.77 1.17 Diluted Earnings Per Share: As reported $ 1.68 $ 0.79 $ 1.17 Pro forma 1.67 0.77 1.16
M. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. 3. Restatement of Previously Reported Results The Company identified adjustments that, in the aggregate, reduced previously reported 2001 earnings by approximately $10.9 million after tax, or $0.16 per share, and other adjustments, as described below, related to 2000 and prior periods. Adjustments were also made to previously reported 2002 quarterly results. In addition to adjustments affecting previously reported net income, other reclassifications were made to the previously reported 2001 and 2000 results to conform with the 2002 presentation. Previously Reported 2001 and 2000 Net Income Adjustments The Company determined that $11.6 million ($7.2 million after tax) of gas costs were improperly recorded as recoverable gas costs due from customers. The error related primarily to the accounting for natural gas inventory and resulted in an overstatement of 2001 earnings. The Company also identified an accounting error related to certain employee benefit and other related costs that are routinely accumulated on the balance sheet and systematically cleared to operating expense and capital projects. Because of inadequate loading rates, these costs were not fully cleared to operating expense and capital projects in 2001. As a result, 2001 earnings were overstated by $5.6 million ($3.5 million after tax). The accounting for certain wholesale power marketing contracts was modified to comply with SFAS 133, which became effective on January 1, 2001. The cumulative effect at adoption was decreased by $2.8 million after tax. This change was offset substantially by an increase in electric margins throughout 2001. The Company identified reconciliation errors and other errors related to the recording of estimates that were not significant, either individually or in the aggregate. As a result of these additional items, 2001 earnings were reduced by $2.6 million ($1.6 million after tax). Originally reflected in 2001, the correction of the year 2000 overstatement of electric revenue totaling $2.4 million ($1.5 million after tax), now reflected in 2000 as discussed below, significantly offset these additional items. The Company also determined that certain billings and collections had been improperly recorded in 2000, resulting in an understatement of gas revenue by $1.8 million ($1.1 million after tax) and an overstatement of electric revenue by $2.4 million ($1.5 million after tax). Other errors were identified that increased 2000 earnings by $0.6 million ($0.3 million after tax). The impact of the restatement of results for the year ended 2000 is a reduction to net income of less than $100,000. In addition, the Company also reduced previously reported revenues and cost of sales by $78.1 million in 2001 and $15.5 million in 2000 to adopt EITF Issue No. 99-19 "Reporting Revenue Gross as a Principal versus Net as an Agent" and to properly eliminate certain transactions in consolidation. Previously Reported 2002 Quarterly Net Income Adjustments As previously reported, in the second quarter of 2002 the Company recorded $5.2 million ($3.2 million after tax) of carrying costs for DSM programs pursuant to existing IURC orders and based on an improved regulatory environment. During the audit of the three years ended December 31, 2002, management determined that the accrual of such carrying costs was more appropriate in periods prior to 2000 when DSM program expenditures were made. Therefore, such carrying costs originally reflected in 2002 quarterly results were reversed and reflected in common shareholders' equity as of January 1, 2000. In addition, the Company identified other adjustments that were not significant, either individually or in the aggregate that increased previously reported 2002 quarterly pre-tax and after tax earnings by approximately $1.4 million and $0.9 million after tax, respectively. The cumulative impact from of these adjustments reduced previously reported earnings for the nine months ended September 30, 2002 by approximately $2.3 million. Beginning Retained Earnings Adjustments In addition to the adjustment of DSM costs above, the Company identified other errors that were not significant, either individually or in the aggregate that relate to years prior to 2000. As a result of these additional items, beginning common shareholders' equity was reduced by $1.5 million. Accordingly, retained earnings as of January 1, 2000 reflects a cumulative net increase of $1.7 million. Other Balance Sheet Adjustments Certain reclassifications were made to reflect separate Company prepaid and accrued taxes that result in the consolidated tax position. This adjustment added approximately $46.4 million of prepaid and other current assets with a corresponding increase in accrued liabilities as of December 31, 2001. The Company also reclassified all previously recorded goodwill not included in rates to goodwill on the balance sheet. This adjustment resulted in a $5.9 million decrease in other assets, a $3.0 million decrease in prepayments and other current assets and an $8.9 million increase in goodwill. The Company has restated its financial statements to give effect to the matters discussed above. Following is a summary of the significant effects of the restatement on previously reported financial position and results of operations. The effects of the restatement on 2001 quarterly results and on 2002 previously reported quarterly information, is discussed in Note 21. Note 21 is unaudited. The effects on the income statement for the year ending December 31, 2001 follow:
As Reported Adjustments As Restated - ----------------------------------------------------------------------------------- OPERATING REVENUES Gas utility $ 1,031.5 $ (11.9) $ 1,019.6 Electric utility 378.9 2.3 381.2 Energy services & other 759.6 (78.6) 681.0 - ---------------------------------------------------------------------------------- Total operating revenues 2,170.0 (88.2) 2,081.8 - ---------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 708.2 0.7 708.9 Fuel for electric generation 74.4 - 74.4 Purchased electric energy 91.7 (4.8) 86.9 Cost of energy services & other 720.2 (79.3) 640.9 Other operating 236.9 6.3 243.2 Merger & integration costs 2.8 - 2.8 Restructuring costs 19.0 - 19.0 Depreciation & amortization 123.7 0.4 124.1 Taxes other than income taxes 53.5 0.2 53.7 - ---------------------------------------------------------------------------------- Total operating expenses 2,030.4 (76.5) 1,953.9 - ---------------------------------------------------------------------------------- OPERATING INCOME 139.6 (11.7) 127.9 - ---------------------------------------------------------------------------------- OTHER INCOME Equity in earnings of unconsolidated affiliates 14.1 (0.7) 13.4 Other - net 16.3 0.4 16.7 - ---------------------------------------------------------------------------------- Total other income 30.4 (0.3) 30.1 - ---------------------------------------------------------------------------------- Interest expense 82.6 0.6 83.2 - ---------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 87.4 (12.6) 74.8 - ---------------------------------------------------------------------------------- Income taxes 18.6 (4.5) 14.1 Minority interest in and preferred dividend requirement of subsidiaries 1.4 - 1.4 - ---------------------------------------------------------------------------------- INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 67.4 (8.1) 59.3 - ---------------------------------------------------------------------------------- Extraordinary loss - net of tax (7.7) - (7.7) Cumulative effect of change in accounting principle - net of tax 3.9 (2.8) 1.1 - ---------------------------------------------------------------------------------- NET INCOME $ 63.6 $ (10.9) $ 52.7 ================================================================================== EARNINGS PER SHARE OF COMMON STOCK: BASIC INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.01 $ (0.12) $ 0.89 Extraordinary loss - net of tax (0.12) - (0.12) Cumulative effect of change in accounting principle - net of tax 0.06 (0.04) 0.02 - ---------------------------------------------------------------------------------- BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.95 $ (0.16) $ 0.79 ================================================================================== DILUTED INCOME BEFORE EXTRAORDINARY LOSS & CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 1.01 $ (0.12) $ 0.89 Extraordinary loss - net of tax (0.12) - (0.12) Cumulative effect of change in accounting principle - net of tax 0.06 (0.04) 0.02 - ---------------------------------------------------------------------------------- DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.95 $ (0.16) $ 0.79 ==================================================================================
The effects on the income statement for the year ending December 31, 2000 follow:
As Reported Adjustments As Restated - ------------------------------------------------------------------------------------ OPERATING REVENUES Gas utility $ 818.8 $ 1.6 $ 820.4 Electric utility 336.4 (2.0) 334.4 Energy services & other 493.5 (15.5) 478.0 - ------------------------------------------------------------------------------------ Total operating revenues 1,648.7 (15.9) 1,632.8 - ------------------------------------------------------------------------------------ OPERATING EXPENSES Cost of gas sold 552.5 - 552.5 Fuel for electric generation 75.7 - 75.7 Purchased electric energy 36.4 - 36.4 Cost of energy services & other 468.8 (15.6) 453.2 Other operating 199.4 (0.9) 198.5 Merger & integration costs 41.1 - 41.1 Depreciation & amortization 105.7 - 105.7 Taxes other than income taxes 38.0 - 38.0 - ------------------------------------------------------------------------------------ Total operating expenses 1,517.6 (16.5) 1,501.1 - ------------------------------------------------------------------------------------ OPERATING INCOME 131.1 0.6 131.7 OTHER INCOME Equity in earnings of unconsolidated affiliates 9.8 - 9.8 Other - net 23.7 (0.6) 23.1 - ------------------------------------------------------------------------------------ Total other income 33.5 (0.6) 32.9 - ------------------------------------------------------------------------------------ Interest expense 56.4 - 56.4 - ------------------------------------------------------------------------------------ INCOME BEFORE INCOME TAXES 108.2 - 108.2 - ------------------------------------------------------------------------------------ Income taxes 34.2 - 34.2 Minority interest in & preferred dividend requirements of subsidiaries 2.0 - 2.0 - ------------------------------------------------------------------------------------ NET INCOME $ 72.0 $ - $ 72.0 ==================================================================================== BASIC EARNINGS PER SHARE OF COMMON STOCK $ 1.18 $ - $ 1.18 ==================================================================================== DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 1.17 $ - $ 1.17 ====================================================================================
The effects on the balance sheet as of December 31, 2001 follow:
ASSETS As Reported Adjustments As Restated ----------- ----------- ----------- Current Assets Cash & cash equivalents $ 27.2 $ (2.2) $ 25.0 Accounts receivable-less reserves 213.8 (5.5) 208.3 Accrued unbilled revenues 78.4 (1.7) 76.7 Inventories 71.4 (0.5) 70.9 Recoverable fuel & natural gas costs 76.5 (6.3) 70.2 Prepayments & other current assets 103.4 27.6 131.0 - ---------------------------------------------------------------------------------- Total current assets 570.7 11.4 582.1 - ---------------------------------------------------------------------------------- Utility Plant Original cost 2,903.2 2.9 2,906.1 Less: accumulated depreciation & amortization 1,308.2 - 1,308.2 - ---------------------------------------------------------------------------------- Net utility plant 1,595.0 2.9 1,597.9 - ---------------------------------------------------------------------------------- Investments in unconsolidated affiliates 127.7 0.9 128.6 Other investments 100.3 (0.5) 99.8 Non-utility property-net 181.7 1.1 182.8 Goodwill-net 193.1 8.4 201.5 Regulatory assets 61.4 6.4 67.8 Other assets 26.9 (8.7) 18.2 - ---------------------------------------------------------------------------------- TOTAL ASSETS $2,856.8 $ 21.9 $ 2,878.7 ================================================================================== LIABILITIES & SHAREHOLDERS' EQUITY Current Liabilities Accounts payable $ 144.4 $ 0.8 $ 145.2 Accounts payable to affiliated companies 37.2 0.9 38.1 Accrued liabilities 101.4 17.1 118.5 Short-term borrowings 381.7 1.6 383.3 Current maturities of long-term debt 1.3 - 1.3 Long-term debt subject to tender 11.5 - 11.5 - ---------------------------------------------------------------------------------- Total current liabilities 677.5 20.4 697.9 - ---------------------------------------------------------------------------------- Long-term Debt-Net of Current Maturities & Debt Subject to Tender 1,014.0 - 1,014.0 Deferred Income Taxes & Other Liabilities Deferred income taxes 206.7 9.6 216.3 Deferred credits & other liabilities 108.1 1.2 109.3 - ---------------------------------------------------------------------------------- Total deferred credits & other liabilities 314.8 10.8 325.6 - ---------------------------------------------------------------------------------- Minority Interest in Subsidiary 1.4 - 1.4 Cumulative, Redeemable Preferred Stock of a Subsidiary 0.5 - 0.5 Common Shareholders' Equity Common stock (no par value) 346.1 - 346.1 Retained earnings 498.3 (9.2) 489.1 Accumulated other comprehensive income 4.2 (0.1) 4.1 - ---------------------------------------------------------------------------------- Total common shareholders' equity 848.6 (9.3) 839.3 - ---------------------------------------------------------------------------------- TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $2,856.8 $ 21.9 $ 2,878.7 ==================================================================================
4. Investments in Unconsolidated Affiliates Investments in unconsolidated affiliates where the Company has significant influence are accounted for using the equity method of accounting. The Company's share of net income or loss from these investments is recorded in equity in earnings of unconsolidated affiliates. Dividends are recorded as a reduction of the carrying value of the investment when received. Investments in unconsolidated affiliates where the Company does not have significant influence are accounted for using the cost method of accounting less write-downs for declines in value judged to be other than temporary. Dividends are recorded as other-net when received. Investments in unconsolidated affiliates consist of the following: At December 31, - ------------------------------------------------------------------------------- In millions 2002 2001 - ------------------------------------------------------------------------------- ProLiance Energy, LLC $ 61.4 $ 25.6 Haddington Energy Partnerships 19.7 26.8 Reliant Services, LLC 18.4 20.6 Utilicom Networks, LLC & related entities 15.4 14.5 Pace Carbon Synfuels, LP 6.8 7.2 Other partnerships & corporations 31.6 33.9 - ------------------------------------------------------------------------------- Total investments in unconsolidated affiliates $ 153.3 $ 128.6 =============================================================================== ProLiance Energy, LLC ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to Indiana Gas, the Ohio operations, Citizens Gas and others. ProLiance also began providing service to SIGECO and Vectren Retail, LLC (the Company's retail gas marketer) in 2002. ProLiance's primary business is optimizing the gas portfolios of utilities and providing services to large end use customers. Pre-tax income of $19.1 million, $12.8 million and $5.4 million was recognized as ProLiance's contribution to earnings for the years ended December 31, 2002, 2001, and 2000, respectively. Earnings recognized from ProLiance are included in equity in earnings of unconsolidated affiliates. Integration of SIGCORP Energy Services, LLC and ProLiance Energy, LLC In June 2002, the integration of Vectren's wholly owned subsidiary SIGCORP Energy Services, LLC (SES) with ProLiance was completed. SES provided natural gas and related services to SIGECO and others prior to the integration. In exchange for the contribution of SES' net assets totaling $19.2 million, including cash of $2.0 million, Vectren's allocable share of ProLiance's profits and losses increased from 52.5% to 61%, consistent with Vectren's new ownership percentage. In March 2001 Vectren's allocable share of profits and losses increased from 50% to 52.5% when ProLiance began managing the Ohio operations' gas portfolio. Governance and voting rights remain at 50% for each member. Since governance of ProLiance remains equal between the members, Vectren continues to account for its investment in ProLiance using the equity method of accounting. Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to June 1, 2002, SES' operating results, now part of ProLiance, are reflected in equity in earnings of unconsolidated affiliates. The transfer of net assets was accounted for at book value consistent with joint venture accounting and did not result in any gain or loss. Additionally, the non-cash component of the transfer totaling $17.2 million is excluded from the Consolidated Statement of Cash Flows. Regulatory Matters The sale of gas and provision of other services to Indiana Gas and SIGECO by ProLiance is subject to regulatory review through the quarterly gas cost adjustment (GCA) process administered by the IURC. The sale of gas and provision of other services to the Ohio operations by ProLiance is subject to regulatory review through the quarterly gas cost recovery (GCR) and audit process administered by the PUCO. Specific to the sale of gas and provision of other services to Indiana Gas by ProLiance, on September 12, 1997, the IURC issued a decision finding the gas supply and portfolio administration agreements between ProLiance and Indiana Gas and ProLiance and Citizens Gas to be consistent with the public interest and that ProLiance is not subject to regulation by the IURC as a public utility. However, with respect to the pricing of gas commodity purchased from ProLiance, the price paid by ProLiance to the utilities for the prospect of using pipeline entitlements if and when they are not required to serve the utilities' firm customers, and the pricing of fees paid by the utilities to ProLiance for portfolio administration services, the IURC concluded that additional review in the GCA process would be appropriate and directed that these matters be considered further in a consolidated GCA proceeding involving Indiana Gas and Citizens Gas. On June 4, 2002, Indiana Gas and Citizens Gas, together with the OUCC and other consumer parties, entered into and filed with the IURC a settlement setting forth the terms for resolution of all pending regulatory issues related to ProLiance, including the three pricing issues. On July 23, 2002, the IURC approved the settlement filed by the parties. The GCA proceeding has been concluded and new supply agreements between Indiana Gas, SIGECO, Citizens Gas, and ProLiance have been approved and extended through March 31, 2007. ProLiance will also have the opportunity, if it so elects, to participate in a "request for proposal" process for service to the utilities after March 31, 2007. For past services provided to Indiana Gas by ProLiance, the Company made refunds to Indiana Gas' retail customers pursuant to the settlement totaling $6.4 million and reimbursed other costs to parties involved in the settlement totaling $1.1 million. Payments were made in the fourth quarter of 2002. At December 31, 2001, the Company had established a reserve specific to this GCA proceeding totaling $5.2 million which was recorded throughout the GCA proceeding as a reduction of ProLiance's contribution to the Company's earnings. The amount of the settlement in excess of that accrued prior to 2002 totaling $2.3 million was reflected as a reduction of ProLiance's contribution to earnings in 2002. Transactions with ProLiance Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2002, 2001, and 2000 totaled $544.1 million, $610.6 million, and $478.9 million, respectively. Amounts owed to ProLiance at December 31, 2002 and 2001 for those purchases were $84.6 million and $36.1 million, respectively, and are included in accounts payable to affiliated companies in the Consolidated Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility. Summarized Financial Information For the year ended December 31, 2002, revenues, margin, operating income, and net income were (in millions) $1,534.5, $61.1, $36.5, and $37.4, respectively. For the year ended December 31, 2001, revenues, margin, operating income, and net income were (in millions) $1,599.5, $40.9, $26.1, and $27.7, respectively. For the year ended December 31, 2000, revenues, margin, operating income, and net income were (in millions) $945.8, $21.1, $10.4, and $12.1, respectively. As of December 31, 2002, current assets, noncurrent assets, current liabilities, and non current liabilities were (in millions) $301.6, $22.8, $228.8, and $1.2, respectively. As of December 31, 2001, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $206.8, $24.3, $180.8, and zero, respectively. Haddington Energy Partnerships The Company has an approximate 40% ownership interest in Haddington Energy Partners, LP (Haddington I). Haddington I raised $27.0 million to invest in energy projects. In July 2000, the Company made a commitment to fund an additional $20.0 million in Haddington Energy Partners II, LP (Haddington II), which raised a total of $47.0 million in firm commitments. Haddington II provides additional capital for Haddington I portfolio companies and made investments in new areas, such as distributed generation, power backup and quality devices, and emerging technologies such as microturbines and photovoltaics. At December 31, 2002, $11.0 million of the additional $20.0 million commitment remains. The Company has an approximate 40% ownership interest in Haddington II. Both Haddington ventures are investment companies accounted for using the equity method of accounting. For the year ended December 31, 2001, the partnerships' contribution to the Company's pre-tax earnings was $6.2 million. In 2000 and 2002, the earnings contribution was not significant. The following is summarized financial information as to the assets, liabilities, and results of operations of the Haddington Partnerships. For the year ended December 31, 2002 revenues, operating income, and net income were (in millions) zero, ($0.9), and ($0.9), respectively. For the year ended December 31, 2001 revenues, operating income, and net income were (in millions) $23.6, $22.5, and $22.5, respectively. For the year ended December 31, 2000 revenues, operating income, and net income were (in millions) zero, ($0.9), and ($0.9), respectively. As of December 31, 2002, investments, other assets, and liabilities were (in millions) $49.6, $0.3, and zero, respectively. As of December 31, 2001, investments, other assets, and liabilities were (in millions) $79.1, $5.0, and $0.2, respectively. Utilicom Networks, LLC & Related Entities Utilicom Networks, LLC (Utilicom) is a provider of bundled communication services through high capacity broadband networks, including analog and digital cable television, high-speed Internet, and advanced local and long distance phone services. The Company has a minority interest and a convertible subordinated debt investment in Utilicom. The Company also has a minority interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). The Company accounts for its investments in Utilicom and Holdings using the cost method of accounting. SIGECOM provides broadband services to the greater Evansville, Indiana, area. Utilicom also plans to provide broadband services to the greater Indianapolis, Indiana, and Dayton, Ohio, markets. However, the funding of these projects has been delayed due to the continued difficult environment within the telecommunication capital markets, which has prevented Utilicom from obtaining debt financing on terms it considers acceptable. While the existing investors are still interested in the Indianapolis and Dayton markets, the Company is not required to make further investments and does not intend to proceed unless commitments are obtained to fully fund these projects. Franchising agreements have been extended in both locations. In January 2000, the Company restructured its investment in SIGECOM. Affiliates of The Blackstone Group acquired a majority ownership interest in Utilicom. In connection with The Blackstone Group investment, the Company exchanged its 49% preferred equity interest in SIGECOM for $16.5 million of convertible subordinated debt of Utilicom and an 18.9% common equity interest in Holdings, which was valued at $6.5 million. The carrying value of the Company's 49% preferred equity interest was $15.0 million prior to the exchange. The Company received consideration in the exchange based upon an investment bank analysis of the fair value of SIGECOM at the transaction date. The investment restructuring resulted in a pre-tax gain of $8.0 million, which is classified in equity in earnings in unconsolidated affiliates in the accompanying Consolidated Statements of Income. At December 31, 2002, the Company has $30.7 million of notes receivable from Utilicom-related entities which are convertible into equity interests. Notes receivable totaling $28.6 million are convertible into Utilicom ownership at the Company's option or upon the event of a public offering of stock by Utilicom, and $2.1 million are convertible into common equity interests in the Indianapolis and Dayton ventures at the Company's option. Upon conversion, the Company would have up to a 12% interest in Utilicom, assuming completion of all required funding and up to a 31% interest in the Indianapolis and Dayton ventures. Investments in convertible notes receivable are included in other investments. At December 31, 2002 and 2001, the Company's combined investment in equity and debt securities of Utilicom-related entities totaled $46.1 million and $39.3 million, respectively. Other than the $8.0 million gain discussed above, these investments had no significant impact on the Company's financial results in 2002, 2001, or 2000. Pace Carbon Synfuels, LP Pace Carbon Synfuels, LP (Pace Carbon) is a limited partnership formed to develop, own, and operate four projects to produce and sell coal-based synthetic fuel. The Company has an 8.3% interest in Pace Carbon which is accounted for using the equity method of accounting. Additional investments in Pace Carbon will be made to the extent Pace Carbon generates Federal tax credits, with any such additional investments to be funded by these credits. The investment in Pace Carbon resulted in losses reflected in equity in earnings of unconsolidated affiliates totaling $6.8 million, $4.5 million, and $2.4 million in 2002, 2001, and 2000, respectively. The production of synthetic fuel generates IRS Code Section 29 investment tax credits that are reflected in income taxes. Net income, including the losses, tax benefits, and tax credits, generated from the investment in Pace Carbon totaled $6.0 million in 2002, $4.3 million in 2001, and $2.1 million in 2000. The following is summarized financial information as to the assets, liabilities, and results of operations of Pace Carbon. For the year ended December 31, 2002, revenues, margin, operating income, and earnings were (in millions) $125.6, ($53.1), ($72.6), and ($73.4), respectively. For the year ended December 31, 2001, revenues, margin, operating income, and earnings were (in millions) $86.2, ($25.1), ($44.1), and ($44.8), respectively. For the year ended December 31, 2000, revenues, margin, operating income, and earnings were (in millions) $35.8, ($24.3), ($33.6), and ($34.1), respectively. As of December 31, 2002, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $32.7, $44.8, $45.9 and $4.3, respectively. As of December 31, 2001, current assets, noncurrent assets, current liabilities, and noncurrent liabilities were (in millions) $22.5, $42.0, $18.2, and $8.4, respectively. Other Affiliate Transactions The Company has ownership interests in other affiliated companies accounted for using the equity method of accounting that provide materials management, underground construction and repair, facilities locating, and meter reading services to the Company. For the years ended December 31, 2002, 2001, and 2000, fees for these services and construction-related expenditures totaled $38.3 million, $37.9 million, and $20.9 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates other than ProLiance totaled $1.8 million and $2.0 million at December 31, 2002 and 2001, respectively, and are included in accounts payable to affiliated companies in the Consolidated Balance Sheets. Amounts due from unconsolidated affiliates included in accounts receivable totaled $0.6 million and $0.3 million, respectively, at December 31, 2002 and 2001. 5. Other Investments Other investments consist of the following: At December 31, - ----------------------------------------------------------------------------- In millions 2002 2001 - ----------------------------------------------------------------------------- Notes receivable: Utilicom Networks, LLC & related entities $ 30.7 $ 24.8 Other notes receivable 41.8 31.3 - ----------------------------------------------------------------------------- Total notes receivable 72.5 56.1 - ----------------------------------------------------------------------------- Leveraged leases 30.5 29.7 Other investments 21.3 14.0 - ----------------------------------------------------------------------------- Total other investments $ 124.3 $ 99.8 ============================================================================= Notes Receivable Interest rates on the above notes receivable range from fixed rates of 5% to 12% or variable rates based on prime and are due at various times through 2017. Generally, first or second mortgages and/or capital stock or partnership units serve as collateral for the notes. (See Note 4 regarding the convertibility of the Utilicom-related notes into equity interests.) Leveraged Leases The Company is a lessor in several leveraged lease agreements under which real estate or equipment is leased to third parties. The economic lives and lease terms vary with the leases. The total equipment and facilities cost was approximately $76.2 million at both December 31, 2002 and 2001. The cost of the equipment and facilities was partially financed by non-recourse debt provided by lenders, who have been granted an assignment of rentals due under the leases and a security interest in the leased property, which they accepted as their sole remedy in the event of default by the lessee. Such debt amounted to approximately $51.7 million and $54.3 million at December 31, 2002 and 2001, respectively. The Company's net investment in leveraged leases follows: At December 31, - ------------------------------------------------------------------------------ In millions 2002 2001 - ------------------------------------------------------------------------------ Minimum lease payments receivable $ 48.6 $ 48.9 Estimated residual value 22.0 22.1 Less: Unearned income 40.1 41.3 - ------------------------------------------------------------------------------ Leveraged lease investments 30.5 29.7 Less: Deferred taxes arising from leveraged leases 26.3 25.4 - ------------------------------------------------------------------------------ Net investment in leveraged leases $ 4.2 $ 4.3 ============================================================================== In June 2001, the Company sold certain leveraged lease investments with a net book value of $59.1 million at a loss of $12.4 million ($7.7 million after tax). Because of the transaction's significance and because the transaction occurred within two years of the effective date of the merger of Indiana Energy and SIGCORP, which was accounted for as a pooling-of-interests, APB 16 requires the loss on disposition of these investments to be treated as extraordinary. Proceeds from the sale totaled $46.7 million. 6. Income Taxes The components of income tax expense and utilization of investment tax credits follow: Year Ended December 31, - ------------------------------------------------------------------------------ In millions 2002 2001 2000 - ------------------------------------------------------------------------------ Current: Federal $ 62.2 $ (2.2) $ 37.1 State 5.2 3.9 2.9 - ------------------------------------------------------------------------------ Total current taxes 67.4 1.7 40.0 - ------------------------------------------------------------------------------ Deferred: Federal (26.2) 14.9 (5.5) State - (0.2) 2.1 - ------------------------------------------------------------------------------ Total deferred taxes (26.2) 14.7 (3.4) - ------------------------------------------------------------------------------ Amortization of investment tax credits (2.3) (2.3) (2.4) - ------------------------------------------------------------------------------ Total income tax expense $ 38.9 $ 14.1 $ 34.2 ============================================================================== A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, - -------------------------------------------------------------------------- 2002 2001 2000 - -------------------------------------------------------------------------- Statutory rate 35.0 % 35.0 % 35.0 % State and local taxes-net of federal benefit 1.3 3.0 3.1 Increase in state income tax rate 1.1 - - Nondeductible merger costs - - 4.0 Section 29 tax credits (7.0) (9.5) (3.3) Amortization of investment tax credit (1.5) (3.1) (2.2) Other tax credits (1.1) (3.6) (3.8) All other-net (2.4) (2.6) (0.4) - -------------------------------------------------------------------------- Effective tax rate 25.4 % 19.2 % 32.4 % ========================================================================== The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:
At December 31, - ---------------------------------------------------------------------------------------- In millions 2002 2001 - ---------------------------------------------------------------------------------------- Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 197.9 $ 215.0 Leveraged leases 26.3 25.4 Regulatory assets recoverable through future rates 37.5 33.5 Regulatory liabilities to be settled through future rates (21.7) (23.2) Employee benefit obligations (45.9) (31.3) Other - net 1.4 (3.1) - ---------------------------------------------------------------------------------------- Net noncurrent deferred tax liability 195.5 216.3 - ---------------------------------------------------------------------------------------- Current deferred tax liabilities (assets): Deferred fuel costs-net 7.7 21.1 LIFO inventory - (2.0) - ---------------------------------------------------------------------------------------- Net current deferred tax liability 7.7 19.1 - ---------------------------------------------------------------------------------------- Net deferred tax liability $ 203.2 $ 235.4 ========================================================================================
At December 31, 2002 and 2001, investment tax credits totaling $18.6 million and $20.9 million, respectively, are included in deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. The Company has no tax credit carryforwards at December 31, 2002. Alternative Minimum Tax credit carryforwards of approximately $5.2 million were utilized in 2001. Through certain of its nonregulated subsidiaries and investments, the Company also realizes federal income tax credits associated with affordable housing projects and the production of synthetic fuels. During 2001, tax credit carryforwards from these operations totaling $5.5 million were utilized. 7. Retirement Plans & Other Postretirement Benefits Effective July 1, 2000, the SIGCORP and Indiana Energy defined benefit pension plans, defined contribution retirement savings plans, and postretirement health care plans and life insurance plans for employees not covered by a collective bargaining agreement were merged. The merged plans became Vectren plans, and as a result, the respective plan assets and plan obligations were transferred to Vectren through cash payment for assets and cash receipt for obligations. These transfers resulted in no gain or loss. The defined benefit pension and other postretirement benefit plans which cover eligible full-time regular employees are primarily noncontributory. The postretirement health care and life insurance plans are a combination of self-insured and fully insured plans. The detailed disclosures of benefit components that follow are based on an actuarial valuation using a measurement date as of September 30. A summary of the components of net periodic benefit cost for the three years ended December 31, 2002 follows:
