-----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, LHVgTjgdqFmu+Cgquz7ODNAbt9glFO9uyrWDDdoy3tsnOrY4RFV5zpkXcUE0K5Pw aNMAM+Dv0fyVtfb20VJpOQ== 0001129542-05-000002.txt : 20050309 0001129542-05-000002.hdr.sgml : 20050309 20050309164008 ACCESSION NUMBER: 0001129542-05-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20041231 FILED AS OF DATE: 20050309 DATE AS OF CHANGE: 20050309 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VECTREN UTILITY HOLDINGS INC CENTRAL INDEX KEY: 0001129542 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 352104850 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-16739 FILM NUMBER: 05669767 BUSINESS ADDRESS: STREET 1: 20 NW 4TH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 BUSINESS PHONE: 8124914000 10-K 1 vuhi10k_2004first3.txt VECTREN UTILITY HOLDINGS 10K YEAR END FILING UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (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, 2004 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: 1-16739 VECTREN UTILITY HOLDINGS, INC. - -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) INDIANA 35-2104850 - --------------------------------------------- ------------------------------- (State or other jurisdiction of (IRS Employer Identification incorporation or organization) 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 - ------------------------------------ ------------------------------------------ 7 1/4% Senior Notes, due 10/15/2031 New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Title of each class Name of each exchange on which registered - ------------------------------------ ------------------------------------------ Common - Without Par 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__. No |X|. 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 30, 2004, was zero. All shares outstanding of the Registrant's common stock were held by Vectren Corporation. 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 10 March 1, 2005 Class Number of Shares Date Omission of Information by Certain Wholly Owned Subsidiaries The Registrant is a wholly owned subsidiary of Vectren Corporation and meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format contemplated thereby. 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 / thousands of megawatt hours (gigawatt hours) FASB: Financial Accounting Standards NOx: nitrogen oxide Board FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility Commission Consumer Counselor IDEM: Indiana Department of PUCO: Public Utilities Commission of Ohio Environmental Management IURC: Indiana Utility Regulatory SFAS: Statement of Financial Accounting Commission Standards MCF/MMCF/BCF: thousands/millions/ USEPA: United States Environmental billions of cubic feet 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 ............................................................5 3 Legal Proceedings......................................................6 4 Submission of Matters to Vote of Security Holders......................6 Part II 5 Market for the Company's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities ....................6 6 Selected Financial Data................................................7 7 Management's Discussion and Analysis of Results of Operations and Financial Condition.....................................8 7A Qualitative and Quantitative Disclosures About Market Risk............23 8 Financial Statements and Supplementary Data...........................25 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................................56 9A Controls and Procedures...............................................56 9B Other Information.....................................................56 Part III 10 Directors and Executive Officers of the Registrant(A).................56 11 Executive Compensation(A).............................................56 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters(A).........................56 13 Certain Relationships and Related Transactions(A).....................56 14 Principal Accountant Fees and Services................................57 Part IV 15 Exhibits and Financial Statement Schedules............................58 Signatures............................................................63 (A) - Omitted or amended as the Registrant is a wholly owned subsidiary of Vectren Corporation and meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and is therefore filing with the reduced disclosure format contemplated thereby. Access to Information Vectren Corporation makes available all SEC filings and recent annual reports, including those of Vectren Utility Holdings, Inc., 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, 47702-0209 Investor Relations sschein@vectren.com PART I ITEM 1. BUSINESS Description of the Business Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation, was formed on March 31, 2000 to serve as the intermediate holding company for Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (SIGCORP), and the Ohio operations. VUHI also has assets that provide information technology and other services to the utilities. Indiana Gas provides energy delivery services to approximately 555,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 136,000 electric customers and approximately 110,000 natural gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 315,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary, (53% ownership) and Indiana Gas (47% ownership). The Ohio operations were acquired from The Dayton Power and Light Company on October 31, 2000. The Ohio operations generally do business as Vectren Energy Delivery of Ohio. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana and 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 that has been accounted for as a pooling-of-interests. 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. Narrative Description of the Business The Company segregates its businesses into three operating segments: Gas Utility Services, Electric Utility Services, and Other Operations. 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 to west central Ohio. The Electric Utility Services segment includes the operations of SIGECO's electric transmission and distribution services, which provides electric distribution services primarily to southwestern Indiana, and includes the Company's power generating and marketing operations. The Company collectively refers to its gas and electric operating segments as its regulated operations. In total, these regulated operations supply natural gas and/or electricity to nearly one million customers. Other Operations primarily provide information technology and other support services to those utility operations. At December 31, 2004, the Company had $3.1 billion in total assets, with $1.9 billion (61%) attributed to the Gas Utility Services, $1.1 billion (35%) attributed to the Electric Utility Services, and $0.1 billion (3%) attributed to Other Operations. Net income for the year ended December 31, 2003, was $83.1 million with $75.9 million attributed to regulated operations and $7.2 million attributed to other operations. Net income for the year ended 2003 was $85.6 million. For further information, refer to Note 13 regarding the activities and assets of the Company's operating segments in the Company's consolidated financial statements included under "Item 8 Financial Statements and Supplementary Data". Following is a more detailed description of the Gas Utility Services and Electric Utility Services operating segments. The Company's Other Operations are generally not significant. Gas Utility Services At December 31, 2004, the Company supplied natural gas service to approximately 980,000 Indiana and Ohio customers, including 895,000 residential, 81,000 commercial, and 4,000 contract and other customers. This represents customer base growth of 1.2% compared to 2003. 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(R)) 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, 2004, gas utility revenues were approximately $1,126.2 million, of which residential customers accounted for 66%, commercial 25%, and industrial and other 9%, respectively. The Company receives gas revenues by selling gas directly to customers at approved rates or by transporting gas through its pipelines at approved rates to customers that have purchased gas directly from other producers, brokers, or marketers. Total volumes of gas provided to both sales and transportation customers (throughput) were 200,343 MDth for the year ended December 31, 2004. Gas transported or sold to residential and commercial customers was 110,666 MDth representing 55% of throughput. Gas transported or sold to industrial and other contract customers was 89,677 MDth representing 45% of 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 has storage capacity at seven active underground gas storage fields, six liquefied petroleum air-gas manufacturing plants, and a propane cavern. The Company also contracts with ProLiance Energy, LLC (ProLiance) to ensure availability of gas. ProLiance is an unconsolidated, nonregulated, energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas). (See Note 4 in the Company's consolidated financial statements included in "Item 8 Financial Statements and Supplementary Data" regarding transactions with ProLiance). Periodically, purchased natural gas is injected into storage. The injected gas is then available to supplement contracted and manufactured volumes during periods of peak requirements. In addition, the Company prepays ProLiance for natural gas delivery services during the seven months prior to the peak heating season. The volume of gas per day that can be delivered during peak demand periods for each utility is located in "Item 2 Properties." Gas Purchases In 2004, the Company purchased 112,372 MDth volumes of gas at an average cost of $6.92 per Dth, all of which was purchased from ProLiance pursuant to contracts approved by the IURC. The average cost of gas per Dth purchased for the last five years was: $6.92 in 2004; $6.36 in 2003; $4.57 in 2002; $5.83 in 2001; and $5.60 in 2000. Electric Utility Services At December 31, 2004, the Company supplied electric service to approximately 136,000 Indiana customers, including 119,000 residential, and 17,000 commercial, industrial, and other customers. This represents customer base growth of 0.9% compared to 2003. In addition, the Company is obligated to provide for firm power commitments to four 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(R)) 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, 2004, retail and firm wholesale electricity sales totaled 6,186,160 MWh, resulting in revenues of approximately $347.5 million. Residential customers accounted for 34% of 2004 revenues; commercial 27%; industrial 31%; and municipal and other 8%. In addition, the Company sold 3,526,005 MWh through wholesale contracts in 2004, generating revenue, net of purchased power costs, of $23.8 million. Generating Capacity Installed generating capacity as of December 31, 2004, was rated at 1,351 MW. Coal-fired generating units provide 1,056 MW of capacity, and natural gas or oil-fired turbines used for peaking or emergency conditions provide 295 MW. Peaking capacity of 80 MW fueled by natural gas was added during 2002. In addition to its generating capacity, in 2004, the Company had 32 MW available under firm contracts and 51 MW available under interruptible contracts. The Company also had a firm purchase supply contract for a maximum of 73 MW for the peak cooling season months during 2004. 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 has been, and may continue to be, impacted. The Company, as a member of the Midwest Independent System Operator (MISO), has turned over operational control of 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 2000 through 2004 at the time of the system summer peak, and the related reserve margin, is presented below in MW. - -------------------------------------------------------------------------------- Date of summer peak load 7/13/2004 8/27/2003 8/5/2002 7/31/2001 8/17/2000 ---------- --------- --------- --------- --------- Total load at peak (1) 1,222 1,272 1,258 1,234 1,212 Generating capability 1,351 1,351 1,351 1,271 1,256 Firm purchase supply 105 32 82 82 75 Interruptible contracts 51 95 95 95 95 - -------------------------------------------------------------------------------- Total power supply capacity 1,507 1,478 1,528 1,448 1,426 - -------------------------------------------------------------------------------- Reserve margin at peak 23% 16% 21% 17% 18% - -------------------------------------------------------------------------------- (1) The total load at peak is increased 25 MW in 2003, 2002, and 2001 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 2004 and 2000, summer cycler programs were not activated. The winter peak load for the 2003-2004 season of approximately 928 MW occurred on January 20, 2004. The prior year winter peak loadwas approximately 948 MW, occurring on January 27, 2003. 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. Such generating capacity is included in firm purchase supply in the chart above. Fuel Costs and Purchased Power Electric generation for 2004 was fueled by coal (95.6%) and natural gas (4.4%). 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 Vectren. Approximately 3.0 million tons of coal were purchased for generating electricity during 2004, of which substantially all was supplied by Vectren Fuels, Inc. from its mines and third party purchases. The average cost of coal consumed in generating electric energy for the years 2000 through 2004 follows: ------------------------------------------------------------------------------- Year Ended December 31, ------------------------------------------------------------- Avg. Cost Per 2004 2003 2002 2001 2000 ------- -------- ------- ------- -------- Ton $ 27.06 $ 24.91 $ 23.50 $ 22.48 $ 22.49 MWh 13.06 11.93 11.00 10.53 10.39 The Company also purchases 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 other wholesale customers. Volumes purchased in 2004 totaled 3,469,610 MWh. Competition The utility industry has undergone dramatic structural change for several years, resulting in increasing competitive pressures faced by electric and gas utility companies. 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. At December 31, 2004, approximately 73,000 customers in VUHI's Ohio service territory purchase natural gas from a supplier other than the regulated utility. Margin earned for transporting natural gas to those customers, who have purchased natural gas from another supplier, are generally the same as those earned by selling gas under Ohio tariffs. 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. 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 other environmental matters. Personnel As of December 31, 2004, the Company and its consolidated subsidiaries had 1566 employees, of which 872 are subject to collective bargaining arrangements. In July of 2004, the Company signed a three year labor agreement with Local 702 of the International Brotherhood of Electrical Workers, ending June 2007. The agreement provides a 3% wage increase in the first two years and a 3.5% increase in the third year of the agreement. The agreement also provides for improvements in pension benefits and a multi-tiered health plan in which the employees pay 16% of the cost. In January 2004, the Company signed a five year labor agreement, ending December 2008, with Local 1393 of the International Brotherhood of Electrical Workers and United Steelworkers of America Locals 12213 and 7441. The agreement provides for annual wage increases of 3%, a multi-tiered health care plan in which the employees pay 12% to 16% of the premium, and pension enhancements for early retirees. The Company's contract with Local 135 of the Teamsters, Chauffeurs, Warehousemen, and Helpers will expire in September 2005. The Company's contract with Local 175, Utility Workers Union of America will expire in October 2005. ITEM 2. PROPERTIES Gas Utility Services Indiana Gas owns and operates four active gas storage fields located in Indiana covering 58,130 acres of land with an estimated ready delivery from storage capability of 5.6 BCF of gas with maximum peak day delivery capabilities of 144,500 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 33,000 MCF of manufactured gas per day. In addition to its company owned storage and propane capabilities, Indiana Gas has contracted for 17.8 BCF of storage with a maximum peak day delivery capability of 299,717 MMBTU per day. Indiana Gas' gas delivery system includes 12,150 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 6.3 BCF of gas with maximum peak day delivery capabilities of 108,000 MCF per day. In addition to its company owned storage delivery capabilities, SIGECO has contracted for 0.5 BCF of storage with a maximum peak day delivery capability of 19,166 MMBTU per day. SIGECO's gas delivery system includes 3,074 miles of distribution and transmission mains, all of which are located in Indiana. The Ohio operations own and operate three liquefied petroleum (propane) air-gas manufacturing plants and a cavern for propane storage, all of which are located in Ohio. The plants and cavern can store 7.5 million gallons of propane, and the plants can manufacture for delivery 51,047 MCF of manufactured gas per day. In addition to its propane delivery capabilities, the Ohio operations have contracted for 13.4 BCF of storage with a maximum peak day delivery capability of 287,684 MMBTU per day. The Ohio operations' gas delivery system includes 5,301 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, 2004, 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, 50 MW and Broadway Avenue Unit 2, 65 MW); two Northeast Gas Turbines located northeast of Evansville in Vanderburgh County, Indiana with a combined capacity of 20 MW; and an 80 MW 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 830 circuit miles of 138,000 and 69,000 volt lines. The transmission system also includes 28 substations with an installed capacity of 4,635.9 megavolt amperes (Mva). The electric distribution system includes 3,223 pole miles of lower voltage overhead lines and 302 trench miles of conduit containing 1,688 miles of underground distribution cable. The distribution system also includes 92 distribution substations with an installed capacity of 1,901.7 Mva and 51,630 distribution transformers with an installed capacity of 2,388.8 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. 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. See the notes to the consolidated financial statements regarding commitments and contingencies, environmental matters, and rate and regulatory matters. The consolidated financial statements are included in "Item 8 Financial Statements and Supplementary Data." 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 COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES Common Stock Market Price All of the outstanding shares of VUHI's common stock are owned by Vectren. VUHI's common stock is not traded. There are no outstanding options or warrants to purchase VUHI's common equity or securities convertible into VUHI's common equity. Additionally, VUHI has no plans to publicly offer any of its common equity. Dividends Paid to Parent During 2004, VUHI paid dividends to its parent company of $20.0 million in the first quarter, $19.9 million in the second quarter, $21.1 million in the third quarter, and $19.6 million in the fourth quarter. During 2003, VUHI paid dividends to its parent company of $18.0 million in the first quarter, $18.2 million in the second quarter, $20.7 million in the third quarter, and $21.1 million in the fourth quarter. On January 26, 2005, the board of directors declared a $20.0 million dividend, payable to Vectren on February 28, 2005. 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. Debt Security The Company's 7 1/4% Senior Notes, due October 15, 2031, trade on the New York Stock Exchange under the symbol "AVU." The high and low sales prices for the Company's publicly traded debt security since issuance in October 2001 as reported on the New York Stock Exchange are shown in the following table for the periods indicated. Price Range Price Range ------------------------- ----------------------------------- 2004 High Low 2003 High Low ------------- --------- -------- -------- First Quarter $ 27.44 $ 26.25 First Quarter $ 26.60 $ 25.54 Second Quarter 27.03 24.05 Second Quarter 27.80 25.61 Third Quarter 26.81 23.03 Third Quarter 27.10 25.60 Fourth Quarter 27.00 26.06 Fourth Quarter 27.35 26.00 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. Year Ended December 31, - ------------------------------------------------------------------------------------------------------------ (In millions) 2004 2003 2002 2001 (1) 2000 (2,3) - ------------------------------------------------------------------------------------------------------------ Operating Data: Operating revenues $ 1,498.0 $ 1,448.8 $ 1,236.9 $ 1,328.3 $ 1,129.9 Operating income 198.2 199.0 207.7 131.4 136.1 Income before cumulative effect of change in accounting principle 83.1 85.6 97.1 43.7 55.9 Net income 83.1 85.6 97.1 44.8 55.9 Balance Sheet Data: Total assets $ 3,147.7 $ 2,925.1 $ 2,780.4 $ 2,489.3 $ 2,509.0 Redeemable preferred stock 0.1 0.2 0.3 0.5 8.1 Long-term debt - net of current maturities & debt subject to tender 941.3 960.5 841.2 900.9 572.6 Common shareholder's equity 985.4 979.8 768.6 738.9 624.3
(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 ($7.7 million after tax). The Company incurred restructuring charges of $15.0 million, ($9.3 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 $32.7 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 $44.1 million ($31.6 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. Executive Summary of Consolidated Results of Operations In 2004, Earnings were $83.1 million as compared to $85.6 million in 2003. The 2004 earnings decline is due to the impact of unfavorable weather, estimated at $5 million after tax. Margin growth, offsetting the weather impact, results from the recovery of NOx related environmental expenditures, gas base rate increases implemented in 2004, and customer growth. The primary expense changes were higher depreciation and lower bad debt expense in 2003. Bad debt expense in 2003 associated with the Ohio service territory was reversed and deferred for later recovery under an uncollectible accounts expense rider. The $11.5 million decrease in earnings occurring in 2003 compared to 2002 was primarily due to increased operating expenses and the write-off of an investment, partially offset by increased wholesale power margins and retail electric rate recovery related to NOx compliance expenditures. An increase in the Indiana state income tax rate to 8.5% from 4.5% also contributed to the decrease. During 2004 and 2003, the Company initiated base rate cases in its three gas service territories. Orders in its two Indiana service territories were received in the second half of 2004. An order in the Ohio territory is expected late in the first quarter of 2005. On an annual basis, the Indiana orders will increase margins an estimated $30 million, and during 2004 provided additional margin of $4.7 million. The Company has sought and received regulatory recovery mechanisms (trackers) affecting electric margin that provide a return on utility plant constructed for environmental compliance and that allow for recovery of related operating expenses. After tax earnings associated with the NOx compliance trackers totaled $9.0 million in 2004, $4.7 million in 2003 and $1.1 million in 2002. The Company has also utilized regulatory trackers affecting gas margin that recover, on a dollar-for-dollar basis, pipeline integrity management costs in its Indiana territories and uncollectible accounts expense, operating expenses related to choice implementation costs, and other costs in its Ohio service territory. VUHI generates revenue primarily from the delivery of natural gas and electric service to its customers. The primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services. Results are impacted by weather patterns in its service territory and general economic conditions both in its service territory as well as nationally. The Company has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of the Company's SEC filings. Significant Fluctuations Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin and Electric Utility margin could be considered non-GAAP measures of income. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas. Electric Utility margin is calculated as Electric utility revenues less Fuel for electric generation and Purchased electric energy. These measures exclude Other operating expenses, Depreciation and amortization, and Taxes other than income taxes, which are included in the calculation of operating income. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel costs can be volatile and are generally collected on a dollar for dollar basis from customers. Margins should not be considered an alternative to, or a more meaningful indicator of, operating performance than operating income or net income as determined in accordance with accounting principles generally accepted in the United States. Margin Margin generated from the sale of natural gas and electricity to residential and commercial customers is seasonal and impacted by weather patterns in the Company's service territories. Margin generated from sales to large customers (generally industrial, other contract, and firm wholesale customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas costs, and is also impacted by some level of price sensitivity in volumes sold. Electric generating asset optimization activities are primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability. Following is a discussion and analysis of margin generated from regulated utility operations. Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold) Gas Utility margin and throughput by customer type follows: Year Ended December 31, - -------------------------------------------------------------------------------- (In millions) 2004 2003 2002 - -------------------------------------------------------------------------------- Residential & Commercial $ 288.3 $ 292.3 $ 282.6 Contract 53.5 51.5 50.5 Other 5.9 6.0 4.1 - -------------------------------------------------------------------------------- Total gas utility margin $ 347.7 $ 349.8 $ 337.2 ================================================================================ Sold & transported volumes in MMDth: To residential & commercial customers 110.7 117.9 111.9 To contract customers 89.7 91.4 95.8 - -------------------------------------------------------------------------------- Total throughput 200.4 209.3 207.7 ================================================================================ Gas utility margins were $347.7 million for the year ended December 31, 2004. This represents a decrease in gas utility margin of $2.1 million compared to 2003. Heating weather for the year ended December 31, 2004, was 8% warmer than normal and 8% warmer than the prior year. The estimated unfavorable impact on gas utility margin caused by weather was approximately $9.8 million compared to 2003. Indiana base rate increases added $4.7 million compared to the prior year. Also offsetting the effects of weather were increased late and reconnect fees, expense recovery pursuant to Ohio regulatory trackers, and higher revenue taxes collected from rate payers. Gas sold and transported volumes were 4% less in 2004, compared to the prior year. The decreased throughput was primarily attributable to weather. The average cost per dekatherm of gas purchased was $6.92 in 2004; $6.36 in 2003, and $4.57 in 2002. Gas Utility margin for the year ended December 31, 2003, of $349.8 million increased $12.6 million, or 4%, compared to 2002. It is estimated that weather near normal for the year and 6% cooler than the prior year, contributed $8 million in increased residential and commercial margin and was the primary contributor to increased throughput compared to 2002. The remaining increase is primarily attributable to $4.5 million in higher revenue taxes on higher gas costs and volumes sold and $1.8 million in recovery of Ohio customer choice implementation costs. Electric Utility Margin (Electric Utility Revenues less Fuel for Electric Generation and Purchased Electric Energy) Electric Utility margin by revenue type follows: Year Ended December 31, - -------------------------------------------------------------------------------- (In millions) 2004 2003 2002 - -------------------------------------------------------------------------------- Residential & commercial $ 159.7 $ 141.1 $ 145.7 Industrial 62.4 53.5 54.9 Municipalities & other 17.4 20.1 16.9 - -------------------------------------------------------------------------------- Total retail & firm wholesale 239.5 214.7 217.5 Asset optimization 15.0 18.3 12.7 - -------------------------------------------------------------------------------- Total electric utility margin $ 254.5 $ 233.0 $ 230.2 ================================================================================ Retail & Firm Wholesale Margin Native load and firm wholesale margin was $239.5 million for the year ended December 31, 2004. This represents a $24.8 million increase over 2003. Additional NOx recoveries increased margin $14.6 million in 2004. Cooling weather for the year was 12% warmer than last year, increasing margin an estimated $2.0 million. The remaining increase in margin was attributable to increased small customer usage and increased sales to industrial customers. Due to the above factors, volumes sold increased 5% to 6.19 GWh for 2004, compared to 5.90 GWh in 2003. Volumes sold in 2002 were 6.19 GWh. For the year ended December 31, 2003, margin from serving native load and firm wholesale customers was $214.7 million, a decrease of $2.8 million when compared to 2002. It is estimated that summer weather, 19% cooler than normal and 34% cooler than 2002, caused an $8 million decrease in residential and commercial margin. The effect of weather was partially offset by a $7.4 million increase in retail electric rates related to recovery of and return on NOx compliance expenditures and related operating expenses. A slowly recovering economy continued to negatively impact industrial sales which decreased $1.4 million compared to 2002. As a result of primarily mild weather and slow economic conditions, retail and firm wholesale volumes sold decreased 5%. Margin from Asset Optimization Activities Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of the margin from these activities is generated from contracts that are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk. Following is a reconciliation of asset optimization activity: Year Ended December 31, - -------------------------------------------------------------------------------- (In millions) 2004 2003 2002 - -------------------------------------------------------------------------------- Beginning of Year Net Asset Optimization Position $ (0.4) $ (0.7) $ 3.3 Statement of Income Activity Mark-to-market gains (losses) recognized (1.4) 0.7 (3.6) Realized gains recognized 16.4 17.6 16.3 - -------------------------------------------------------------------------------- Net activity in electric utility margin 15.0 18.3 12.7 - -------------------------------------------------------------------------------- Net cash received & other adjustments (15.2) (18.0) (16.7) - -------------------------------------------------------------------------------- End of Year Net Asset Optimization Position $ (0.6) $ (0.4) $ (0.7) ================================================================================ Net wholesale margins decreased $3.3 million compared to 2003 due to reduced available capacity. The availability of excess capacity was impacted by scheduled outages of owned generation, related to the installation of environmental compliance equipment and an increase in demand by native load customers due to both weather and increased usage. The $5.6 million increase in 2003 compared to 2002 was primarily due to price volatility and additional capacity due to weather. Operating Expenses Other Operating Other operating expenses increased $8.4 million for the year ended December 31, 2004 as compared to 2003. Expense in 2003 reflects the deferral of $4.0 million relating to the Ohio order allowing the Company to defer for future recovery its actual bad debt expense in excess of the amount provided in base rates (See Rate and Regulatory Matters below). Other factors contributing to the increase were an increase in NOx-related expenses of $2.6 million recovered in rates and planned turbine maintenance of $1.9 million. Other operating expense increased $11.5 million in 2003 compared to 2002. The increase was principally caused by increased distribution, plant, and transmission operating expenses; power plant and other maintenance; customer service initiatives; higher insurance premiums; and prior year insurance recoveries. In addition, operating expenses reflect $1.8 million in amortization of Ohio choice implementation costs, which are recovered through increased gas utility margin. The increase in operating expenses was partially offset by the impact of an Ohio regulatory order, which resulted in the reversal and deferral of 2003 uncollectible accounts expense of $4.0 million for future recovery. Depreciation & Amortization For the year ended December 31, 2004, depreciation expense increased $9.9 million compared to 2003. NOx-related depreciation contributed $4.8 million of the increase with the remaining increase due primarily to normal additions to utility plant. The increase of $7.2 million in 2003 compared to 2002 is also due to normal additions to utility plant. In addition to the NOx scrubbers placed into service in 2004, other significant expenditures included upgrades of electric facilities subjected to storm damage, construction of a new substation, and a new transmission main. Upgrades implemented in 2002 and 2003 now included in annual depreciation expense include a gas-fired peaker unit, expenditures for implementing a choice program for Ohio gas customers, customer system upgrades, and other upgrades to existing transmission and distribution facilities. Taxes Other Than Income Taxes Taxes other than income taxes increased $1.6 million in 2004 compared to 2003 and $5.9 million in 2003 compared to 2002. Almost all of the 2004 increase and $4.5 million of the 2003 increase corresponds with increased collections of utility receipts and excise taxes due to higher revenues. The remaining 2003 increase results principally from higher property taxes. Other Income (Expense) Total other income (expense)-net increased $1.1 million during 2004 compared to 2003 and decreased $1.0 million during 2003 compared to 2002. Lower amounts of AFUDC were recorded in 2004 as NOx expenditures were placed in service. Fiscal year 2003 includes operating losses and the write-off of investments in an entity that processes fly ash, totaling $4.2 million. In 2002, the Company recognized losses associated with those investments totaling $1.5 million. Interest Expense In the second half of 2003, the Company completed permanent financing transactions in which approximately $366 million in equity, debt, and hedging net proceeds were received and used to retire higher coupon long-term debt and other short term borrowings. The changes in interest expense in 2004 and 2003 reflect the full impact of that transaction. Income Taxes For the year ended December 31, 2004, income taxes were relatively consistent with 2003 with decreased earnings offset by a slightly higher effective rate. An increase in the Indiana state income tax rate from 4.5% to 8.5% was the primary reason for increased tax expense in 2003 compared to 2002. 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 oxide (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 with which to comply. Clean Air Act NOx SIP Call Matter The Company has taken steps to comply with Indiana's State Implementation Plan (SIP) of the Clean Air Act (the Act). 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 currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required. The IURC has issued orders that approve: o the Company's project to achieve environmental compliance by investing in clean coal technology; o a total capital cost investment for this project up to $244 million (excluding AFUDC), subject to periodic review of the actual costs incurred; o a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and o ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service. Based on the level of system-wide emissions reductions required and the control technology utilized to achieve the reductions, the current estimated construction cost is consistent with amounts approved in the IURC's orders. Through December 31, 2004, $238 million has been expended, and three of the four SCR's are operational. Once all equipment is installed and operational, related annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million. The Company is recovering the operational costs associated with the SCR's and related technology. The 8% return on capital investment approximates the return authorized in the Company's last electric rate case in 1995 and includes a return on equity. The Company has achieved timely compliance through the reduction of 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 During 2003, the U.S. District Court for the Southern District of Indiana entered a consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley Generating Station for (1) making modifications to generating station without obtaining required permits, (2) making major modifications to the generating station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications. Under the terms of the agreement, the DOJ and USEPA agreed to drop all challenges of past maintenance and repair activities at the Culley Generating Station. In reaching the agreement, SIGECO did not admit to any allegations in the government's complaint, and SIGECO continues to believe that it acted in accordance with applicable regulations and conducted only routine maintenance on the units. SIGECO entered into this agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation. Under the agreement, SIGECO committed to o either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR control technology for further reduction of nitrogen oxide, or cease operation of the unit by December 31, 2006; o operate the existing SCR control technology recently installed on Culley Unit 3 (287 MW) year round at a lower emission rate than that currently required under the NOx SIP Call, resulting in further nitrogen oxide reductions; o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions; o install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007; o conduct a Sulphuric Acid Reduction Demonstration Project as an environmental mitigation project designed to demonstrate an advance in pollution control technology for the reduction of sulfate emissions; and o pay a $600,000 civil penalty. The Company notified the USEPA of its intention to shut down Culley Unit 1 effective December 31, 2006. The Company does not believe that implementation of the settlement will have a material effect to it results from operations or financial condition. The $600,000 civil penalty was expensed and paid during 2003 and is reflected in Other-net. Information Request On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Clean Air Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested with the most recent correspondence provided on March 26, 2001. Manufactured Gas Plants In the past, Indiana Gas, SIGECO, 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, SIGECO, 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 (VRP) 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 VRP. 