Pension Benefits Other Benefits ----------------------- ---------------------- In millions 2002 2001 2000 2002 2001 2000 - ------------------------------------ ----------------------- ---------------------- Service cost $ 5.9 $ 5.9 $ 4.3 $ 1.0 $ 1.0 $ 1.3 Interest cost 13.9 13.6 11.7 6.0 5.8 5.9 Expected return on plan assets (15.7) (16.3) (15.9) (0.7) (0.8) (0.8) Amortization of prior service cost 0.8 0.8 0.2 - - - Amortization of transitional obligation (asset) (0.5) (0.6) (0.7) 2.9 3.0 3.7 Amortization of actuarial loss (gain) 0.1 (0.9) (1.1) (0.5) (1.0) (1.5) Settlement, curtailment, & other charges (credits) - (1.4) 2.7 - (0.6) - - ---------------------------------------------------------------------------------------- Net periodic benefit cost $ 4.5 $ 1.1 $ 1.2 $ 8.7 $ 7.4 $ 8.6 ========================================================================================
To calculate the expected return on plan assets, the Company uses an expected long-term rate of return and the plan assets' market-related value. The fair market value of the assets at the measurement date is adjusted to a market-related value by recognizing the change in fair value experienced in a given year ratably over a five year period. A reconciliation of the plans' benefit obligations, fair value of plan assets, funded status, and amounts recognized in the Consolidated Balance Sheets at December 31, 2002 and 2001 follows:
Pension Benefits Other Benefits ---------------- --------------- In millions 2002 2001 2002 2001 - ---------------------------------------------- --------------- --------------- Benefit Obligation Benefit obligation at beginning of year $191.3 $167.0 $ 83.6 $ 77.4 Service cost - benefits earned during the year 5.9 5.9 1.0 1.0 Interest cost on projected benefit obligation 13.9 13.6 6.0 5.8 Plan amendments (0.1) 9.5 - - Settlements & (curtailments) - (1.5) - (0.6) Benefits paid (12.1) (13.5) (8.7) (1.7) Actuarial (gain) loss 3.0 10.3 (0.4) 1.7 - ----------------------------------------------------------------------------------- Benefit obligation at end of year $201.9 $191.3 $ 81.5 $ 83.6 =================================================================================== Fair Value of Plan Assets Plan assets at fair value at beginning of year $160.1 $193.8 $ 8.8 $ 11.2 Actual return on plan assets (10.1) (20.9) (0.5) (1.6) Employer contributions 0.7 0.7 7.8 0.9 Benefits paid (12.1) (13.5) (8.7) (1.7) - ----------------------------------------------------------------------------------- Fair value of plan assets at end of year $138.6 $160.1 $ 7.4 $ 8.8 =================================================================================== Funded status $(63.3) $(31.2) $(74.1) $(74.8) Company contributions after measurement date 0.2 - 1.5 - Unrecognized transitional obligation (asset) (0.4) (0.8) 32.0 34.9 Unrecognized service cost 11.0 12.0 - - Unrecognized net (gain) loss and other 42.2 13.4 (11.6) (13.0) - ----------------------------------------------------------------------------------- Net amount recognized $(10.3) $ (6.6) $(52.2) $(52.9) =================================================================================== Net amount recognized included in: Deferred credits & other liabilities $(15.2) $(13.0) $(52.2) $(52.9) Other assets 4.9 6.4 - -
In addition to the pension liability above, at December 31, 2002 and 2001, the Company incurred additional minimum pension liabilities totaling $30.0 million and $7.3 million, respectively, which are also included in deferred credits and other liabilities. These liabilities are offset by intangible assets totaling $10.5 and $3.5 million, respectively, which are included in other noncurrent assets, and accumulated other comprehensive income totaling $19.5 ($11.6 million after tax) and $3.8 million ($2.4 million after tax). As of December 31, 2002 and 2001, pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations of $201.9 million and $96.7 million, respectively. Those plans had accumulated benefit obligations of $179.1 million and $84.5 million, respectively. The fair value of plan assets for such pension plans as of December 31, 2002 and 2001 was $138.6 million and $73.9 million, respectively. Weighted-average assumptions used to develop annual costs and the benefit obligation for these plans are as follows: At & Year Ended December 31, - ------------------------------------------------------------------------------ Pension Benefits Other Benefits ---------------- ------------------- 2002 2001 2002 2001 - -------------------------------- ---------------- ------------------- Discount rate 6.75% 7.25% 6.75% 7.25% Expected return on plan assets before expenses 9.00% 9.00% 9.00% 9.00% Rate of compensation increase 4.25% 4.75% 4.25% 4.75% CPI rate N/A N/A 10.00% 12.00% - ------------------------------------------------------------------------------ As of December 31, 2002, the health care cost trend rate is 10% declining to 5% in 2006 and remaining level thereafter. Future changes in health care costs, work force demographics, interest rates, or plan changes could significantly affect the estimated cost of these future benefits. A 1% change in the assumed health care cost trend rate for the postretirement health care plans would have the following effects as of and for the year ended December 31, 2002: In millions 1% Increase 1% Decrease - ------------------------------------------------------------------------------- Effect on the aggregate of the service & interest cost components $ 0.5 $ (0.4) Effect on the postretirement benefit obligation 5.6 (4.7) - ------------------------------------------------------------------------------- The Company has adopted Voluntary Employee Beneficiary Association Trust Agreements for the partial funding of postretirement health benefits for retirees and their eligible dependents and beneficiaries. Annual funding is discretionary and is based on the projected cost over time of benefits to be provided to covered persons consistent with acceptable actuarial methods. To the extent these postretirement benefits are funded, the benefits are not liabilities in these consolidated financial statements. The Company also has defined contribution retirement savings plans that are qualified under sections 401(a) and 401(k) of the Internal Revenue Code. During 2002, 2001, and 2000, the Company made contributions to these plans of $3.0 million, $3.4 million, and $1.6 million, respectively. 8. Borrowing Arrangements Long-Term Debt Senior unsecured obligations and first mortgage bonds outstanding and classified as long-term by subsidiary follow: At December 31, - ------------------------------------------------------------------------------- In millions 2002 2001 - ------------------------------------------------------------------------------- VUHI Fixed Rate Senior Unsecured Notes 2011, 6.625% $ 250.0 $ 250.0 2031, 7.25% 100.0 100.0 - ------------------------------------------------------------------------------- Total VUHI 350.0 350.0 - ------------------------------------------------------------------------------- SIGECO First Mortgage Bonds Fixed Rate: 2003, Series B, 6.25%, tax exempt 1.0 1.0 2016, 1986 Series, 8.875% 13.0 13.0 2023, Series, 7.60% 45.0 45.0 2023, Series B, 6.00%, tax exempt 22.8 22.8 2025, 1993 Series, 7.625% 20.0 20.0 2029, 1999 Senior Notes, 6.72% 80.0 80.0 Adjustable Rate: 2015, Pollution Control Series A, presently 4.30%, tax exempt, next rate adjustment: 2004 10.0 10.0 2025, Pollution Control Series A, presently 4.75%, tax exempt, next rate adjustment: 2006 31.5 31.5 2024, Environmental Improvement Series A, tax exempt, adjusts every 35 days, weighted average for year: 1.80% 22.5 22.5 - ------------------------------------------------------------------------------- Total First Mortgage Bonds 245.8 245.8 - ------------------------------------------------------------------------------- Adjustable Rate Senior Unsecured Bonds 2020, Pollution Control Series B, presently 4.40%, tax exempt, next rate adjustment: 2003 4.6 4.6 2030, Pollution Control Series B, presently 4.40%, tax exempt, next rate adjustment: 2003 22.0 22.0 2030, Pollution Control Series C, presently 5.00%, tax exempt, next rate adjustment: 2006 22.2 22.2 - ------------------------------------------------------------------------------- Total Adjustable Rate Senior Unsecured Bonds 48.8 48.8 - ------------------------------------------------------------------------------- Total SIGECO 294.6 294.6 - ------------------------------------------------------------------------------- At December 31, - ------------------------------------------------------------------------------- In millions 2002 2001 - ------------------------------------------------------------------------------- Indiana Gas Fixed Rate Senior Unsecured Notes 2003, Series F, 5.75% 15.0 15.0 2004, Series F, 6.36% 15.0 15.0 2007, Series E, 6.54% 6.5 6.5 2013, Series E, 6.69% 5.0 5.0 2015, Series E, 7.15% 5.0 5.0 2015, Insured Quarterly, 7.15% 20.0 20.0 2015, Series E, 6.69% 5.0 5.0 2015, Series E, 6.69% 10.0 10.0 2021, Private Placement, 9.375%, $1.3 due annually in 2002 23.8 25.0 2025, Series E, 6.31% - 5.0 2025, Series E, 6.53% 10.0 10.0 2027, Series E, 6.42% 5.0 5.0 2027, Series E, 6.68% 3.5 3.5 2027, Series F, 6.34% 20.0 20.0 2028, Series F, 6.75% 13.6 13.8 2028, Series F, 6.36% 10.0 10.0 2028, Series F, 6.55% 20.0 20.0 2029, Series G, 7.08% 30.0 30.0 2030, Insured Quarterly, 7.45% 49.9 50.0 - ------------------------------------------------------------------------------- Total Indiana Gas 267.3 273.8 - ------------------------------------------------------------------------------- Vectren Capital Corp. Private Placement Fixed Rate Senior Unsecured Notes 2005, 7.67% 38.0 38.0 2007, 7.83% 17.5 17.5 2010, 7.98% 22.5 22.5 2012, 7.43% 35.0 35.0 - ------------------------------------------------------------------------------- Total Vectren Capital Corp. 113.0 113.0 - ------------------------------------------------------------------------------- Total long-term debt outstanding 1,024.9 1,031.4 Less: Current maturities of long-term debt 39.8 1.3 Debt subject to tender 26.6 11.5 Unamortized debt premium & discount - net 4.3 4.6 - ------------------------------------------------------------------------------- Total long-term debt-net $ 954.2 $1,014.0 =============================================================================== VUHI In September 2001, VUHI filed a shelf registration statement with the Securities and Exchange Commission for $350.0 million aggregate principal amount of unsecured senior notes. In October 2001, VUHI issued senior unsecured notes with an aggregate principal amount of $100.0 million and an interest rate of 7.25% (the October Notes), and in December 2001, issued the remaining aggregate principal amount of $250.0 million at an interest rate of 6.625% (the December Notes). The December Notes were priced at 99.302% to yield 6.69% to maturity. These issues have no sinking fund requirements, and interest payments are due quarterly for the October Notes and semi-annually for the December Notes. The October Notes are due October 2031, but may be called by the Company, in whole or in part, at any time after October 2006 at 100% of the principal amount plus any accrued interest thereon. The December Notes are due December 2011, but may be called by the Company, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 25 basis points. The net proceeds from the sale of the senior notes and settlement of the hedging arrangements (see Note 16) totaled $344.0 million. Vectren Capital Corp. In December 2000, Vectren Capital Corp (Cap Corp), a wholly owned consolidated subsidiary that provides financing for the Company's nonregulated operations and investments, issued $78.0 million of private placement unsecured senior notes to three institutional investors. The issues and terms are $38.0 million at 7.67%, due December 2005; $17.5 million at 7.83%, due December 2007; and $22.5 million at 7.98%, due December 2010. The issues have no sinking fund requirements. The net proceeds totaled $77.4 million. Indiana Gas In December 2000, $20.0 million of 15-Year Insured Quarterly (IQ) Notes at an interest rate of 7.15% and $50.0 million of 30-Year IQ Notes at an interest rate of 7.45% were issued. Indiana Gas may call the 15-Year IQ Notes, in whole or in part, from time to time on or after December 15, 2004 and has the option to redeem the 30-Year IQ Notes in whole or in part, from time to time on or after December 15, 2005. The IQ notes have no sinking fund requirements. The net proceeds totaled $67.9 million. Both the quarterly interest payments and the principal amount of the IQ Notes are insured by Ambac Assurance Corporation. Long-Term Debt Put & Call Provisions On January 15, 2003, the Company called the remaining $23.8 million of Indiana Gas' 9.375% private placement notes originally due in 2021. Since the proceeds to repay the notes were generated from short-term borrowings, these notes are classified in current maturities of long-term debt at December 31, 2002. Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. Other than those described below related to ratings triggers, the put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements, such as when notes are re-marketed. Debt which may be put to the Company during the years following 2002 (in millions) is $26.6 in 2003, $13.5 in 2004, $10.0 in 2005, $53.7 in 2006, $20.0 in 2007, and $120.0 thereafter. Debt that may be put to the Company within one year is classified as debt subject to tender in current liabilities. Long-Term Debt Sinking Fund Requirements & Maturities The annual sinking fund requirement of SIGECO's first mortgage bonds is 1% of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2002 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2002 is excluded from current liabilities in the Consolidated Balance Sheets. At December 31, 2002, $342.8 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. Consolidated maturities and sinking fund requirements on long-term debt, including debt to be called, during the five years following 2002 (in millions) are $39.8 in 2003, $15.0 in 2004, $38.0 in 2005, zero in 2006, and $24.0 in 2007. Short-Term Borrowings At December 31, 2002, the Company has $510.0 million of short-term borrowing capacity, including $330.0 million for its regulated operations and $180.0 million for its wholly owned nonregulated and corporate operations, of which approximately $90.9 million is available for regulated operations and $17.0 million is available for wholly owned nonregulated and corporate operations. The availability of short-term borrowing is reduced by outstanding letters of credit totaling $5.2 million, collateralizing nonregulated activities. Subsequent to December 31, 2002, the Company increased its regulated capacity $145.0 million to $475.0 million. See the table below for interest rates and outstanding balances. Year ended December 31, - ------------------------------------------------------------------------------- In millions 2002 2001 2000 - ------------------------------------------------------------------------------- Weighted average commercial paper and bank loans outstanding during the year $ 288.8 $ 447.0 $ 316.7 Weighted average interest rates during the year Bank loans 2.52% 6.77% 6.98% Commercial paper 2.02% 4.39% 6.53% At December 31, - --------------------------------------------------------------------- In millions 2002 2001 - --------------------------------------------------------------------- Bank loans $ 157.8 $ 107.2 Commercial paper 239.1 273.3 Other 2.6 2.8 - --------------------------------------------------------------------- Total short-term borrowings $ 399.5 $ 383.3 ===================================================================== Covenants Both long-term and short-term borrowing arrangements contain customary default provisions, restrictions on liens, sale leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2002, the Company was in compliance with all financial covenants. Ratings Triggers Cap Corp's $113.0 million senior unsecured notes are subject to ratings trigger provisions that would provide that the full balance outstanding is subject to prepayment if the ratings of Indiana Gas or SIGECO declined to BBB/Baa2. In addition, accrued interest and a make whole amount based on the discounted value of the remaining payments due on the notes would also become payable. Ratings triggers on Cap Corp's bank loans and VUHI's commercial paper back up facility existing at December 31, 2001 were removed as facilities were renewed during 2002. Effective January 1, 2003, the Company transferred certain assets that primarily support the regulated operations from other wholly owned subsidiaries to VUHI. This transfer of assets will take advantage of greater borrowing capacity available to the regulated segment and will make the nonregulated and corporate capacity available to support those operations. The Company is currently exploring expanding unutilized capacity under its nonregulated short-term borrowing facilities for additional liquidity protection. Debt Guarantees Vectren Corporation guarantees Cap Corp's long-term and short-term debt, which totaled $113.0 million and $157.8 million, respectively, at December 31, 2002. VUHI's currently outstanding long-term and short-term debt is jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. VUHI's long-term and short-term debt outstanding at December 31, 2002 totaled $350.0 million and $239.1 million, respectively. 