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 been initiated by the Company to confirm that the sites continue to pose no such risk. On October 6, 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program. The total investigative costs, and if necessary, costs of remediation at the four SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot be determined at this time. Jacobsville Superfund Site On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. Vectren's property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the Vectren property contains lead contaminated soils. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils. At this time, Vectren anticipates only additional soil testing, if required by the USEPA. 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 the IURC. The retail gas operations of the Ohio operations are subject to regulation by the PUCO. All metered gas rates in Indiana contain a gas cost adjustment (GCA) clause, and all metered gas rates in Ohio contain a gas cost recovery (GCR) clause. GCA and GCR clauses allow the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause (FAC) that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an agreed upon benchmark, is also recovered through regulatory proceedings. Rate structures in the Company's territories 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. GCA, GCR, and FAC procedures involve periodic filings and IURC and PUCO hearings to establish the amount of price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between the estimated cost of gas, cost of fuel, and net energy cost of purchased power and actual costs incurred. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in margin. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The IURC has also applied the statute authorizing GCA and FAC 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. For the recent past, the earnings test has not affected the Company's ability to recover costs, and the Company does not anticipate the earnings test will restrict recovery in the near future. SIGECO and Indiana Gas Base Rate Settlements On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO's gas distribution business, and on November 30, 2004, approved a $24 million base rate increase for Indiana Gas' gas distribution business. The new rate designs include a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in SIGECO's service territory was implemented on July 1, 2004, resulting in additional 2004 revenues of $2.5 million. The base rate change in Indiana Gas' service territory was implemented on December 1, 2004, resulting in additional 2004 revenues of $2.2 million. The orders also permit SIGECO and Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these annual caps are to be deferred for future recovery. VEDO Pending Base Rate Increase Settlement On February 4, 2005, the Company filed with the PUCO a settlement agreement that had been entered into with several parties, including the PUCO staff, in its base rate case. The Ohio Office of the Consumer Counselor (OCC) is opposing the settlement. Earlier in 2004 VEDO had filed with the PUCO a request to adjust its base rates and charges for its gas distribution business serving more than 315,000 customers located in west central Ohio. The settlement provides for a $15.7 million increase in VEDO's base distribution rates to cover the ongoing costs of operating, maintaining, and expanding the approximately 5,200-mile distribution system. The settlement increase includes $1.1 million of funding for weatherization and conservation programs for low income customers. Evidentiary hearings were completed in the case on February 9, 2005. Review and approval by the PUCO is necessary before the settlement is effective. The proposed new rate design includes a larger service charge, which will address, to some extent, earnings volatility related to weather. The settlement also permits VEDO the annual recovery of on-going costs associated with the Pipeline Safety Improvement Act of 2002. Based upon the PUCO's actions in other proceedings, the Company would expect an order near the end of the first quarter of 2005. Ohio Uncollectible Accounts Expense Tracker On December 17, 2003, the PUCO approved a request by VEDO and several other regulated Ohio gas utilities to establish a mechanism to recover uncollectible account expense outside of base rates. The tariff mechanism establishes an automatic adjustment procedure to track and recover these costs instead of providing the recovery of the historic amount in base rates. Through this order, VEDO received authority to defer its 2003 uncollectible accounts expense to the extent it differs from the level included in base rates. The Company estimated the difference to approximate $4 million in excess of that included in base rates, and reversed and deferred that amount for future recovery. In 2004, the Company recorded revenues of $3.3 million which is equal to the level of uncollectible accounts expense recognized for Ohio customers. Gas Cost Recovery (GCR) Audit Proceedings There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of their gas acquisition practices in connection with the gas cost recovery (GCR) mechanism. In the case of VEDO, a two-year audit period ended in November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The external auditor retained by the PUCO staff submitted an audit report in the fall of 2003 wherein it recommended a disallowance of approximately $7 million of previously recovered gas costs. The Company believes a large portion of the third party auditor recommendations is without merit. A hearing has been held, and the PUCO staff has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has recommended an $11.5 million disallowance. For this PUCO audit period, any disallowance relating to the Company's ProLiance arrangement will be shared by the Company's joint venture partner. Based on a review of the matters, the Company has recorded $1.1 million for its estimated share of a potential disallowance. A PUCO decision on this matter is yet to be issued. The Company is also unable to determine the effects that a PUCO decision for the audit period ended in November 2002 may have on results in audit periods beginning after November 2002. Other Operating Matters MISO 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 MISO is committed to reliability, the nondiscriminatory operation of the bulk power transmission system, and to working with all stakeholders to create cost-effective and innovative solutions. The Carmel, Indiana, based MISO began operations in December 2001 and serves the electrical transmission needs of much of the Midwest. 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. Pursuant to an order from the IURC, certain MISO costs have been deferred for future recovery. During 2004, SIGECO together with three other Indiana electric utilities filed a proceeding with the IURC seeking to recover the anticipated costs associated with MISO's implementation of the "Day 2 energy market" on April 1, 2005. A hearing considering this request occurred in February, 2005. 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, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO's policies regarding use of transmission facilities, as well as ongoing FERC initiatives and uncertainties around the "Day 2 energy market" operations, it is difficult to predict near term operational impacts. However, as stated above, it is believed that MISO's regional operation of the transmission system will ultimately lead to reliability improvements. 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. United States Securities and Exchange Commission Inquiry into PUCHA Exemption In July 2004, the Company received a letter from the SEC regarding its exempt status under the Public Utility Holding Company Act of 1935 (PUHCA). The letter asserts that the Company's out of state electric power sales exceed the amount previously determined by the SEC to be acceptable in order to qualify for the exemption. There is pending a request by Vectren and VUHI for an order of exemption under Section 3(a)(1) of PUHCA. Vectren and VUHI also claim the benefit of the exemption pursuant to Rule 2 under Section 3(a)(1) of PUHCA by filing an annual statement on SEC Form U-3A-2. The Company has responded to the SEC inquiry and filed an amended Form U-3A-2 for the year ended December 31, 2003. The amendment changed the method of aggregating wholesale power sales and purchases outside of Indiana from that previously reported. The new method is to aggregate by delivery point. The amendment also submitted clarifications as to activity outside of Indiana related to gas utility operations. Critical Accounting Policies Management is required to make judgments, 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 judgment. These include the estimates to perform goodwill and other asset impairments tests. The Company makes other estimates in the course of accounting for unbilled revenue, the effects of regulation, and intercompany allocations 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. 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 13 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 in 2004, 2003, and 2002 and therefore resulted in no impairment. Estimating fair value using a discounted cash flow model is subjective and requires significant judgment 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 would have resulted in no impairment charge. Impairment Review of Investments The Company will occasionally make equity investments in companies and notes receivable convertible into equity interests. 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. An impairment analysis of equity method investments involves comparison of the investment's estimated fair value to its carrying amount. Fair value is estimated using primarily discounted cash flow analyses. Calculating free cash flows and fair value is subjective and requires judgment concerning growth assumptions, longevity of cash flows, and discount rates (for fair value calculations). As a result of such tests, a $3.9 million dollar write-off of investments in an entity that processes fly ash resulted in 2003. No impairments were recorded in 2004. 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, the method these estimates are derived from is 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 judgment 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. Intercompany Allocations Support Services Vectren and certain subsidiaries of Vectren provide corporate, general, and administrative services to the Company including legal, finance, tax, risk management, and human resources, which includes charges for share-based compensation and for pension and other postretirement benefits not directly charged to subsidiaries. These costs have been allocated using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are based on cost. Management believes that the allocation methodology is reasonable and approximates the costs that would have been incurred had the Company secured those services on a stand-alone basis. The allocation methodology is not subject to near term changes. Pension and Other Postretirement Obligations Vectren satisfies the future funding requirements of its pension and other postretirement plans and the payment of benefits from general corporate assets. An allocation of expense is determined by Vectren's actuaries, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date, which occurs on September 30. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the SFAS 87/106 liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Management believes these direct charges when combined with benefit-related corporate charges discussed in "support services" above approximate costs that would have been incurred if the Company accounted for benefit plans on a stand-alone basis. Vectren 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 pension and postretirement plans. Vectren used the following weighted average assumptions to develop 2004 periodic benefit cost: a discount rate of 6.0%, an expected return on plan assets of 8.5%, a rate of compensation increase of 3.5%, and a health care cost trend rate of 10% in 2004 declining to 5% in 2009. During 2004, Vectren reduced the discount rate by 25 basis points to value 2004 ending pension and postretirement obligations due to a decline in benchmark interest rates. In addition, Vectren used the following weighted average assumptions to develop 2004 periodic benefit cost: a discount rate of 6.0%, an expected return on plan assets of 8.5%, a rate of compensation increase of 3.5%, and a health care cost trend rate of 10% in 2004 declining to 5% in 2009. In January 2005, Vectren announced the amendment of certain postretirement benefit plans, effective January 1, 2006. The amendment will result in a decrease of allocated costs that may approximate $3 million annually, a portion of which will be recognized in 2005. Two of the unions that represent bargaining employees at the Company's regulated subsidiaries have advised Vectren that it is their position that these changes are not permitted under the existing collective bargaining agreements which govern the relationship between the employees and the affected subsidiaries. With assistance from legal counsel, management has analyzed the unions' position and continues to believe that the Company has reserved the right to amend the affected plans and that changing these benefits for retirees is not a mandatory subject of bargaining. Future changes in health care costs, work force demographics, interest rates, or plan changes could significantly affect the estimated cost of these future benefits. Impact of Recently Issued Accounting Guidance SFAS 123 (revised 2004) In December 2004, the FASB issued Statement 123 (revised 2004), "Share-Based Payments" (SFAS 123R) that will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces FASB Statement No. 123, "Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25, "Accounting for Stock Issued to Employees." The effective date of SFAS 123R for the Company is July 1, 2005. SFAS 123R provides for multiple transition methods, and the Company is still evaluating potential methods for adoption. VUHI does not have share-based compensation plans separate from Vectren. An insignificant number of VUHI's employees participate in Vectren's share-based compensation plans. The adoption of this standard is not expected to have any material effect on the Company's operating results or financial condition. Financial Condition Within Vectren's consolidated group, VUHI, the parent company, funds short-term and long-term financing needs of the utility group operations. Vectren 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. The guarantees are full and unconditional and joint and several, and VUHI has no subsidiaries other than the subsidiary guarantors. VUHI's long-term and short-term obligations outstanding at December 31, 2004, totaled $550.0 million and $308.0 million, respectively. Additionally, prior to VUHI's formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations. VUHI's operations have historically funded almost all of Vectren's common stock dividends. VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at December 31, 2004, are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor's) and Moody's Investors Service (Moody's), respectively. SIGECO's credit ratings on outstanding senior unsecured debt are BBB+/Baa1. SIGECO's credit ratings on outstanding secured debt are A-/A3. VUHI's commercial paper has a credit rating of A-2/P-2. The ratings of Moody's and Standard and Poor's are categorized as investment grade and are unchanged from December 31, 2003. Moody's current outlook is stable. During January 2005, Standard and Poor's changed its current outlook to stable from negative. 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 50-55% of permanent 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 operations. The Company's equity component was 51% and 50% of permanent capitalization at December 31, 2004, and 2003, respectively. Permanent capitalization includes long-term debt, including current maturities and debt subject to tender, as well as common shareholders' equity and any outstanding preferred stock. The Company expects the majority of its capital expenditures, investments, and debt security redemptions to be provided by internally generated funds. However, due to significant capital expenditures, the Company may require additional permanent financing. 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 $85.1 million during the year ended December 31, 2004, compared to 2003 primarily as a result of favorable changes in working capital accounts and increased earnings before non-cash charges. Cash flow from operating activities decreased during the year ended December 31, 2003, compared to 2002 by $108.4 million. The primary reason for this change was favorable changes in working capital accounts occurring in 2002 due to lower gas prices in that year and higher gas prices in 2003. 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. Additionally, short-term borrowings are required for capital projects and investments until they are permanently financed. Cash flow required for financing activities of $7.4 million for the year ended December 31, 2004, includes a net increase of short-term borrowings of $123.1 million and the net retirement of $38.1 million of long-term debt. Cash flow provided by financing activities of $64.5 million for the year ended December 31, 2003, includes the effects of the permanent financing executed during the current year in which approximately $407 million in capital contributions from Vectren, third party debt proceeds, and hedging net proceeds were received and used to retire higher coupon long-term debt and other short term borrowings. Common stock dividends paid to Vectren have increased in 2004 compared to 2003 and in 2003 compared to 2002. VUHI Debt Issuance In March 2003, Vectren filed a registration statement with the Securities and Exchange Commission with respect to a public offering of authorized but previously unissued shares of common stock as well as senior unsecured notes of VUHI. In July 2003, VUHI issued senior unsecured notes with an aggregate principal amount of $200 million in two $100 million tranches. The first tranche was 10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746% to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year notes due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity (2018 Notes). The notes are guaranteed by VUHI's three public utilities: SIGECO, Indiana Gas, and VEDO. These guarantees are full and unconditional and joint and several. In addition, they have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by VUHI, 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 20 basis points for the 2013 Notes and 25 basis points for the 2018 Notes. Shortly before these issues, VUHI entered into several treasury locks with a total notional amount of $150.0 million. Upon issuance of the debt, the treasury locks were settled resulting in the receipt of $5.7 million in cash, which was recorded as a regulatory liability pursuant to existing regulatory orders. The value received is being amortized as a reduction of interest expense over the life of the issues. The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $203 million and were used to repay short-term borrowing and to retire long-term debt with higher interest rates. Additional Capital Contributions During 2003, the Company received a $204.1 million equity contribution from Vectren. Vectren funded $163.2 million of the contribution with proceeds from an offering of its common stock, $35.0 million was funded by Vectren's nonregulated operations, and $5.9 million was funded by new share issues from Vectren's dividend reinvestment plan. These proceeds were used by VUHI and VUHI's subsidiaries to repay short-term borrowings and to retire long-term debt with higher interest rates. Long-Term Debt Put & Call Provisions 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. During 2004, 2003, and 2002, debt totaling $2.5 million, $0.1 million, and $5.2 million, respectively, was put to the Company. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities. SIGECO and Indiana Gas Debt Call During 2004, the Company called $20.0 million of insured quarterly senior unsecured notes outstanding at Indiana Gas. The notes, originally due in 2015, were called at par. During 2003, the Company called two first mortgage bonds outstanding at SIGECO and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond had a principal amount of $45.0 million, an interest rate of 7.60%, was originally due in 2023, and was redeemed at 103.745% of its stated principal amount. The second SIGECO bond had a principal amount of $20.0 million, an interest rate of 7.625%, was originally due in 2025, and was redeemed at 103.763% of the stated principal amount. The first Indiana Gas note had a remaining principal amount of $21.3 million, an interest rate of 9.375%, was originally due in 2021, and was redeemed at 105.525% of the stated principal amount. The second Indiana Gas note had a principal amount of $13.5 million, an interest rate of 6.75%, was originally due in 2028, and was redeemed at the principal amount. Pursuant to regulatory authority, the premiums paid to retire these notes totaling $3.6 million were deferred as a regulatory asset. Other Financing Transactions During 2004, the Company remarketed two first mortgage bonds outstanding at SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate debt into variable rate debt where interest rates reset weekly. One bond, due in 2023, had a principal amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015, had a principal amount of $10.0 million and an interest rate of 4.3%. These remarketing efforts resulted in the extinguishment and reissuance of debt at generally the same par value. At December 31, 2002, the Company had $26.6 million of adjustable rate senior unsecured bonds which could, at the election of the bondholder, be tendered to the Company when interest rates are reset. Such bonds were classified as Long-term debt subject to tender. During 2003, the Company re-marketed $4.6 million of the bonds through 2020 at a 4.5% fixed interest rate and remarketed $22.0 million of the bonds through 2030 at a 5.0% fixed interest rate. Additionally, during 2003, the Company re-marketed $22.5 million of first mortgage bonds subject to interest rate exposure on a long term basis. The $22.5 million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest rate. Other Company debt totaling $15.0 million in 2004, $18.5 million in 2003, and $6.5 million in 2002 was retired as scheduled. Investing Cash Flow Cash flow required for investing activities was $264.1 million in 2004, $236.1 million in 2003, and $218.7 million in 2002. Capital expenditures are the primary component of investing activities. Capital expenditures were $267.6 million in 2004 compared to $235.0 million in 2003 and $217.3 million in 2002. The increases are primarily driven by expenditures for environmental compliance. Available Sources of Liquidity At December, 31, 2004, the Company has $355 million of short-term borrowing capacity, of which approximately $47 million is available. VUHI's short-term credit facility was renewed on June 24, 2004 at $350 million, a slight increase from the previous year's renewal level of $346 million. Instead of the traditional 364-day facility, the facility was renewed for a 5-year period ending June 2009. Vectren periodically issues new shares to satisfy dividend reinvestment plan and stock option plan requirements and contributes those proceeds to VUHI. During 2004 and 2003, these new issuances added additional liquidity of $3.1 million and $5.9 million, respectively. Potential & Future Uses of Liquidity Contractual Obligations The following is a summary of contractual obligations at December 31, 2004: - --------------------------------------------------------------------------------------------------------- (In millions) 2005 2006 2007 2008 2009 Thereafter - --------------------------------------------------------------------------------------------------------- Long-term debt (1) $ - $ - $ 6.5 $ - $ - $ 949.1 Short-term debt 308.3 - - - - Commodity firm purchase commitments 99.1 - - - - - Utility & nonutility plant purchase commitments (2) 20.5 - - - - - --------------------------------------------------------------------------------------------------------- Total $427.9 $ - $ 6.5 $ - $ - $ 949.1 =========================================================================================================