9. Cumulative Preferred Stock of Subsidiary Redemption of Preferred Stock of a Subsidiary Nonredeemable preferred stock of a subsidiary containing call options was redeemed during September 2001 for a total redemption price of $9.8 million. The 4.80%, $100 par value preferred stock was redeemed at its stated call price of $110 per share, plus accrued and unpaid dividends totaling $1.35 per share. The 4.75%, $100 par value preferred stock was redeemed at its stated call price of $101 per share, plus accrued and unpaid dividends totaling $0.97 per share. Prior to the redemptions, there were 85,519 shares of the 4.80% Series outstanding and 3,000 shares of the 4.75% Series outstanding. In September 2001, the 6.50%, $100 par value of redeemable preferred stock of a subsidiary was redeemed for a total redemption price of $7.9 million at $104.23 per share, plus $0.73 per share in accrued and unpaid dividends. Prior to the redemption, there were 75,000 shares outstanding. As both series of preferred stock redeemed was that of a subsidiary, the loss on redemption of $1.2 million in 2001 is reflected in retained earnings. Redeemable, Special This series of redeemable preferred stock has a dividend rate of 8.50% and in the event of involuntary liquidation the amount payable is $100 per share, plus accrued dividends. This series may be redeemed at $100 per share, plus accrued dividends on any of its dividend payment dates and is also callable at the Company's option at a rate of 1,160 shares per year. As of December 31, 2002 and 2001, there were 3,437 shares and 4,597 shares outstanding, respectively. 10. Common Shareholders' Equity In March 2000, the merger of Indiana Energy and SIGCORP with and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling of interests. The common shareholders of SIGCORP received 1.333 shares of Vectren common stock for each SIGCORP common share and the common shareholders of Indiana Energy received one share of Vectren common stock for each Indiana Energy common share, resulting in the issuance of 61.3 million shares of Vectren common stock. In January 2001, the Company filed a registration statement with the Securities and Exchange Commission with respect to a public offering of 5.5 million shares of new common stock. In February 2001, the registration became effective, and an agreement was reached to sell approximately 6.3 million shares (the original 5.5 million shares, plus an over-allotment option of 0.8 million shares) to a group of underwriters. The net proceeds totaled 129.4 million. Authorized, Reserved Common and Preferred Shares At December 31, 2002 and 2001 the Company was authorized to issue 480.0 million shares of common stock and 20.0 million shares of preferred stock. Of the authorized common shares, approximately 7.3 million shares at December 31, 2002 and 7.5 million shares at December 31, 2001 were reserved by the Board of Directors for issuance through the Company's stock-based incentive plans and benefit plans. At both December 31, 2002 and 2001 there were 404.8 million authorized shares of common stock and all authorized preferred stock available for a variety of general corporate purposes, including future public offerings to raise additional capital and for facilitating acquisitions. Shareholder Rights Agreement The Company's board of directors has adopted a Shareholder Rights Agreement (Rights Agreement). As part of the Rights Agreement, the board of directors declared a dividend distribution of one right for each outstanding Vectren common share. Each right entitles the holder to purchase from Vectren one share of common stock at a price of $65.00 per share (subject to adjustment to prevent dilution). The rights become exercisable 10 days following a public announcement that a person or group of affiliated or associated persons (Vectren Acquiring Person) has acquired beneficial ownership of 15% or more of the outstanding Vectren common shares (or a 10% acquirer who is determined by the board of directors to be an adverse person), or 10 days following the announcement of an intention to make a tender offer or exchange offer the consummation of which would result in any person or group becoming a Vectren Acquiring Person. The Vectren Shareholder Rights Agreement expires October 21, 2009. 11. Earnings Per Share Basic earnings per share is computed by dividing net income available to common shareholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share assumes the conversion of stock options into common shares and the lifting of restrictions on issued restricted shares using the treasury stock method to the extent the effect would be dilutive. The following table illustrates the basic and dilutive earnings per share calculations for the three years ended December 31, 2002:
2002 2001 2000 ---------------------- ---------------------- ---------------------- Per Per Per In millions, except Share Share Share per share amounts Income Shares Amount Income Shares Amount Income Shares Amount - ------------------- ------ ------ ------ ------ ------ ------ ------ ------ ------ Basic EPS $114.0 67.6 $ 1.69 $52.7 66.7 $0.79 $72.0 61.3 $ 1.18 Effect of dilutive stock equivalents 0.3 0.2 0.1 - -------------------------------------------------------------------------------------------- Diluted EPS $114.0 67.9 $ 1.68 $52.7 66.9 $0.79 $72.0 61.4 $ 1.17 ============================================================================================
Options to purchase 87,963 shares of common stock for the year ended December 31, 2002, 836,688 shares of common stock for the year ended December 31, 2001, and 526,469 shares of common stock for the year ended December 31, 2000 were not included in the computation of dilutive earnings per share because the options' exercise price was greater than the average market price of a share of common stock during the period. Exercise prices for options excluded from the computation ranged from $24.05 to $25.59 in 2002; $22.54 to $24.05 in 2001; and $19.83 to $24.05 in 2000. 12. Stock-Based Incentive Plans The Company has various stock-based incentive plans to encourage employees and non-employee directors to remain with the Company and to more closely align their interest with those of the Company's shareholders. Stock Option Plans A summary of the status of the Company's stock option plans for the past three years follows: Wtd. Avg. Exercise Options Price - ------------------------------------------------------------------------- Outstanding at January 1, 2000 931,004 $ 18.33 Cancelled (30,955) 19.04 Exercised (40,608) 15.92 - -------------------------------------------------------------------------- Outstanding at December 31, 2000 859,441 18.41 Granted 783,999 22.54 Cancelled (92,953) 21.84 Exercised (122,709) 16.05 - ------------------------------------------------------------------------- Outstanding at December 31, 2001 1,427,778 20.67 Granted 71,374 23.51 Cancelled (3,000) 22.54 Exercised (146,890) 14.51 - -------------------------------------------------------------------------- Outstanding at December 31, 2002 1,349,262 21.48 ========================================================================== In January 2003, 384,500 options to purchase shares of common stock at an exercise price of $23.19 were issued to management. The grant vests over three years. Certain SIGCORP employees held options to purchase SIGCORP common shares. When the merger of SIGCORP and Indiana Energy was consummated, each granted and outstanding option to purchase SIGCORP common shares was converted into an option to purchase the number of Vectren common shares that could have been purchased under the original option multiplied by one and one-third. The exercise price per Vectren common share under the new option is equal to the original per share price divided by one and one-third. The new Vectren options are otherwise subject to the same terms and conditions as the original SIGCORP options. Accordingly, the conversion resulted in no compensation expense. Stock options granted in 2001 and 2002 become fully vested and exercisable at the end of five years for stock options issued to employees and one year for non-employee directors. Stock options granted prior to 2001 generally vest and become exercisable between one and three years in equal annual installments beginning one year after the grant date and are all vested as of December 31, 2002. Options granted both before and after 2001 generally expire ten years from the date of grant. The fair value of each option granted used to determine pro forma net income as disclosed in Note 2, is estimated as of the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in the years ended December 31, 2002 and 2001: risk-free rate of return of 3.80% and 5.65%, respectively; expected option term of 8 years for both years; expected volatility of 26.44% and 26.56%, respectively; and dividend yield of 4.65% and 4.42%, respectively. The weighted average fair value of options granted in 2002 and 2001 were $4.33 and $5.21, respectively. No options were granted in 2000. The following table summarizes information about stock options outstanding and exercisable at December 31, 2002: Outstanding Exercisable ---------------------------------------- --------------------- Wtd. Avg. Wtd. Avg. Wtd. Avg. Range of Remaining Exercise Exercise Exercise Prices # of Options Contractual Life Price # of Options Price - ----------------------------------------------------- ------------------------- $13.82 - $17.44 109,934 2.5 $ 15.46 109,934 $ 15.46 $19.83 - $20.26 336,266 5.8 20.09 336,266 20.09 $22.54 - $25.59 903,062 8.2 22.73 246,088 22.94 - ------------------------------------------------------------------------------- Total 1,349,262 7.1 21.48 692,288 20.37 ==============================================================================- As of December 31, 2001 and 2000, stock options that are exercisable and those options' weighted average exercise prices are 658,221 and $18.47 in 2001; and 781,415 and $18.41 in 2000. Other Plans Indiana Energy had a performance-based Executive Restricted Stock Plan for its principal officers and a Directors' Restricted Stock Plan through which non-employee directors received a portion of their director fees. Upon consummation of the merger, the restrictions on each outstanding share of restricted stock lapsed, and all shares that were issued as restricted stock were treated as unrestricted shares in the merger exchange. In 2000, the Company adopted these plans. A summary of outstanding restricted stock issued through these plans since the merger and through December 31, 2002 follows: - ------------------------------------------------------------------------ Grants in & outstanding at December 31, 2000 194,884 - ------------------------------------------------------------------------ Grants 4,257 Forfeitures (19,726) Vested (1,302) - ------------------------------------------------------------------------ Outstanding at December 31, 2001 178,113 - ------------------------------------------------------------------------ Grants 66,831 Vested (4,257) - ------------------------------------------------------------------------ Outstanding at December 31, 2002 240,687 ======================================================================== For the years ended December 31, 2002, 2001, and 2000, the weighted average fair value per share of restricted stock granted was $23.10, $22.54, and $19.90, respectively. In January 2003, 93,000 restricted shares with a fair value per share of $23.19 were issued to management. Those shares vest in 2006. Executives and non-employee directors may defer certain portions of their salary, annual bonus, incentive compensation, and earned stock-based incentives into phantom stock units. Such units are vested when granted. Compensation expense associated with the restricted stock and phantom stock plans for the years ended December 31, 2002, 2001, and 2000 was $2.1 million, $2.8 million, and $2.9 million, respectively. Approximately $2.3 million of compensation expense for the year ended December 31, 2000 is for the lifting of restrictions triggered by the merger transaction. 13. Commitments & Contingencies Commitments Future minimum lease payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year during the five years following 2002 and thereafter (in millions) are $6.8 in 2003, $6.3 in 2004, $5.0 in 2005, $4.5 in 2006, $4.0 in 2007, and $4.7 thereafter. Total lease expense (in millions) was $7.3 in 2002, $6.2 in 2001, and $3.4 in 2000. Firm commitments to purchase natural gas for years following December 31, 2002 totaled (in millions) $89.5 in 2003, $21.3 in 2004, and $3.6 million in 2005. Other Guarantees The Company is party to financial guarantees with off-balance sheet risk. These guarantees may include posted letters of credit, debt and leasing guarantees, performance guarantees, and energy saving guarantees and may periodically include the debt of and performance obligations of unconsolidated affiliates. The Company estimates these guarantees totaled approximately $117 million at December 31, 2002, including outstanding letters of credit discussed in Note 8. The Company's most significant guarantee approximating $60 million represents two-thirds of Energy Systems Group, LLC's (ESG) surety bonds, performance guarantees, and energy savings guarantees. ESG is a two-thirds owned consolidated subsidiary. The guarantees relate to amounts due to various insurance companies for surety bonds should ESG default on obligations to complete construction, pay vendors or subcontractors, or to achieve energy guarantees. Through December 31, 2002, the Company has not been called upon to satisfy any obligations pursuant to the guarantees. Legal Proceedings The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 14 regarding the Clean Air Act. 14. Environmental Matters Clean Air Act NOx SIP Call Matter The Clean Air Act (the Act) requires each state to adopt a State Implementation Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS) for a number of pollutants, including ozone. If the USEPA finds a state's SIP inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its SIP (a SIP Call). In October 1998, the USEPA issued a final rule "Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed. Reg. 57355). This ruling found that the SIP's of certain states, including Indiana, were substantially inadequate since they allowed for nitrogen oxide (NOx) emissions in amounts that contributed to non-attainment with the ozone NAAQS in downwind states. The USEPA required each state to revise its SIP to provide for further NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx emissions from Indiana. In June 2001, the Indiana Air Pollution Control Board adopted final rules to achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by May 31, 2004 (the compliance date). This is a 65% reduction from emission levels existing in 1999 and 1998. The Company has initiated steps toward compliance with the revised regulations. These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to be the most effective method of reducing NOx emissions where high removal efficiencies are required. On August 28, 2001, the IURC issued an order that (1) approved the Company's proposed project to achieve environmental compliance by investing in clean coal technology, (2) approved the Company's initial cost estimate of $198 million for the construction, subject to periodic review of the actual costs incurred, and (3) approved a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months a return on its capital costs for the project, at its overall cost of capital, including a return on equity. The first rider adjustment for ongoing cost recovery was approved by the IURC on February 6, 2002. Based on the level of system-wide emissions reductions required and the control technology utilized to achieve the reductions, the current estimated clean coal technology construction cost ranges from $240 million to $250 million and is expected to be expended during the 2001-2006 period. Through December 31, 2002, $70.0 million has been expended. On June 5, 2002, the Company filed a new proceeding to update the NOx project cost and to obtain approval of a second rider authorizing ongoing recovery of depreciation and operating costs related to the clean coal technology. After the equipment is installed and operational, related annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million. Such expenses would commence in 2004 when the technology becomes operational. On January 3, 2003, the IURC approved a settlement that authorizes total capital cost investment for this project up to $244 million (excluding AFUDC) and recovery on those capital costs, as well as the recovery of future operating costs, including depreciation and purchased emission allowances, through a rider mechanism. The settlement establishes a fixed return of 8 percent on the capital investment, which approximates the return authorized in the Company's last electric rate case in 1995. The Company expects to achieve timely compliance as a result of the project. Construction of the first SCR at Culley is nearing completion on schedule, and installation of SCR technology as planned is expected to reduce the Company's overall NOx emissions to levels compliant with Indiana's NOx emissions budget allotted by the USEPA. Therefore, the Company has recorded no accrual for potential penalties that may result from noncompliance. Culley Generating Station Litigation In the late 1990's, the USEPA initiated an investigation under Section 114 of the Act of SIGECO's coal-fired electric generating units in commercial operation by 1977 to determine compliance with environmental permitting requirements related to repairs, maintenance, modifications, and operations changes. The focus of the investigation was to determine whether new source review permitting requirements were triggered by such plant modifications, and whether the best available control technology was, or should have been used. Numerous electric utilities were, and are currently, being investigated by the USEPA under an industry-wide review for compliance. In July 1999, SIGECO received a letter from the Office of Enforcement and Compliance Assurance of