(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 2004 (in millions) is $10.0 in 2005, zero in 2006, $20.0 in 2007, zero in 2008, $80.0 in 2009, and $40.0 thereafter. (2) The settlement period of these obligations is estimated. Planned Capital Expenditures The timing and amount of capital expenditures, including contractual purchase commitments discussed above, for the five-year period 2005 - 2009 are estimated as follows (in millions): $205.2 in 2005, $219.4 in 2006, $259.2 in 2007, $251.9 in 2008, and $206.4 in 2009. Pension and Postretirement Funding Obligations Vectren believes making contributions to its qualified pension plans in the coming years will be necessary. Management currently estimates that the qualified pension plans will require Company contributions in the range of $5 million to $10 million in both 2005 and 2006. VUHI may be called upon to fund a portion of these contributions. During 2004, Vectren funded $7.7 million in contributions of which $4.6 million in contributions were funded by VUHI. 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 include, 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, commodity prices, 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 Direct or indirect effects on our business, financial condition or liquidity resulting from a change in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries. o Employee or contractor 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. The Company also executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and optimizing its generation assets. The Company has in place a risk management committee that consists of senior management as well as financial and operational management. The committee is actively involved in identifying risks as well as reviewing and authorizing risk mitigation strategies. 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 the cost of such purchases through natural gas and fuel cost adjustment mechanisms. Electric sales and purchases in the wholesale power market and sales of electricity to certain municipalities and large industrial customers are exposed to commodity price risk associated with fluctuating commodity prices. Open positions in terms of price, volume, and specified delivery points may occur and are managed using methods described below with frequent management reporting. The Company's wholesale power marketing activities include asset optimization strategies that manage the utilization of available electric generating capacity. Execution of asset optimization strategies require entering into energy 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 accounts for asset optimization contracts that are derivatives at fair value with the offset marked to market through earnings. Sales to certain municipalities and large industrial customers are executed to meet customer demand. Price risk from forward positions obligating the Company to deliver commodities is mitigated using generating capability and offsetting forward purchase contracts. These contracts are expected to be settled by physical receipt or delivery of the commodity. Market risk resulting from commodity contracts is measured by management using the potential impact on pre-tax earnings caused by the effect a 10% adverse change in forward commodity prices might have on market sensitive derivative positions outstanding on specific dates. For the years ended December 31, 2004, and 2003, a 10% adverse change in forward commodity prices would have decreased earnings by $0.7 million and $3.0 million, respectively, based upon open positions existing on the last day of those years. Interest Rate Risk The Company is exposed to interest rate risk associated with its borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense. The Company manages this risk by allowing 20% and 30% of its total debt to be exposed to short-term interest rate volatility. However, there are times when this targeted range of interest rate exposure may not be attained. To manage this exposure, the Company may use derivative financial instruments. At December 31, 2004, such debt obligations, as affected by seasonal increases in short-term debt outstanding, represented 27% of the Company's total debt portfolio. 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. During 2004 and 2003, the weighted average combined borrowings under these arrangements were $142.7 million and $226.9 million, respectively. At December 31, 2004, and 2003, combined borrowings under these arrangements were $340.7 million and $185.2 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2004 and 2003, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $1.4 million and $2.3 million, respectively. 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. 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. The Company mitigates these risks by executing derivative contracts that manage the price of forecasted natural gas purchases. These contracts are subject to regulation, which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholder and Board of Directors of Vectren Utility Holdings, Inc.: We have audited the accompanying consolidated balance sheets of Vectren Utility Holdings, Inc. and subsidiaries (the "Company") as of December 31, 2004 and 2003, and the related consolidated statements of income, shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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 Utility Holdings, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. /s/ DELOITTE & TOUCHE LLP - ----------------------------------------------- DELOITTE & TOUCHE LLP Indianapolis, Indiana February 23, 2005 VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (In millions) At December 31, - -------------------------------------------------------------------------------- 2004 2003 - -------------------------------------------------------------------------------- ASSETS Current Assets Cash & cash equivalents $ 5.7 $ 8.1 Accounts receivable - less reserves of $1.9 & $3.1, respectively 147.5 114.0 Receivables due from other Vectren companies 4.0 1.7 Accrued unbilled revenues 161.2 128.7 Inventories 53.0 55.1 Recoverable fuel & natural gas costs 17.7 20.3 Prepayments & other current assets 138.2 131.3 - -------------------------------------------------------------------------------- Total current assets 527.3 459.2 - -------------------------------------------------------------------------------- Utility Plant Original cost 3,465.2 3,250.7 Less: accumulated depreciation & amortization 1,309.0 1,247.0 - -------------------------------------------------------------------------------- Net utility plant 2,156.2 2,003.7 - -------------------------------------------------------------------------------- Investments in unconsolidated affiliates 0.2 1.8 Other investments 19.6 20.6 Non-utility property - net 149.6 141.3 Goodwill - net 205.0 205.0 Regulatory assets 82.5 89.6 Other assets 7.3 3.9 - -------------------------------------------------------------------------------- TOTAL ASSETS $ 3,147.7 $ 2,925.1 ================================================================================ The accompanying notes are an integral part of these consolidated financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS (In millions) At December 31, - -------------------------------------------------------------------------------- 2004 2003 - -------------------------------------------------------------------------------- LIABILITIES & SHAREHOLDER'S EQUITY Current Liabilities Accounts payable $ 97.3 $ 63.0 Accounts payable to affiliated companies 98.8 80.3 Payables to other Vectren companies 15.8 13.3 Accrued liabilities 116.3 93.9 Short-term borrowings 308.3 185.2 Current maturities of long-term debt - 15.0 Long-term debt subject to tender 10.0 13.5 - -------------------------------------------------------------------------------- Total current liabilities 646.5 464.2 - -------------------------------------------------------------------------------- Long-Term Debt - Net of Current Maturities & Debt Subject to Tender 941.3 960.5 Deferred Income Taxes & Other Liabilities Deferred income taxes 240.8 201.5 Regulatory liabilities 251.7 235.0 Deferred credits & other liabilities 81.9 83.9 - -------------------------------------------------------------------------------- Total deferred credits & other liabilities 574.4 520.4 - -------------------------------------------------------------------------------- Commitments & Contingencies (Notes 8 - 10) Cumulative, Redeemable Preferred Stock of a Subsidiary 0.1 0.2 Common Shareholder's Equity Common stock (no par value) 592.9 589.8 Retained earnings 392.5 390.0 - -------------------------------------------------------------------------------- Total common shareholder's equity 985.4 979.8 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 3,147.7 $ 2,925.1 ================================================================================ The accompanying notes are an integral part of these consolidated financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME (In millions) Year Ended December 31, - -------------------------------------------------------------------------------- 2004 2003 2002 - -------------------------------------------------------------------------------- OPERATING REVENUES Gas utility $ 1,126.2 $ 1,112.3 $ 908.0 Electric utility 371.3 335.7 328.6 Other 0.5 0.8 0.3 - -------------------------------------------------------------------------------- Total operating revenues 1,498.0 1,448.8 1,236.9 - -------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 778.5 762.5 570.8 Fuel for electric generation 96.1 86.5 81.6 Purchased electric energy 20.7 16.2 16.8 Other operating 218.5 210.1 198.6 Depreciation & amortization 127.8 117.9 110.7 Taxes other than income taxes 58.2 56.6 50.7 - -------------------------------------------------------------------------------- Total operating expenses 1,299.8 1,249.8 1,029.2 - -------------------------------------------------------------------------------- OPERATING INCOME 198.2 199.0 207.7 OTHER INCOME (EXPENSE) Other - net 5.2 4.8 7.1 Equity in losses of unconsolidated affiliates 0.2 (0.5) (1.8) - -------------------------------------------------------------------------------- Total other income 5.4 4.3 5.3 - -------------------------------------------------------------------------------- Interest expense 67.4 66.1 69.1 - -------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 136.2 137.2 143.9 - -------------------------------------------------------------------------------- Income taxes 53.1 51.6 46.8 - -------------------------------------------------------------------------------- NET INCOME $ 83.1 $ 85.6 $ 97.1 ================================================================================ The accompanying notes are an integral part of these consolidated financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In millions) Year Ended December 31, - ---------------------------------------------------------------------------------------------- 2004 2003 2002 - ---------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 83.1 $ 85.6 $ 97.1 Adjustments to reconcile net income to cash from operating activities: Depreciation & amortization 127.8 117.9 110.7 Deferred income taxes & investment tax credits 43.0 24.1 (23.4) Pension & postretirement periodic benefit cost 5.7 5.9 6.5 Equity in losses (earnings) of unconsolidated affiliates (0.2) 0.5 1.8 Net unrealized (gain) loss on derivative instruments 1.4 (0.7) 3.6 Other non-cash charges - net 10.0 10.7 8.4 Changes in working capital accounts: Accounts receivable, including to Vectren companies & accrued unbilled revenue (79.0) 44.3 (28.1) Inventories 1.6 0.9 (1.2) Recoverable fuel & natural gas costs 2.6 (1.0) 48.1 Prepayments & other current assets (7.0) (49.1) (9.4) Accounts payable, including to Vectren companies & affiliated companies 55.3 (73.6) 73.2 Accrued liabilities 21.9 12.6 0.1 Changes in noncurrent assets (1.9) (5.9) (1.2) Changes in noncurrent liabilities (10.0) (3.0) (8.6) - ---------------------------------------------------------------------------------------------- Net cash flows from operating activities 254.3 169.2 277.6 - ---------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt - net of issuance costs & hedging proceeds 32.4 202.9 - Additional capital contribution 3.1 204.1 - Requirements for: Dividends to parent (80.6) (78.0) (69.7) Retirement of long-term debt, including premiums paid (70.5) (121.9) (6.5) Redemption of preferred stock of subsidiary (0.1) (0.1) (0.2) Net change in short-term borrowings, including from other Vectren companies 123.1 (140.8) 22.8 Other activity - (1.7) - - ---------------------------------------------------------------------------------------------- Net cash flows from financing activities 7.4 64.5 (53.6) - ---------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from other investing activities 3.5 - 10.4 Requirements for: Capital expenditures, excluding AFUDC equity (267.6) (235.0) (217.3) Unconsolidated affiliate & other investments - (1.1) (11.8) - ---------------------------------------------------------------------------------------------- Net cash flows from investing activities (264.1) (236.1) (218.7) - ---------------------------------------------------------------------------------------------- Net (decrease) increase in cash & cash equivalents (2.4) (2.4) 5.3 Cash & cash equivalents at beginning of period 8.1 10.5 5.2 - ---------------------------------------------------------------------------------------------- Cash & cash equivalents at end of period $ 5.7 $ 8.1 $ 10.5 ============================================================================================== Cash paid during the year for: Interest $ 65.0 $ 60.7 $ 58.4 Income taxes 6.1 52.2 63.3