the USEPA discussing the industry-wide investigation, vaguely referring to an investigation of SIGECO and inviting SIGECO to participate in a discussion of the issues. No specifics were noted; furthermore, the letter stated that the communication was not intended to serve as a notice of violation. Subsequent meetings were conducted in September and October 1999 with the USEPA and targeted utilities, including SIGECO, regarding potential remedies to the USEPA's general allegations. On November 3, 1999, the USEPA filed a lawsuit against seven utilities, including SIGECO. SIGECO's suit is pending in the U.S. District Court for the Southern District of Indiana. The USEPA alleges that, beginning in 1992, SIGECO violated the Act by (1) making modifications to its Culley Generating Station in Yankeetown, Indiana without obtaining required permits (2) making major modifications to the Culley Generating Station without installing the best available emission control technology and (3) failing to notify the USEPA of the modifications. In addition, the lawsuit alleges that the modifications to the Culley Generating Station required SIGECO to begin complying with federal new source performance standards at its Culley Unit 3. SIGECO believes it performed only maintenance, repair, and replacement activities at the Culley Generating Station, as allowed under the Act. Because proper maintenance does not require permits, application of the best available control technology, notice to the USEPA, or compliance with new source performance standards, SIGECO believes that the lawsuit is without merit, and intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA has voluntarily dismissed a majority of the claims brought in its original complaint. In its original complaint, USEPA alleged significant emissions increases of three pollutants for each of four maintenance projects. Currently, USEPA is alleging only significant emission increases of a single pollutant at three of the four maintenance projects cited in the original complaint. The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per violation. However, on July 29, 2002, the Court ruled that USEPA could not seek civil penalties for two of the three remaining projects at issue in the litigation, significantly reducing potential civil penalty exposure. The lawsuit also seeks a court order requiring SIGECO to install the best available emissions technology at the Culley Generating Station. If the USEPA were successful in obtaining an order, SIGECO estimates that in response it could incur capital costs of approximately $20 million to $40 million to comply with the order. Trial is currently set to begin July 14, 2003. The USEPA has also issued an administrative notice of violation to SIGECO making the same allegations, but alleging that violations began in 1977. While it is possible that SIGECO could be subjected to criminal penalties if the Culley Generating Station continues to operate without complying with the permitting requirements of new source review and the allegations are determined by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA and the electric utility industry have a bonafide dispute over the proper interpretation of the Act. Accordingly, the Company has recorded no accrual and the plant continues to operate while the matter is being decided. Information Request On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested, and no further action has occurred. Manufactured Gas Plants In the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites. Indiana Gas has identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program and is currently conducting some level of remedial activities including groundwater monitoring at certain sites where deemed appropriate and will continue remedial activities at the sites as appropriate and necessary. In conjunction with data compiled by environmental consultants, Indiana Gas has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million. The estimated accrued costs are limited to Indiana Gas' proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas' share of response costs at these 19 sites to between 20% and 50%. With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million. Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen. In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled the IDEM's Voluntary Remediation Program. In response SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990's. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have recently been initiated by the Company to confirm that the sites continue to pose no such risk. 15. Rate & Regulatory Matters Gas Costs Proceedings Commodity prices for natural gas purchases were significantly higher during the 2000 - 2001 heating season, primarily due to colder temperatures, increased demand and tighter supplies. Subject to compliance with applicable state laws, Vectren's utility subsidiaries are allowed full recovery of such changes in purchased gas costs from their retail customers through commission-approved gas cost adjustment mechanisms. In March 2001, Indiana Gas and SIGECO reached agreement with the OUCC and the Citizens Action Coalition of Indiana, Inc. (CAC) regarding the matters raised by an IURC Order that disallowed $3.8 million of Indiana Gas' gas procurement costs for the 2000 - 2001 heating season which was recognized during the year ended December 31, 2000. As part of the agreement, the companies agreed to contribute an additional $1.7 million to assist qualified low income gas customers, and Indiana Gas agreed to credit $3.3 million of the $3.8 million disallowed amount to its customers' April 2001 utility bills in exchange for both the OUCC and the CAC dropping their appeals of the IURC Order. In April 2001, the IURC issued an order approving the settlement. Substantially all of the financial assistance for low income gas customers was distributed in 2001. Purchased Power Costs As a result of an appeal of a generic order issued by the IURC in August 1999 regarding guidelines for the recovery of purchased power costs, SIGECO entered into a settlement agreement with the OUCC that provides certain terms with respect to the recoverability of such costs. The settlement, originally approved by the IURC in August 2000, has been extended by agreement through March 2003, and discussions regarding further extension of the settlement term are ongoing. Under the settlement, SIGECO can recover the entire cost of purchased power up to an established benchmark, and during forced outages, SIGECO will bear a limited share of its purchased power costs regardless of the market costs at that time. Based on this agreement, SIGECO believes it has limited its exposure to unrecoverable purchased power costs. 16. Risk Management, Derivatives, & Other Financial Instruments The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit. These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program. The Company's risk management program includes, among other things, the use of derivatives to mitigate risk. The Company also executes derivative contracts in the normal course of operations while buying and selling commodities and other fungible goods to be used in operations and while optimizing generation assets. The Company does not execute derivative contracts for speculative or trading purposes. Commodity Price Risk The Company's regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations, which subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Electric sales and purchases in the wholesale power market and other commodity-related operations are exposed to commodity price risk associated with fluctuating electric power, natural gas, coal, and other commodity prices. Other commodity operations include sales of electricity to certain municipalities and large industrial customers and nonregulated retail gas marketing and coal mining operations. The Company's non-firm wholesale power marketing operations manage the utilization of its available electric generating capacity by entering into forward and option contracts that commit the Company to purchase and sell electricity in the future. Commodity price risk results from forward positions that commit the Company to deliver electricity. The Company mitigates price risk exposure with planned unutilized generation capability and offsetting forward purchase contracts. The Company's other commodity-related operations involve the purchase and sale of commodities, including electricity, natural gas, and coal, to meet customer demands and operational needs. These operations also enter into forward and option contracts that commit the Company to purchase and sell commodities in the future. Price risk from forward positions that commit the Company to deliver commodities is mitigated using stored inventory, insurance contracts, and offsetting forward purchase contracts. In addition, price risk also results from forward contracts to purchase commodities to fulfill forecasted sales transactions that may, or may not, occur. Open positions in terms of price, volume, and specified delivery points may occur and are managed using methods described above and frequent management reporting. Interest Rate Risk The Company is exposed to interest rate risk associated with its adjustable rate borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on operations. The Company tries to limit the amount of adjustable rate borrowing arrangements exposed to short-term interest rate volatility to a maximum of 25% of total debt. However, there are times when this targeted level of interest rate exposure may be exceeded. To manage this exposure, the Company may periodically use derivative financial instruments to reduce earnings fluctuations caused by interest rate volatility. Other Risks By using forward purchase contracts and derivative financial instruments to manage risk, the Company exposes itself to counter-party credit risk and market risk. The Company manages exposure to counter-party credit risk by entering into contracts with companies that can be reasonably expected to fully perform under the terms of the contract. Counter-party credit risk is monitored regularly and positions are adjusted appropriately to manage risk. Further, tools such as netting arrangements and requests for collateral are also used to manage credit risk. Market risk is the adverse effect on the value of a financial instrument that results from a change in commodity prices or interest rates. The Company attempts to manage exposure to market risk associated with commodity contracts and interest rates by establishing parameters and monitoring those parameters that limit the types and degree of market risk that may be undertaken. The Company's customer receivables from gas and electric sales and gas transportation services are primarily derived from a diversified base of residential, commercial, and industrial customers located in Indiana and west central Ohio. The Company manages credit risk associated with its receivables by continually reviewing creditworthiness and requests cash deposits or refunds cash deposits based on that review. Credit risk associated with certain investments is also managed by a review of creditworthiness and receipt of collateral. Although the Company's regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements; increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas; and some level of price sensitive reduction in volumes sold. Accounting for Derivatives & Other Contracts When a derivative contract that is entered into in the normal course of operations is probable of physical settlement, that contract is designated and documented as a normal purchase or normal sale and is exempted from mark-to-market accounting. Otherwise, derivative contracts are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. Unless the contract is a cash flow hedge that qualifies for hedge accounting treatment or is subject to SFAS 71, that contract is marked to market through earnings. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between its financial instruments, including commodity contracts and interest rate swaps, and underlying risks as well as the investment's risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges. The ineffective portion of hedging arrangements is marked to market through earnings. Contracts affected by SFAS 71 are marked to market as a regulatory asset or liability. Market value is determined using quoted market prices from independent sources. Non-Firm Wholesale Power Marketing Contracts Periodically, generation capacity is in excess of that needed to serve retail and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. The contracts entered into are primarily short-term purchase and sale contracts that expose the Company to limited market risk and are settled both financially and physically. These operations do not meet the definition of energy trading activities based upon the provisions in EITF Issue 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). Asset optimization sale contracts are reflected in electric utility revenues, and purchase contracts are reflected in purchased electric energy. Contracts with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. Subsequent to the adoption of SFAS 133 as described below, certain non-firm power marketing contracts that are periodically financially settled are recorded at market value. Changes in market value, which is a function of the normal decline in market value as earnings are realized and the fluctuation in market value resulting from price volatility, are recorded in purchased electric energy. Power marketing contracts recorded at market value at December 31, 2002 totaled $3.5 million of prepayments and other current assets and $4.2 million of accrued liabilities, compared to $6.1 million of prepayments and other current assets and $2.8 million of accrued liabilities at December 31, 2001. The change in the net value of these contracts includes an unrealized loss of $3.6 million in 2002 and an unrealized gain of $1.5 million in 2001, respectively. Including these unrealized changes in market value, overall margin (revenue net of purchased power) from non-firm wholesale power marketing operations for the years ended December 31, 2002 and 2001 was $14.9 million and $19.9 million, respectively. Prior to the adoption of SFAS 133 and for the year ended December 31, 2000, margin was $21.1 million. Financial Contracts In September 2001, the Company entered into several forward starting interest rate swaps with a total notional amount of $200.0 million in anticipation of VUHI's $250.0 million long-term debt issuance. Upon issuance of the debt in December 2001, the swaps were settled resulting in the Company receiving $0.9 million. The value received is being amortized from accumulated other comprehensive income to interest expense over the life of the debt. In December 2000, the Company entered into an interest rate swap used to hedge interest rate risk associated with variable rate short-term notes payable totaling $150.0 million. The swap was entered into concurrently with the issuance of the floating rate notes on December 28, 2000 and swapped the debt's variable interest rate of three-month LIBOR plus 0.75% for a fixed rate of 6.64%. The swap expired on December 27, 2001, the date the debt agreement expired. Prior to the adoption of SFAS 133, instruments hedging interest rate risk were accounted for upon settlement in interest expense. After adoption of SFAS 133, hedging instruments are carried at market value, and changes in market value are recorded in accumulated other comprehensive income, when effective, and are recorded to interest expense as settled. As of December 31, 2002 and 2001, no interest rate swaps are outstanding. At December 31, 2002, approximately $0.8 million remains in accumulated other comprehensive income related to future interest payments. Of that amount, $0.1 million will be reclassified to earnings in 2003 and $0.1 million was reclassified to earnings during 2002. Other Commodity-Related Operations Other commodity contracts are generally settled by physical delivery or receipt and are within the normal operations of the Company. Contracts entered into that are probable of physical delivery or receipt receive accounting recognition upon settlement. Firm wholesale electric contracts are recorded in electric utility revenues. Contracts recorded by nonregulated operations related to the delivery or receipt of natural gas or coal are included in energy services and other revenues or cost of energy services and other revenues, as appropriate. Certain contracts that purchase commodities for operational needs are recorded when settled in other operating expenses. The Company enters into other derivative contracts to hedge certain physical natural gas positions used in nonregulated operations that are not probable of physical delivery or receipt. Prior to the adoption of SFAS 133, instruments hedging commodity price risk were accounted for upon settlement in cost of energy services and other. After adoption of SFAS 133, hedging instruments are carried at market value, and changes in market value are recorded in accumulated other comprehensive income, when effective, and recorded to cost of energy services and other when the underlying transaction occurs. Occasionally, contracts required to be recorded at market value do not qualify for hedge accounting and are required to be marked to market directly to cost of energy services and other. For the years ended December 31, 2002 and 2001, derivative instruments involving the purchase and sale of other commodities that were not subject to the "normal" exception as described in SFAS 133 had no significant impact on the Company's results or financial condition. Impact of Adoption of SFAS 133 In June 1998, the FASB issued SFAS 133, which required that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its market value and that changes in the derivative's market value be recognized currently in earnings unless specific hedge or regulatory accounting criteria are met. SFAS 133, as amended, required that as of the date of initial adoption, the difference between the market value of derivative instruments recorded on the balance sheet and the previous carrying amount of those derivatives be reported in net income, other comprehensive income, or regulatory assets or liabilities, as appropriate. A change in earnings or other comprehensive income was reported as a cumulative effect of a change in accounting principle in accordance with APB Opinion No. 20, "Accounting Changes." Resulting from the adoption of SFAS 133, certain non-firm wholesale power marketing contracts and other commodity contracts that are periodically settled net were required to be recorded at market value. Previously, the Company accounted for these contracts on settlement. The cumulative impact of the adoption of SFAS 133 resulting from marking these contracts to market on January 1, 2001 was an earnings gain of approximately $1.8 million ($1.1 million net of tax) recorded as a cumulative effect of accounting change. The majority of this gain results from the Company's non-firm wholesale power marketing operations. SFAS 133 did not impact other commodity contracts because they were normal purchases and sales specifically excluded from the provisions of SFAS 133 and did not impact the Company's cash flow hedges because they had no value on the date of adoption. Fair Value of Other Financial Instruments The carrying values and estimated fair values of the Company's other financial instruments follow:
At December 31, - ------------------------------------------------------------------------------------ 2002 2001 ------------------- ------------------- Carrying Est. Fair Carrying Est. Fair In millions Amount Value Amount Value - ---------------------------------------- ------------------- ------------------- Long-term debt $1,024.9 $1,095.3 $ 1,031.4 $ 1,022.4 Short-term borrowings & notes payable 399.5 399.5 383.3 383.3
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's other financial instruments was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value. Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's financial position or results of operations. Periodically, the Company tests its cost method investments and notes receivable for impairment, which may require their fair value to be estimated. Because of the customized nature of these investments and lack of a readily available market, it is not practicable to estimate the fair value of these financial instruments at specific dates without considerable effort and costs. At December 31, 2002 and 2001, fair value for these financial instruments has not been estimated. 17. Additional Operational & Balance Sheet Information Other - net in the Consolidated Statements of Income consists of the following: Year ended December 31, - -------------------------------------------------------------------------- In millions 2002 2001 2000 - -------------------------------------------------------------------------- AFUDC & capitalized interest $ 5.7 $ 6.3 $ 6.5 Interest income 4.7 5.7 8.6 Leveraged lease investment income 1.1 4.6 7.7 Other income 4.5 8.9 5.9 Other expense (4.5) (8.8) (5.6) - -------------------------------------------------------------------------- Total other - net $11.5 $16.7 $23.1 ========================================================================== Other current assets in the Consolidated Balance Sheets consists of the following: At December 31, - ------------------------------------------------------------------------- In millions 2002 2001 - ------------------------------------------------------------------------- Prepaid gas delivery service $ 70.3 $ 67.7 Prepaid taxes 4.8 46.4 Other prepayments & current assets 17.9 16.9 - ------------------------------------------------------------------------- Total prepayments & other current assets $ 93.0 $ 131.0 ========================================================================= Accrued liabilities in the Consolidated Balance Sheets consists of the following: At December 31, - -------------------------------------------------------------------------- In millions 2002 2001 - -------------------------------------------------------------------------- Accrued taxes $ 47.2 $ 34.0 Refunds to customers & customer deposits 21.0 18.7 Accrued interest 14.0 13.2 Deferred income taxes 7.7 19.1 Accrued salaries & other 30.0 33.5 - -------------------------------------------------------------------------- Total accrued liabilities $119.9 $ 118.5 ========================================================================== 18. Segment Reporting The Company had four operating segments during 2002: 1) Gas Utility Services, (2) Electric Utility Services, (3) Nonregulated Operations, and (4) Corporate and Other. The Gas Utility Services segment provides natural gas distribution and transportation services in nearly two-thirds of Indiana and west central Ohio. The Electric Utility Services segment includes the operations of SIGECO's electric transmission and distribution services, which provides electricity primarily to southwestern Indiana, and SIGECO's power generating and power marketing operations. The Company collectively refers to its gas and electric utility services segments as its Regulated Operations. The Nonregulated Operations segment is comprised of various subsidiaries and affiliates offering and investing in energy marketing and services, coal mining, utility infrastructure services, and broadband communications among other energy-related opportunities. The Corporate and Other segment, among other activities, provides general and administrative support and assets, including computer hardware and software, to the Company's other operating segments. The Company makes decisions on finance and dividends at the corporate level. Investments in unconsolidated affiliates, earnings of those unconsolidated affiliates, and the extraordinary item recognized in 2001 are primarily within the Nonregulated Operations segment. Year ended December 31, - ------------------------------------------------------------------------------ In millions 2002 2001 2000 - ------------------------------------------------------------------------------ Operating Revenues Gas Utility Services $ 909.0 $ 1,019.6 $ 820.4 Electric Utility Services 608.1 381.2 334.4 - ------------------------------------------------------------------------------ Total Regulated 1,517.1 1,400.8 1,154.8 - ------------------------------------------------------------------------------ Nonregulated Operations 352.3 741.8 503.8 Corporate & Other 23.3 29.7 33.6 Intersegment Eliminations (88.4) (90.5) (59.4) - ------------------------------------------------------------------------------- Total operating revenues $1,804.3 $ 2,081.8 $1,632.8 ============================================================================== Interest Expense Gas Utility Services $ 45.6 $ 51.6 $ 28.0 Electric Utility Services 20.5 18.5 18.1 - ------------------------------------------------------------------------------ Total Regulated 66.1 70.1 46.1 - ------------------------------------------------------------------------------ Nonregulated Operations 9.1 12.5 9.6 Corporate & Other 3.5 1.5 1.3 Intersegment Eliminations (0.2) (0.9) (0.6) - ------------------------------------------------------------------------------ Total interest expense $ 78.5 $ 83.2 $ 56.4 ============================================================================== Income Taxes Gas Utility Services $ 18.0 $ (2.0) $ 11.5 Electric Utility Services 26.6 20.4 23.5 - ------------------------------------------------------------------------------ Total Regulated 44.6 18.4 35.0 - ------------------------------------------------------------------------------ Nonregulated Operations (6.9) (4.7) 0.6 Corporate & Other 1.2 0.4 (1.4) - ------------------------------------------------------------------------------ Total income taxes $ 38.9 $ 14.1 $ 34.2 ============================================================================== Equity in Earnings of Unconsolidated Affiliates Gas Utility Services $ 0.1 $ 0.7 $ - Electric Utility Services (1.9) (1.2) - - ------------------------------------------------------------------------------ Total Regulated (1.8) (0.5) - - ------------------------------------------------------------------------------ Nonregulated Operations 10.9 13.9 9.8 - ------------------------------------------------------------------------------ Total equity in earnings of unconsolidated affiliates $ 9.1 $ 13.4 $ 9.8 ============================================================================== Net Income Gas Utility Services $ 39.0 $ (2.6) $ 15.7 Electric Utility Services 54.6 42.7 36.8 - ------------------------------------------------------------------------------ Total Regulated 93.6 40.1 52.5 - ------------------------------------------------------------------------------ Nonregulated Operations 19.0 12.1 21.8 Corporate & Other 1.4 0.5 (2.3) - ------------------------------------------------------------------------------ Net income $ 114.0 $ 52.7 $ 72.0 ============================================================================== Year ended December 31, - ------------------------------------------------------------------------------ In millions 2002 2001 2000 - ------------------------------------------------------------------------------ Depreciation & Amortization Gas Utility Services $ 56.8 $ 58.5 $ 43.8 Electric Utility Services 40.0 38.7 38.6 - ------------------------------------------------------------------------------ Total Regulated 96.8 97.2 82.4 - ------------------------------------------------------------------------------ Nonregulated Operations 8.6 5.9 1.1 Corporate & Other 14.2 21.0 22.2 - ------------------------------------------------------------------------------ Total depreciation & amortization $ 119.6 $ 124.1 $ 105.7 ============================================================================== Capital Expenditures Gas Utility Services $ 63.0 $ 77.8 $ 73.1 Electric Utility Services 88.9 69.8 37.6 - ------------------------------------------------------------------------------ Total Regulated 151.9 147.6 110.7 - ------------------------------------------------------------------------------ Nonregulated Operations 28.0 35.0 27.3 Corporate & Other 38.8 57.1 26.3 - ------------------------------------------------------------------------------ Total capital expenditures $ 218.7 $ 239.7 $ 164.3 ============================================================================== At December 31, - ------------------------------------------------------------ In millions 2002 2001 - ------------------------------------------------------------ Identifiable Assets Gas Utility Services $1,570.1 $ 1,582.5 Electric Utility Services 869.2 818.4 - ------------------------------------------------------------ Total Regulated 2,439.3 2,400.9 - ------------------------------------------------------------ Nonregulated Operations 419.6 466.5 Corporate & Other 393.3 331.9 Intersegment Eliminations (325.7) (320.6) - ------------------------------------------------------------ Total identifiable assets $2,926.5 $ 2,878.7 ============================================================ 19. Special Charges for 2001 and 2000 Restructuring & Related Charges As part of continued cost saving efforts, in June 2001, the Company's management and the board of directors approved a plan to restructure, primarily, its regulated operations. The restructuring plan included the elimination of certain administrative and supervisory positions in its utility operations and corporate office. Charges of $11.8 million were expensed in June 2001 as a direct result of the restructuring plan. Additional charges of $7.2 million were incurred during the remainder of 2001 primarily for consulting fees, employee relocation, and duplicate facilities costs. In total, the Company incurred restructuring charges of $19.0 million. These charges were comprised of $10.9 million for employee severance, related benefits and other employee related costs, $4.0 million for lease termination fees related to duplicate facilities and other facility costs, and $4.1 million for consulting and other fees. The $10.9 million of severance and related costs includes $1.6 million of deferred compensation payable at various times through 2016 and $0.8 million of non-cash pension costs. The $4.0 million of lease termination fees includes $1.0 million of non-cash charges for impaired leasehold improvements. Restructuring expenses were incurred by the Company's operating segments as follows: $10.3 million by the Gas Utility Services segment; $4.8 million by the Electric Utility Services segment; and $3.9 million by the Nonregulated segment. Employee severance and related costs are associated with approximately 100 employees. Employee separation benefits include severance, healthcare, and outplacement services. As of December 31, 2001, approximately 80 employees had exited the business. The restructuring program was completed during 2001, except for the departure of the remaining employees impacted by the restructuring which occurred during 2002 and the final settlement of the lease obligation which has yet to occur. In June 2001, the Company established accruals totaling $8.8 million ($6.8 million for severance and $2.0 million for lease termination fees). Throughout 2001 additional expenses totaling $3.1 million ($2.1 million for severance and $1.0 million for lease termination fees) were incurred. Cash payments in 2001 totaled $6.8 million, all of which related to severance payments. As of December 31, 2001, the remaining accrual related to the restructuring was $5.1 million. Of that amount, $2.1 million remained accrued for severance, almost all of which relates to deferred compensation arrangements, and $3.0 million remained for lease termination fees. During 2002, the accrual for severance did not substantially change, and $1.0 million of lease costs were paid. At December 31, 2002, the remaining accrual was $4.2 million ($2.2 million for severance and $2.0 million for lease termination fees). The restructuring accrual is included in accrued liabilities. Merger & Integration Costs Merger and integration costs incurred for the years ended December 31, 2001 and 2000 were $2.8 million and $41.1 million, respectively. Merger and integration activities resulting from the 2000 merger were completed in 2001. Since March 31, 2000, $43.9 million has been expensed associated with merger and integration activities. Accruals were established at March 31, 2000 totaling $20.7 million. Of this amount, $5.5 million related to employee and executive severance costs, $13.1 million related to transaction costs and regulatory filing fees incurred prior to the closing of the merger, and the remaining $2.1 million related to employee relocations that occurred prior to or coincident with the merger closing. At December 31, 2001, the remaining accrual related to employee severance was not significant and was entirely utilized in 2002. The remaining $23.2 million was expensed ($20.4 million in 2000 and $2.8 million in 2001) for accounting fees resulting from merger related filing requirements, consulting fees related to integration activities such as organization structure, employee travel between company locations, internal labor of employees assigned to integration teams, investor relations communication activities, and certain benefit costs. During the merger planning process, approximately 135 positions were identified for elimination. As of December 31, 2001, all such identified positions were vacated. The integration activities experienced by the Company included such things as information system consolidation, process review and definition, organization design and consolidation, and knowledge sharing. As a result of merger integration activities, management retired certain information systems in 2001. Accordingly, the useful lives of these assets were shortened in 2000 to reflect this decision, resulting in additional depreciation expense of approximately $9.6 million ($6.0 million after tax) for the year ended December 31, 2001 and $11.4 million ($7.1 million after tax) for the year ended December 31, 2000. 20. Impact of Recently Issued Accounting Guidance EITF 02-03 In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-03) that gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 should be shown net in the income statement, whether or not settled physically, if the derivative instruments are held for "trading purposes." The consensus rescinded EITF Issue 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10) as well as other decisions reached on energy trading contracts at the EITF's June 2002 meeting. The Company's non-firm wholesale power marketing operations enter into contracts that are derivatives as defined by SFAS 133, but these operations do not meet the definition of energy trading activities based upon the provisions in EITF 98-10. Currently, the Company uses a gross presentation to report the results of these operations as described in Note 16. The Company has re-evaluated its portfolio of derivative contracts and has determined gross presentation remains appropriate. SFAS 143 In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Any costs of removal recorded in accumulated depreciation pursuant to regulatory authority will require disclosure in future periods. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company's results of operations or financial condition. FASB Interpretation (FIN) 45 In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a guarantor's accounting for and disclosure of certain guarantees issued and outstanding and that a guarantor is required to recognize, at the inception of a guarantee, a liability for the obligations it has undertaken. The objective of the initial measurement of that liability is the fair value of the guarantee at its inception. The initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The incremental disclosure requirements are included in these financial statements in Note 13. Although management is still evaluating the impact of FIN 45 on its financial position and results of operations, the adoption is not expected to have a material effect. FIN 46 In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 addresses consolidation by business enterprises of variable interest entities and significantly changes the consolidation requirements for those entities. FIN 46 is intended to achieve more consistent application of consolidation policies to variable interest entities and, thus improves comparability between enterprises engaged in similar activities when those activities are conducted through variable interest entities. FIN 46 applies to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date. FIN 46 applies to the Company's third quarter for variable interest entities in which the Company holds a variable interest acquired before February 1, 2003. Although management is still evaluating the impact of FIN 46 on its financial position and results of operations, the adoption is not expected to have a material effect. 21. Quarterly Financial Data (Unaudited) As more fully described in Note 3, the Company has restated the results for the year ended December 31, 2001, including each quarter, as well as the first three quarters of 2002 to appropriately account for certain transactions. Provided below is a comparison of restated summarized quarterly financial data to summarized quarterly financial data previously reported. Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company's utility operations. Summarized quarterly financial data for 2002 follows:
In millions, except per share amounts Q1 (5) Q2 (5) (7) Q3 Q4 - ----------------------- ------------------ ------------------ ------------------ -------- As As As As As As As Reported Restated Reported Restated Reported Restated Reported 2002 Operating data -------- -------- -------- -------- -------- -------- -------- Operating revenues $ 635.2 $ 630.4 $ 386.9 $ 380.1 $ 304.5 $ 304.3 $ 489.5 Operating income 84.2 82.9 23.6 25.6 32.5 31.5 71.3 Net income 45.6 45.6 14.3 12.5 14.0 13.5 42.4 Earnings per share: Basic 0.68 0.68 0.21 0.18 0.21 0.20 0.63 Diluted 0.67 0.67 0.21 0.18 0.21 0.20 0.62
Summarized quarterly financial data for 2001 follows:
In millions, except per share amounts Q1 (1) (5) Q2 (2) (3) (5) Q3 (5) Q4 (5) (6) - ------------------------- ------------------ ------------------ ------------------ ------------------ As As As As As As As As Reported Restated Reported Restated Reported Restated Reported Restated 2001 Operating Data (4) -------- -------- -------- -------- -------- -------- -------- -------- Operating revenues $ 883.9 $ 878.0 $ 433.1 $ 416.1 $ 356.7 $ 336.9 $ 496.3 $ 450.8 Operating income (loss) 73.5 78.2 (3.8) (4.5) 17.4 16.8 52.5 37.4 Income (loss) before extraordinary loss & cumulative effect of change in accounting principle 40.5 43.8 (10.0) (10.6) 4.5 3.8 32.4 22.3 Earnings (loss) per share before extraordinary loss & cumulative effect of change in accounting principle: Basic 0.62 0.66 (0.15) (0.15) 0.07 0.06 0.48 0.33 Diluted 0.61 0.66 (0.15) (0.15) 0.07 0.06 0.48 0.33 Net income (loss) 44.4 44.9 (17.7) (18.3) 4.5 3.8 32.4 22.3 Earnings (loss) per share Basic 0.68 0.68 (0.26) (0.27) 0.07 0.06 0.48 0.33 Diluted 0.67 0.68 (0.26) (0.27) 0.07 0.06 0.48 0.33
1. Q1 of 2001 includes charges for cumulative effect of changes in accounting principle as described in Note 16. 2. Q2 of 2001 includes restructuring charges as described in Note 19. 3. Q2 of 2001 includes an extraordinary loss as described in Note 5. 4. 2001 includes merger and integration charges as described in Note 19. 5. The changes in previously reported revenues reflect principal/agent relationships and the proper elimination of certain transactions upon consolidation. 6. The benefit clearing adjustment and primarily all of the inventory adjustment discussed in Note 3 were recorded in the fourth quarter of 2001. 7. In Q2 of 2002, the Company recorded $3.2 million of after tax carrying costs for DSM programs pursuant to existing IURC orders. Management determined that the accrual of such carrying costs was more appropriate in periods prior to 2000 when DSM program expenditures were made. Therefore, such carrying costs originally reflected in Q2 of 2002 were reversed and reflected in common shareholders' equity as of January 1, 2000. ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Disclosure with respect to this Item, has been previously provided on Form 8-K originally filed with the SEC on March 26, 2002, as amended on Form 8-K/A filed with the SEC on May 20, 2002. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Except with respect to information regarding the executive officers of the Registrant, the information required by Part III, Item 10 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the company's definitive Proxy Statement for its 2003 Annual Meeting of Stockholders, will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year. The information with respect to the executive officers of the Registrant is included below. Niel C. Ellerbrook, age 54, has been a director of Indiana Energy or the Company since 1991. Mr. Ellerbrook is Chairman of the Board and Chief Executive Officer of the Company, having served in that capacity since March 2000. Mr. Ellerbrook served as President and Chief Executive Officer of Indiana Energy from June 1999 to March 2000. Mr. Ellerbrook served as President and Chief Operating Officer of Indiana Energy from October 1997 to March 2000. From January through October 1997, Mr. Ellerbrook served as Executive Vice President, Treasurer, and Chief Financial Officer of Indiana Energy; and from 1986 to January 1997 as Vice President, Treasurer, and Chief Financial Officer of Indiana Energy. Mr. Ellerbrook is a director of Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., and Southern Indiana Gas and Electric Co. He is also a director of Old National Bancorp and Deaconess Hospital of Evansville, Indiana. Andrew E. Goebel, age 55, has been a director of SIGCORP or the Company since 1997. Mr. Goebel is President and Chief Operating Officer of the Company, having served in that capacity since March 2000. Mr. Goebel was President and Chief Operating Officer of SIGCORP from April 1999 to March 2000. From September 1997 through April 1999, Mr. Goebel served as Executive Vice President of SIGCORP; and from 1996 to September 1997, he served as Secretary and Treasurer of SIGCORP. Mr. Goebel is a director of Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., and Southern Indiana Gas and Electric Co. Mr. Goebel is also a director of Old National Bancorp and Old National Bank. Mr. Goebel is retiring from the Company effective April 30, 2003. Jerome A. Benkert, Jr., age 44, has served as Executive Vice President and Chief Financial Officer of the Company since March 2000 and as Treasurer of the Company since October 2001 to April 2002. He was Executive Vice President and Chief Operating Officer of Indiana Energy's administrative services company from October 1997 to March 2000. Mr. Benkert has served as Controller and Vice President of Indiana Gas. Mr. Benkert is a director of Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Co., and Fifth Third Bank, Indiana. Carl L. Chapman, age 47, has served as Executive Vice President of the Company and President of Vectren Enterprises, Inc. since March 2000. Prior to March 31, 2000 and since 1999, Mr. Chapman served as Executive Vice President and Chief Financial Officer of Indiana Energy. From October 1997 to June 2002, Mr. Chapman served as President of IGC Energy, Inc., which has been renamed Vectren Energy Marketing and Services, Inc. Mr. Chapman served as President of ProLiance Energy, LLC ("ProLiance"), a gas supply and energy marketing joint venture partially owned by Vectren Energy Marketing and Services, Inc., an indirect, wholly-owned subsidiary of the Company, from March 1996, until April 1998. Currently, Mr. Chapman is the chairman of ProLiance. From 1995 until March 1996, he was Senior Vice President of Corporate Development for Indiana Gas. Prior to 1995 and since 1987, he was Vice President of Planning for Indiana Gas. Ronald E. Christian, age 44, has served as Senior Vice President, General Counsel, and Secretary of the Company since March 2000. Mr. Christian served as Vice President and General Counsel of Indiana Energy from July 1999 to March 2000. From June 1998 to July 1999, Mr. Christian was the Vice President, General Counsel and Secretary of Michigan Consolidated Gas Company in Detroit, Michigan. He served as the General Counsel and Secretary of Indiana Energy, Indiana Gas and Indiana Energy Investments, Inc. from 1993 to June 1998. Mr. Christian is a director of Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., and Southern Indiana Gas and Electric Co. Richard G. Lynch, age 51, has served as Senior Vice President-Human Resources and Administration of the Company since March 2000. Mr. Lynch was Vice President of Human Resources for SIGCORP from March 1999 to March 2000. Prior to joining the Company, Mr. Lynch was the Director of Human Resources for the Mead Johnson Division of Bristol Myers-Squibb in Evansville, Indiana. ITEM 11. EXECUTIVE COMPENSATION Information required by Part III, Item 11 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2003 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year. ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Except with respect to equity compensation plan information of the Registrant, the information required by Part III, Item 12 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the company's definitive Proxy Statement for its 2003 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year. The information with respect to common shares issuable under equity compensation plans as of December 31, 2002 with respect to the Registrants is included below.
- ---------------------------------------------------------------------------------------- (a) (b) ( c) - ---------------------------------------------------------------------------------------- 'Number of Weighted- securities to be average exercise Number of securities issued upon price of remaining available exercise of outstanding for future issuance under outstanding options, equity compensation plans options, warrants warrants (excluding securities Plan category and rights and rights reflected in column (a) - ---------------------------------------------------------------------------------------- Equity compensation 1,733,762 (2) $ 21.86 2,909,316 (3) plans approved by security holders (1) - ---------------------------------------------------------------------------------------- Equity compensation 0 0 0 plans not approved by security holders - ---------------------------------------------------------------------------------------- Total 1,733,762 $ 21.86 2,909,316 ========================================================================================
(1) Includes the following Vectren Corporation Plans: Vectren Corporation At-Risk Compensation Plan, 1994 SIGCORP Stock Option Plan, Vectren Corporation Executive Restricted Stock Plan, and Vectren Corporation Directors Restricted Stock Plan. (2) Includes a stock option grant approved by the Board of Directors' Compensation Committee on December 11, 2002, effective January 1, 2003. (3) Includes shares available for issuance under the Vectren Corporation At-Risk Compensation Plan (2,678,027), of which up to 800,000 shares may be issued in restricted stock, Vectren Corporation Executive Restricted Stock Plan (186,098), and Vectren Corporation Directors Restricted Stock Plan (45,191). The SIGCORP stock option plan was approved by SIGCORP common shareholders prior to the merger forming Vectren, and both the directors and executive restricted stock plans were approved by Indiana Energy common shareholders prior to the merger forming Vectren. The At-Risk Compensation plan was approved by Vectren Corporation common shareholders after the merger forming Vectren. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information required by Part III, Item 13 of this Form 10-K is incorporated by reference herein, and made part of this Form 10-K, from the Company's definitive Proxy Statement for its 2003 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A, not later than 120 days after the end of the fiscal year. PART IV ITEM 14. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures Within 90 days prior to the filing of the report, the Company carried out an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective in bringing to their attention on a timely basis material information relating to the Company required to be disclosed by the Company in its filings under the Securities Exchange Act of 1934 (Exchange Act). Disclosure controls and procedures, as defined by the Exchange Act in Rules 13a-14(c) and 15d-14(c), are controls and other procedures of the Company that are designed to ensure that information required to be disclosed by the Company in the reports filed or submitted by it under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms. "Disclosure controls and procedures" include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in its Exchange Act reports is accumulated and communicated to the Company's management, including its principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company has investments in unconsolidated affiliates. As the Company does not control or manage these affiliates, its disclosure controls and procedures with respect to them are more limited than the disclosure controls and procedures maintained within the Company's consolidated subsidiaries. Changes in Internal Control Since the evaluation of disclosure controls and procedures, there have been no significant changes to the Company's internal controls and procedures or significant changes in other factors that could significantly affect the Company's internal controls and procedures. However, in Note 3 to the consolidated financial statements (included in Item 8) which discusses the restatement of 2001 and 2000 previously reported information, the Company identified certain errors, the net effect of which, related primarily to gas inventory accounting and the proper clearing of employee benefit related costs routinely accumulated on the balance sheet. These errors resulted primarily from insufficient account reconciliation procedures. The Company has taken steps to improve these internal controls. Internal control, as defined in American Institute of Certified Public Accountants Codification of Statements on Auditing Standards (AU ss.319), is a process, effected by an entity's board of directors, management, and other personnel, designed to provide reasonable assurance regarding the achievement of objectives in the following categories: (a) reliability of financial reporting, (b) effectiveness and efficiency of operations and (c) compliance with applicable laws and regulations. ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K List Of Documents Filed As Part Of This Report Consolidated Financial Statements The consolidated financial statements and related notes, together with the report of Deloitte & Touche LLP, appear in Part II Item 8 Financial Statements and Supplementary Data of this Form 10-K. Supplemental Schedules For the years ended December 31, 2002, 2001, and 2000, the Company's Schedule II - -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented on page 93. The report of Deloitte & Touche LLP on the schedule may be found in Item 8. All other schedules are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or related notes in Item 8. List of Exhibits The Company has incorporated by reference herein certain exhibits as specified below pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company are listed in the Index to Exhibits beginning on page 95. Exhibits for the Company attached to this filing filed electronically with the SEC are listed on page 100. Reports On Form 8-K During The Last Calendar Quarter On October 25, 2002 Vectren Corporation filed a Current Report on Form 8-K with respect to the release of financial information to the investment community regarding the Company's results of operations, financial position and cash flows for the three, nine, and twelve month periods ended September 30, 2002. The financial information was released to the public through this filing. Item 5. Other Events Item 7. Exhibits 99.1 - Press Release - Third Quarter 2002 Vectren Corporation Earnings 99.2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 On November 21, 2002, Vectren Corporation filed a Current Report on Form 8-K with respect to an analyst meeting where a discussion of the Company's current financial and operating results and plans for the future will occur. Item 5. Other Events Item 7. Exhibits 99.1 - Press Release - Vectren Annual Analyst Seminar to be Webcast 99.2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 On November 27, 2002, Vectren Corporation filed a Current Report on Form 8-K with respect to a press release issued by Moody's Investors Service that downgraded the credit ratings on various debt instruments issued by certain of Vectren Corporation's (Vectren) wholly owned subsidiaries. Item 5. Other Events Item 7. Exhibits 99.1 - Press Release - Moody's Investors Service 99.2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 SCHEDULE II
Vectren Corporation and Subsidiaries VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E - ---------------------------------------------------------------------------------------------------- Additions ------------------ Balance at Charged Charged Deductions Balance at Beginning to to Other from End of Description Of Year Expenses Accounts Reserves, Net Year - ---------------------------------------------------------------------------------------------------- (In millions) VALUATION AND QUALIFYING ACCOUNTS: AS RESTATED Year 2002 - Accumulated provision for uncollectible accounts $ 5.3 $ 11.7 $ - $ 11.5 $ 5.5 Year 2001 - Accumulated provision for uncollectible accounts $ 5.1 $ 17.3 $ - $ 17.1 $ 5.3 Year 2000 - Accumulated provision for uncollectible accounts $ 3.9 $ 7.7 $ 0.1 $ 6.6 $ 5.1 OTHER RESERVES: Year 2002 - Reserve for merger and integration charges $ 0.4 $ - $ - $ 0.4 $ - Year 2001 - Reserve for merger and integration charges $ 1.8 $ - $ - $ 1.4 $ 0.4 Year 2000 - Reserve for merger and integration charges $ - $ 27.2 $ - $ 25.4 $ 1.8 Year 2002 - Reserve for restructuring costs $ 5.1 $ - $ - $ 0.9 $ 4.2 Year 2001 - Reserve for restructuring costs $ - $ 11.9 $ - $ 6.8 $ 5.1
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Amendment No. 1 on Form 10-K/A to the Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. VECTREN CORPORATION Dated June 17, 2003 /S/ Niel C. Ellerbrook ------------------------------------- Niel C. Ellerbrook, Chairman and Chief Executive Officer, Director INDEX TO EXHIBITS 2. Plan Of Acquisition, Reorganization, Arrangement, Liquidation Or Succession 2.1 Agreement and Plan of Merger dated as of June 11,1999 among Indiana Energy, Inc., SIGCORP, Inc. and Vectren Corporation (the "Merger Agreement "). (Filed and designated in Form S-4 to (No. 333-90763) filed on November 12, 1999, File No. 1-15467, as Exhibit 2.) 2.2 Amendment No.1 to the Merger Agreement dated December 14, 1999 (Filed and designated in Current Report on Form 8-K filed December 16, 1999, File No. 1-09091, as Exhibit 2.) 2.3 Asset Purchase Agreement dated December 14,1999 between Indiana Energy, Inc. and The Dayton Power and Light Company and Number-3CHK with a commitment letter for a 364-Day Credit Facility dated December 16,1999. (Filed and designated in Current Report on Form 8-K dated December 28, 1999, File No. 1-9091, as Exhibit 2 and 99.1.) Articles Of Incorporation And By-Laws 3.1 Amended and Restated Articles of Incorporation of Vectren Corporation effective March 31, 2000. (Filed and designated in Current Report on Form 8-K filed April 14, 2000, File No. 1-15467, as Exhibit 4.1.) 3.2 Amended and Restated Code of By-Laws of Vectren Corporation as of February 26, 2003. (Filed and designated in Annual Report on Form 10-K filed March 18, 2003, File No. 1-15467, as Exhibit 3.2.) 3.3 Shareholders Rights Agreement dated as of October 21, 1999 between Vectren Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and designated in Form S-4 (No. 333-90763), filed November 12. 1999, File No. 1-15467, as Exhibit 4.) 4. Instruments Defining The Rights Of Security Holders, Including Indentures 4.1 Mortgage and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas and Electric Company and Bankers Trust Company, as Trustee, and Supplemental Indentures thereto dated August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.) December 13, 1990. (Filed and designated in Form 10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.) April 1, 1993. (Filed and designated in Form 8-K, dated April 13, 1993, File No. 1-3553, as Exhibit 4.) June 1, 1993 (Filed and designated in Form 8-K, dated June 14, 1993, File No. 1-3553, as Exhibit 4.) May 1, 1993. (Filed and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit 4(a).) July 1, 1999. (Filed and designated in Form 10-Q, dated August 16, 1999, File No. 1-3553, as Exhibit 4(a).) March 1, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 4.1.) 4.2 Indenture dated February 1, 1991, between Indiana Gas and U.S. Bank Trust National Association (formerly know as First Trust National Association, which was formerly know as Bank of America Illinois, which was formerly know as Continental Bank, National Association. Inc.'s. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494.); First Supplemental Indenture thereto dated as of February 15, 1991. (Filed and designated in Current Report on Form 8-K filed February 15, 1991, File No. 1-6494, as Exhibit 4(b).); Second Supplemental Indenture thereto dated as of September 15, 1991, (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(b).); Third supplemental Indenture thereto dated as of September 15, 1991 (Filed and designated in Current Report on Form 8-K filed September 25, 1991, File No. 1-6494, as Exhibit 4(c).); Fourth Supplemental Indenture thereto dated as of December 2, 1992, (Filed and designated in Current Report on Form 8-K filed December 8, 1992, File No. 1-6494, as Exhibit 4(b).); Fifth Supplemental Indenture thereto dated as of December 28, 2000, (Filed and designated in Current Report on Form 8-K filed December 27, 2000, File No. 1-6494, as Exhibit 4.) 4.3 Indenture dated October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.1); First Supplemental Indenture, dated October 19, 2001, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated October 19, 2001, File No. 1-16739, as Exhibit 4.2); Second Supplemental Indenture, between Vectren Utility Holdings, Inc., Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company, Vectren Energy Delivery of Ohio, Inc., and U.S. Bank Trust National Association. (Filed and designated in Form 8-K, dated November 29, 2001, File No. 1-16739, as Exhibit 4.1). 10. Material Contracts 10.1 Agreement, dated, January 30, 1968, for Unit No. 4 at the Warrick Power Plant of Alcoa Generating Corporation ("Alcoa"), between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Registration No. 2-29653 as Exhibit 4(d)-A.) 10.2 Letter of Agreement, dated June 1, 1971, and Letter Agreement, dated June 26, 1969, between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Registration No. 2-41209 as Exhibit 4(e)-2.) 10.3 Letter Agreement, dated April 9, 1973, and Agreement dated April 30, 1973, between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Registration No. 2-53005 as Exhibit 4(e)-4.) 10.4 Electric Power Agreement (the "Power Agreement"), dated May 28, 1971, between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Registration No. 2-41209 as Exhibit 4(e)-1.) 10.5 Second Supplement, dated as of July 10, 1975, to the Power Agreement and Letter Agreement dated April 30, 1973 - First Supplement. (Filed and designated in Form 10-K for the fiscal year 1975, File No. 1-3553, as Exhibit 1(e).) 10.6 Third Supplement, dated as of May 26, 1978, to the Power Agreement. (Filed and designated in Form 10-K for the fiscal year 1978 as Exhibit A-1.) 10.7 Letter Agreement dated August 22, 1978 between Southern Indiana Gas and Electric Company and Alcoa, which amends Agreement for Sale in an Emergency of Electrical Power and Energy Generation by Alcoa and Southern Indiana Gas and Electric Company dated June 26, 1979. (Filed and designated in Form 10-K for the fiscal year 1978, File No. 1-3553, as Exhibit A-2.) 10.8 Fifth Supplement, dated as of December 13, 1978, to the Power Agreement. (Filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-3.) 10.9 Sixth Supplement, dated as of July 1, 1979, to the Power Agreement. (Filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-5.) 10.10 Seventh Supplement, dated as of October 1, 1979, to the Power Agreement. (Filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-6.) 10.11 Eighth Supplement, dated as of June 1, 1980 to the Electric Power Agreement, dated May 28, 1971, between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Form 10-K for the fiscal year 1980, File No. 1-3553, as Exhibit (20)-1.) 10.12 Amendment Agreement, dated March 3, 2001, between Alcoa Power Generating Inc. and Southern Indiana Gas and Electric Company. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.12.) 10.13 Summary description of Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) 10.14 Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and designated in Southern Indiana Gas and Electric Company's Proxy Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.) 10.15 Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan as amended, effective April 16, 1997. (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.) 10.16 Vectren Corporation Retirement Savings Plan (amended and restated effective January 1, 2002). (Filed and designated in Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-15467, as Exhibit 10.1.) 10.17 Vectren Corporation Combined Non-Bargaining Retirement Plan. (Filed and designated in Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-15467, as Exhibit 99.2.) 10.18 Indiana Energy, Inc. Unfunded Supplemental Retirement Plan for a Select Group of Management Employees as amended and restated effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-G.) 10.19 Indiana Energy, Inc. Nonqualified Deferred Compensation Plan effective January 1, 1999. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-H.) 10.20 Formation Agreement among Indiana Energy, Inc., Indiana Gas Company, Inc., IGC Energy, Inc., Indiana Energy Services, Inc., Citizens Gas & Coke Utility, Citizens Energy Services Corporation and ProLiance Energy, LLC, effective March 15, 1996. (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1996, File No. 1-9091, as Exhibit 10-C.) 10.21 Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective March 15, 1996, for services to begin April 1, 1996. (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1996, File No. 1-6494, as Exhibit 10-C.) 10.22 Amended appendices to the Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC effective November 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended March 31, 1999, File No. 1-6494, as Exhibit 10-A.) 10.23 Amended appendices to the Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC effective November 1, 1999. (Filed and designated in Form 10-K for the fiscal year ended September 30, 1999, File No. 1-6494, as Exhibit 10-V.) 10.24 Gas Sales and Portfolio Administration Agreement between Vectren Energy Delivery of Ohio and ProLiance Energy, LLC, effective October 31, 2000, for services to begin November 1, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10-24.) 10.25 Indiana Energy, Inc. Executive Restricted Stock Plan as amended and restated effective October 1, 1998. (Filed and designated in Form 10-K for the fiscal year ended September 30, 1998, File No. 1-9091, as Exhibit 10-O.) 10.26 Amendment to Indiana Energy, Inc. Executive Restricted Stock Plan effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-I.) 10.27 Indiana Energy, Inc. Director's Restricted Stock Plan as amended and restated effective May 1, 1997. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 1997, File No. 1-9091, as Exhibit 10-B.) 10.28 First Amendment to Indiana Energy, Inc. Directors' Restricted Stock Plan, effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File No. 1-9091, as Exhibit 10-J.) 10.29 Second Amendment to Indiana Energy, Inc. Directors Restricted Stock Plan, renamed the Vectren Corporation Directors Restricted Stock Plan effective October 1, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2000, File No. 1-15467, as Exhibit 10-34.) 10.30 Third Amendment to Indiana Energy, Inc. Directors Restricted Stock Plan, renamed the Vectren Corporation Directors Restricted Stock Plan effective March 28, 2001. (Filed and designated in Form 10-K for the year ended December 31, 2000, File No. 1-15467, as Exhibit 10-35.) 10.31 Vectren Corporation At Risk Compensation Plan effective May 1, 2001. (Filed and designated in Vectren Corporation's Proxy Statement dated March 16, 2001, File No. 1-15467, as Appendix B.) 10.32 Vectren Corporation Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.32.) 10.33 Vectren Corporation Employment Agreement between Vectren Corporation and Niel C. Ellerbrook dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.1.) 10.34 Vectren Corporation Employment Agreement between Vectren Corporation and Andrew E. Goebel dated as of March 31, 2000 (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.2.) 10.35 Vectren Corporation Employment Agreement between Vectren Corporation and Jerome A. Benkert, Jr. dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.3.) 10.36 Vectren Corporation Employment Agreement between Vectren Corporation and Carl L. Chapman dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.4.) 10.37 Vectren Corporation Employment Agreement between Vectren Corporation and Ronald E. Christian dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.5.) 10.38 Vectren Corporation Employment Agreement between Vectren Corporation and Timothy M. Hewitt dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.6.) 10.39 Vectren Corporation Retirement Agreement between Vectren Corporation and Timothy M. Hewitt dated as of May 31, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.39.) 10.40 Vectren Corporation Employment Agreement between Vectren Corporation and J. Gordon Hurst dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.7.) 10.41 Vectren Corporation Retirement Agreement between Vectren Corporation and J. Gordon Hurst dated as of May 31, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.41.) 10.42 Vectren Corporation Employment Agreement between Vectren Corporation and Richard G. Lynch dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15467, as Exhibit 99.8.) 10.43 Vectren Corporation Employment Agreement between Vectren Corporation and William S. Doty dated as of April 30, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.43.) 10.44 Vectren Corporation Retirement Agreement between Vectren Corporation and Thomas J. Zabor dated as of May 31, 2001. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10.44.) 21. Subsidiaries Of The Company The list of the Company's significant subsidiaries was (Filed and designated in Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-15467, as Exhibit 21.1.) 23. Consents Of Experts And Counsel The consent of Deloitte & Touche LLP is attached hereto as Exhibit 23.1. 99. Additional Exhibits 99.1 Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (Filed Herewith.) 99.2 Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed Herewith.) 99.3 Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (Filed Herewith.) Vectren Corporation 2002 Form 10-K/A Attached Exhibits The following Exhibits were filed electronically with the SEC with this filing. See Page 95 of this Amendment to the Annual Report on Form 10-K/A for a complete list of exhibits. Exhibit Number Document 23.1 Consent of Independent Public Accountants 99.1 Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 99.3 Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. EX-23.1 CONSENT 3 vvc-amended23_1.txt CONSENT OF INDEPENDENT AUDITORS EX 23.1 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 333-33608 and 333-61252 of Vectren Corporation on Form S-8, Post Effective Amendment No. 1 to Registration Statement No. 333-33684 of Vectren Corporation on Form S-8, and Registration Statement No. 333-31326 of Vectren Corporation on Form S-3D of our report dated February 26, 2003 (which expresses an unqualified opinion and includes explanatory paragraphs relating to the changes in the method of accounting for goodwill described in Note 2G and financial derivative instruments and hedging activities described in Note 16, and the restatement described in Note 3), appearing in this Amendment No. 1 to the Annual Report on Form 10-K/A of Vectren Corporation for the year ended December 31, 2002. /s/Deloitte & Touche LLP - ------------------------ Deloitte & Touche LLP Indianapolis, Indiana June 17, 2003 EX-99.1 CERTIFICATIO 4 vvc-ex99_1.txt CERTIFICATION EX. 99.1 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 CERTIFICATION By signing below, each of the undersigned officers hereby certifies pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his or her knowledge, (i) this report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in this report fairly presents, in all material respects, the financial condition and results of operations of Vectren Corporation. Signed this 17th day of June, 2003. /s/ Jerome A. Benkert, Jr. /s/ Niel C. Ellerbrook - ---------------------------------------- ------------------------------------- (Signature of Authorized Officer) (Signature of Authorized Officer) Jerome A. Benkert, Jr. Niel C. Ellerbrook - ---------------------------------------- ------------------------------------ (Typed Name) (Typed Name) Executive Vice President and Chief Financial Officer Chairman and Chief Executive Officer - ---------------------------------------- ------------------------------------ (Title) (Title) EX-99.2 CERTIFICATIO 5 vvc-ex99_2.txt CERTIFICATION EX 99.2 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 CHIEF EXECUTIVE OFFICER CERTIFICATION I, Niel C. Ellerbrook, certify that: 1. I have reviewed this amendment to the annual report on Form 10-K/A of Vectren Corporation; 2. Based on my knowledge, this amendment to the annual report on Form 10-K/A does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this amendment to the annual report on Form 10-K/A; 3. Based on my knowledge, the financial statements, and other financial information included in this amendment to the annual report on Form 10-K/A, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this amendment to the annual report on Form 10-K/A; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this amendment to the annual report on Form 10-K/A is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this amendment to the annual report on Form 10-K/A (the "Evaluation Date"); and c) presented in this amendment to the annual report on Form 10-K/A our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this amendment to the annual report on Form 10-K/A whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: June 17, 2003 /s/ Niel C. Ellerbrook ------------------------------------ Niel C. Ellerbrook Chairman and Chief Executive Officer EX-99.3 CERTIFICATIO 6 vvc-ex99_3.txt CERTIFICATION EX 99.3 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 CHIEF FINANCIAL OFFICER CERTIFICATION I, Jerome A. Benkert, Jr., certify that: 1. I have reviewed this amendment to the annual report on Form 10-K/A of Vectren Corporation; 2. Based on my knowledge, this amendment to the annual report on Form 10-K/A does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this amendment to the annual report on Form 10-K/A; 3. Based on my knowledge, the financial statements, and other financial information included in this amendment to the annual report on Form 10-K/A, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this amendment to the annual report on Form 10-K/A; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this amendment to the annual report on Form 10-K/A is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this amendment to the annual report on Form 10-K/A (the "Evaluation Date"); and c) presented in this amendment to the annual report on Form 10-K/A our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this amendment to the annual report on Form 10-K/A whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: June 17, 2003 /s/ Jerome A. Benkert, Jr. --------------------------------- Jerome A. Benkert, Jr. Executive Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----