The accompanying notes are an integral part of these consolidated financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (In millions) - ---------------------------------------------------------------------------------------------- Accumulated Other Common Retained Comprehensive Stock Earnings Income (Loss) Total - ---------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------- Balance at January 1, 2002 $ 385.7 $ 355.0 $ (1.8) $ 738.9 - ---------------------------------------------------------------------------------------------- Comprehensive income: Net income 97.1 97.1 Minimum pension liability adjustments & other - net of tax 2.3 2.3 - ---------------------------------------------------------------------------------------------- Total comprehensive income 99.4 - ---------------------------------------------------------------------------------------------- Common stock dividends (69.7) (69.7) - ---------------------------------------------------------------------------------------------- Balance at December 31, 2002 385.7 382.4 0.5 768.6 - ---------------------------------------------------------------------------------------------- Comprehensive income: Net income 85.6 85.6 Other comprehensive income adjustment - net of tax (0.5) (0.5) - ---------------------------------------------------------------------------------------------- Total comprehensive income 85.1 - ---------------------------------------------------------------------------------------------- Common stock: Additional capital contribution 204.1 204.1 Dividends (78.0) (78.0) - ---------------------------------------------------------------------------------------------- Balance at December 31, 2003 589.8 390.0 - 979.8 ============================================================================================== Net income and comprehensive income 83.1 83.1 Common stock: Additional capital contribution 3.1 3.1 Dividends (80.6) (80.6) - ---------------------------------------------------------------------------------------------- Balance at December 31, 2004 $ 592.9 $ 392.5 $ - $ 985.4 ==============================================================================================
The accompanying notes are an integral part of these consolidated financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Nature of Operations Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation, serves as the intermediate holding company for Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas Company, Inc. (Indiana Gas), Southern Indiana Gas and Electric Company (SIGECO), and the Ohio operations. VUHI also has assets that provide information technology and other services to the utilities. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana. 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 energy delivery services to approximately 555,000 natural gas customers located in central and southern Indiana. SIGECO provides energy delivery services to approximately 136,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. Indiana Gas and SIGECO generally do business as Vectren Energy Delivery of Indiana. The Ohio operations provide energy delivery services to approximately 315,000 natural gas customers located near Dayton in west central Ohio. The Ohio operations are owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc. (VEDO), a wholly owned subsidiary, (53% ownership) and Indiana Gas (47% ownership). The Ohio operations generally do business as Vectren Energy Delivery of Ohio. 2. Summary of Significant Accounting Policies A. Principles of Consolidation The accompanying consolidated financial statements for periods prior to January 1, 2003, reflect the Company on a historical basis as restated for the effects of the combination of entities under common control whereby certain information technology systems and related assets and buildings were transferred from other entities within Vectren's consolidated group to VUHI effective January 1, 2003. The consolidated financial statements include the accounts of the Company and its wholly owned and majority owned subsidiaries, after elimination of significant intercompany transactions. For the year ended December 31, 2002, operating income and net income attributable to the contributed assets were $8.5 million and $3.5 million, respectively. For the year ended December 31, 2002, operating income and net income attributable to VUHI's operations before the contribution were $199.2 million and $93.6 million, respectively. 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. C. Inventories Inventories consist of the following: At December 31, - ----------------------------------------------------------------------------- (In millions) 2004 2003 - ----------------------------------------------------------------------------- Materials & supplies $ 22.2 $ 19.3 Gas in storage - at LIFO cost 18.9 21.9 Fuel (coal & oil) for electric generation 8.8 10.7 Gas in storage - at average cost - 2.5 Other 3.1 0.7 - ----------------------------------------------------------------------------- Total inventories $ 53.0 $ 55.1 ============================================================================= 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, 2004, and 2003, by approximately $56.4 million and $52.2 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 rates, which include a cost of removal component, are established through regulatory proceedings and are applied to all in-service utility plant. 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) 2004 2003 - ---------------------------------------------------------------------------------------- Depreciation Depreciation Rates as a Rates as a Percent of Percent of Original Cost Original Cost Original Cost Original Cost - ---------------------------------------------------------------------------------------- Gas utility plant $ 1,793.6 3.5% $ 1,721.9 3.6% Electric utility plant 1,458.1 3.6% 1,322.4 3.4% Common utility plant 44.2 2.7% 44.3 2.7% Construction work in progress 169.3 - 162.1 - - ---------------------------------------------------------------------------------------- Total original cost $ 3,465.2 $ 3,250.7 ========================================================================================
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. AFUDC 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) 2004 2003 2002 - ----------------------------------------------------------------------------- AFUDC - borrowed funds $ 1.6 $ 2.1 $ 3.1 AFUDC - equity funds 1.6 2.9 2.2 - ----------------------------------------------------------------------------- Total AFUDC capitalized $ 3.2 $ 5.0 $ 5.3 ============================================================================= 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 remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation. Costs to dismantle and remove retired property are charged against Regulatory liabilities, where the cost of removal obligation is classified in these financial statements. E. Non-utility Property 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 $73.3 million and $57.0 million as of December 31, 2004, and 2003, respectively. For the years ended December 31, 2004 and 2003, the Company capitalized interest totaling $1.4 million and $0.9 million, respectively, on non-utility plant construction projects. Capitalized interest in 2002 was not significant. 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 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 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 business combinations is accounted for in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company adopted SFAS 142 on January 1, 2002. SFAS 142 requires a portion of goodwill be charged to expense only when it is impaired. The Company tests its goodwill for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. Impairment reviews consist 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. Through December 31, 2004, no goodwill impairments have been recorded. All of the Company's goodwill is included in the Gas Utility Services operating segment. 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 expenditures by the Company for removal costs or 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) 2004 2003 - ------------------------------------------------------------------------------ Future amounts recoverable from ratepayers: Income taxes $ 11.5 $ 18.1 Other 1.0 1.0 - ------------------------------------------------------------------------------ 12.5 19.1 Amounts deferred for future recovery: Demand side management programs 25.9 25.0 Other 7.3 5.3 - ------------------------------------------------------------------------------ 33.2 30.3 Amounts currently recovered through base rates: Unamortized debt issue costs 20.4 21.4 Premiums paid to reacquire debt 7.0 7.4 Demand side management programs 2.3 2.7 Rate case expenses 1.2 - - ------------------------------------------------------------------------------ 30.9 31.5 Amounts currently recovered through tracking mechanisms: Ohio authorized trackers 6.3 7.5 Indiana authorized trackers (0.4) 1.2 - ------------------------------------------------------------------------------ 5.9 8.7 - ------------------------------------------------------------------------------ Total regulatory assets $ 82.5 $ 89.6 ============================================================================== Of the $30.9 million currently being recovered through base rates charged to customers, $29.7 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered is 13.9 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable. Regulatory liabilities consist of the following: At December 31, - ------------------------------------------------------------------------------ (In millions) 2004 2003 - ------------------------------------------------------------------------------ Cost of removal $ 246.2 $ 228.8 Interest rate hedging proceeds (See Note 11) 5.5 6.2 - ------------------------------------------------------------------------------ Total regulatory liabilities $ 251.7 $ 235.0 ============================================================================== Cost of Removal and SFAS 143 The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. The Company records amounts expensed in advance of payments as a regulatory liability because the liability does not meet the threshold of a legal asset retirement obligation (ARO) as defined by SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of a liability for a legal ARO 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. To the extent regulation is involved, such gain or loss may be deferred. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company's results of operations. 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 contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an agreed upon benchmark, is also recovered through regulatory proceedings. 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 Shareholder's Equity. The principal transaction resulting in other comprehensive income relates to a minimum pension liability adjustment. In 2002, all such liabilities were transferred to Vectren. In 2003, the remaining component of accumulated other comprehensive income relating to a cash flow hedge was reclassified to a regulatory liability in accordance with regulatory orders. The effects of hedging arrangements are further discussed in Note 11. 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 Utility Receipts Taxes Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues, which totaled $38.3 million in 2004, $37.1 million in 2003, and $32.4 million in 2002. Excise and utility receipts taxes paid are recorded as a component of Taxes other than income taxes. L. Earnings Per Share Earnings per share are not presented as VUHI's common stock is wholly owned by Vectren. M. Other Significant Policies Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 3) and derivatives (Note 11). N. 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. Transactions with Other Vectren Companies Support Services and Purchases Vectren and certain subsidiaries of Vectren provided corporate and general and administrative services to the Company including legal, finance, tax, risk management, human resources, which includes charges for restricted stock compensation and for pension and other postretirement benefits not directly charged to subsidiaries. These costs have been allocated using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are based on cost. VUHI received corporate allocations totaling $44.5 million, $43.4 million, and $41.4 million for the years ended December 31, 2004, 2003, and 2002, respectively. Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases fuel used for electric generation. Amounts paid for such purchases for the years ended December 31, 2004, 2003, and 2002, totaled $79.0 million, $77.0 million, and $62.1 million, respectively. Retirement Plans and Other Postretirement Benefits Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 87 "Employers' Accounting for Pensions" and SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions," respectively. An allocation of expense is determined by Vectren's actuaries, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the SFAS 87/106 liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with "multiemployer" benefit accounting as described in SFAS 87 and 106. For the years ended December 31, 2004, 2003, and 2002, periodic pension costs totaling $4.8 million, $5.0 million, and $5.5 million, respectively, was directly charged by Vectren to the Company. For the years ended December 31, 2004, 2003, and 2002, other periodic postretirement benefit costs totaling $0.9 million, $0.9 million, and $1.0 million, respectively, was directly charged by Vectren to the Company. As of December 31, 2004 and 2003, $49.8 million and $52.7 million, respectively, is included in Deferred credits & other liabilities and represents expense directly charged to the Company that is yet to be funded to Vectren, and $2.4 million and $2.2 million, respectively, is included in Other assets for amounts funded in advance to Vectren. Cash Management Arrangements The Company participates in a centralized cash management program with Vectren, other wholly owned subsidiaries, and banks which permits funding of checks as they are presented. Share-Based Incentive Plans In December 2004, the FASB issued Statement 123 (revised 2004), "Share-Based Payments" (SFAS 123R) that will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces FASB Statement No. 123, "Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25, "Accounting for Stock Issued to Employees." The effective date of SFAS 123R for the Company is July 1, 2005. SFAS 123R provides for multiple transition methods, and the Company is still evaluating potential methods for adoption. VUHI does not have share-based compensation plans separate from Vectren. An insignificant number of VUHI's employees participate in Vectren's share-based compensation plans. The adoption of this standard is not expected to have any material effect on the Company's operating results or financial condition. Income Taxes Vectren and subsidiary companies file a consolidated federal income tax return. For financial reporting purposes, VUHI's current and deferred tax expense is computed on a separate company basis. A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, - ------------------------------------------------------------------------------ 2004 2003 2002 - ------------------------------------------------------------------------------ Statutory rate 35.0 % 35.0 % 35.0 % State and local taxes-net of federal benefit 5.2 5.4 1.3 Amortization of investment tax credit (1.6) (1.6) (1.7) All other - net 0.4 (1.2) (2.3) - ------------------------------------------------------------------------------ Effective tax rate 39.0 % 37.6 % 32.3 % ============================================================================== The components of income tax expense and utilization of investment tax credits follow: Year Ended December 31, - ----------------------------------------------------------------------------- (In millions) 2004 2003 2002 - ----------------------------------------------------------------------------- Current: Federal $ 3.7 $ 15.0 $ 62.5 State 6.4 12.5 7.7 - ----------------------------------------------------------------------------- Total current taxes 10.1 27.5 70.2 - ----------------------------------------------------------------------------- Deferred: Federal 40.6 27.4 (16.2) State 4.6 (1.1) (4.9) - ----------------------------------------------------------------------------- Total deferred taxes 45.2 26.3 (21.1) - ----------------------------------------------------------------------------- Amortization of investment tax credits (2.2) (2.2) (2.3) - ----------------------------------------------------------------------------- Total income tax expense $ 53.1 $ 51.6 $ 46.8 ============================================================================= 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) 2004 2003 - ----------------------------------------------------------------------------- Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 253.4 $ 208.7 Regulatory assets recoverable through future rates 19.2 26.9 Regulatory liabilities to be settled through future rates (7.7) (8.8) Employee benefit obligations (21.5) (22.7) Other - net (2.6) (2.6) - ----------------------------------------------------------------------------- Net noncurrent deferred tax liability 240.8 201.5 - ----------------------------------------------------------------------------- Current deferred tax liabilities: Deferred fuel costs - net 4.5 6.9 - ----------------------------------------------------------------------------- Net current deferred tax liability 4.5 6.9 - ----------------------------------------------------------------------------- Net deferred tax liability $ 245.3 $ 208.4 ============================================================================= At December 31, 2004 and 2003, investment tax credits totaling $14.2 million and $16.4 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. 4. Transactions with Vectren Affiliates 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 the Company's utilities, Citizens Gas, and others. ProLiance's primary business is optimizing the gas portfolios of utilities and providing services to large end use customers. Transactions with ProLiance Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2004, 2003, and 2002, totaled $789.8 million, $770.7 million, and $542.5 million, respectively. Amounts owed to ProLiance at December 31, 2004 and 2003, for those purchases were $97.7 million and $79.9 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. As part of a settlement agreement approved by the IURC during July 2002, the gas supply agreements with Indiana Gas and SIGECO, were approved and extended through March 31, 2007. The utilities may decide to conduct a "request for proposal" (RFP) for a new supply administrator, or they may decide to make an alternative proposal for procurement of gas supply. That decision will be made by December 2005. To the extent an RFP is conducted, ProLiance has the opportunity, if it so elects, to participate in the RFP process for service to the utilities after March 31, 2007. Other Affiliate Transactions Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that perform underground construction and repair, facilities locating, and meter reading services to the Company. For the years ended December 31, 2004, 2003, and 2002, fees for these services and construction-related expenditures paid by the Company to Vectren affiliates totaled $31.2 million, $37.2 million, and $38.3 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates other than ProLiance totaled $1.1 million and $0.4 million at December 31, 2004, and 2003, respectively, and are included in Accounts payable to affiliated companies in the Consolidated Balance Sheets. 5. Borrowing Arrangements Short-Term Borrowings At December, 31, 2004, the Company has $355 million of short-term borrowing capacity, of which approximately $47 million is available. VUHI's short-term credit facility was renewed on June 24, 2004 at $350 million, a slight increase from the previous year's renewal level of $346 million. Instead of the traditional 364-day facility, the facility was renewed for a 5-year period ending June 2009. See the table below for interest rates and outstanding balances. Year Ended December 31, - ------------------------------------------------------------------------------- (In millions) 2004 2003 2002 - ------------------------------------------------------------------------------- Weighted average commercial paper and bank loans outstanding during the year $ 133.2 $ 219.5 $ 155.7 Weighted average interest rates during the year Commercial paper 1.78% 1.36% 2.61% Bank loans 2.19% 1.86% 2.02% At December 31, - ------------------------------------------------------------------- (In millions) 2004 2003 - ------------------------------------------------------------------- Commercial paper $ 308.0 $ 184.4 Bank loans 0.3 0.8 - ------------------------------------------------------------------- Total short-term borrowings $ 308.3 $ 185.2 =================================================================== Prior to the asset transfer discussed in Note 2, the operations integrated with VUHI relied on the borrowing arrangements of Vectren Capital Corp, a wholly owned subsidiary of Vectren, for its working capital needs. Interest expense incurred on these borrowing arrangements for the year ended December 31, 2002, totaled $3.0 million. Long-Term Debt Senior unsecured obligations and first mortgage bonds outstanding and classified as long-term by subsidiary follow: At December 31, - ------------------------------------------------------------------------------- (In millions) 2004 2003 - ------------------------------------------------------------------------------- VUHI Fixed Rate Senior Unsecured Notes 2011, 6.625% $ 250.0 $ 250.0 2013, 5.25% 100.0 100.0 2018, 5.75% 100.0 100.0 2031, 7.25% 100.0 100.0 - ------------------------------------------------------------------------------- Total VUHI 550.0 550.0 - ------------------------------------------------------------------------------- SIGECO First Mortgage Bonds 2016, 1986 Series, 8.875% 13.0 13.0 2023, Series B, adjustable rate presently 2.08%, tax exempt, auction rate mode, weighted average for 2004: 4.44% 22.6 22.8 2029, 1999 Senior Notes, 6.72% 80.0 80.0 2015, 1985 Pollution Control Series A, adjustable rate presently 2.03%, tax exempt, auction rate mode, weighted average for 2004: 3.09% 9.8 10.0 2025, 1998 Pollution Control Series A, adjustable rate presently 4.75%, tax exempt, next rate adjustment: 2006 31.5 31.5 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt 22.5 22.5 - ------------------------------------------------------------------------------- Total first mortgage bonds 179.4 179.8 - ------------------------------------------------------------------------------- Senior Unsecured Bonds to Third Parties: 2020, 1998 Pollution Control Series B, 4.50%, tax exempt 4.6 4.6 2030, 1998 Pollution Control Series B, 5.00%, tax exempt 22.0 22.0 2030, 1998 Pollution Control Series C, adjustable rate presently 5.00%, tax exempt, next rate adjustment: 2006 22.2 22.2 - ------------------------------------------------------------------------------- Total senior unsecured bonds 48.8 48.8 - ------------------------------------------------------------------------------- Total SIGECO 228.2 228.6 - ------------------------------------------------------------------------------- Indiana Gas Senior Unsecured Notes 2004, Series F, 6.36% - 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 2015, Series E, 6.69% 5.0 5.0 2015, Series E, 6.69% 10.0 10.0 2025, Series E, 6.53% 10.0 10.0 2027, Series E, 6.42% 5.0 5.0 2027, Series E, 6.68% 1.0 3.5 2027, Series F, 6.34% 20.0 20.0 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 49.9 - ------------------------------------------------------------------------------- Total Indiana Gas 177.4 214.9 - ------------------------------------------------------------------------------- At December 31, - ------------------------------------------------------------------------------- (In millions) 2004 2003 - ------------------------------------------------------------------------------- Total long-term debt outstanding 955.6 993.5 Current maturities of long-term debt - (15.0) Debt subject to tender (10.0) (13.5) Unamortized debt premium & discount - net (4.6) (4.9) Other 0.3 0.4 - ------------------------------------------------------------------------------- Total long-term debt-net $ 941.3 $ 960.5 =============================================================================== VUHI 2003 Issuance In July 2003, VUHI issued senior unsecured notes with an aggregate principal amount of $200 million in two $100 million tranches. The first tranche was 10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746% to yield 5.28% to maturity (2013 Notes). The second tranche was 15-year notes due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity (2018 Notes). The notes have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by VUHI, 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 20 basis points for the 2013 Notes and 25 basis points for the 2018 Notes. Shortly before these issues, VUHI entered into several treasury locks with a total notional amount of $150.0 million. Upon issuance of the debt, the treasury locks were settled resulting in the receipt of $5.7 million in cash, which was recorded as a regulatory liability pursuant to existing regulatory orders. The value received is being amortized as a reduction of interest expense over the life of the issues. The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $203 million. Long-Term Debt Put & Call Provisions Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. 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. During 2004, 2003, and 2002, debt totaling $2.5 million, $0.1 million, and $5.2 million, respectively, was put to the Company. Debt which may be put to the Company during the years following 2004 (in millions) is $10.0 in 2005, zero in 2006, $20.0 in 2007, zero in 2008, $80.0 in 2009, and $40.0 thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities. SIGECO and Indiana Gas Debt Call During 2004, the Company called $20.0 million of insured quarterly senior unsecured notes outstanding at Indiana Gas. The notes, originally due in 2015, were called at par. During 2003, the Company called two first mortgage bonds outstanding at SIGECO and two senior unsecured notes outstanding at Indiana Gas. The first SIGECO bond had a principal amount of $45.0 million, an interest rate of 7.60%, was originally due in 2023, and was redeemed at 103.745% of its stated principal amount. The second SIGECO bond had a principal amount of $20.0 million, an interest rate of 7.625%, was originally due in 2025, and was redeemed at 103.763% of the stated principal amount. The first Indiana Gas note had a remaining principal amount of $21.3 million, an interest rate of 9.375%, was originally due in 2021, and was redeemed at 105.525% of the stated principal amount. The second Indiana Gas note had a principal amount of $13.5 million, an interest rate of 6.75%, was originally due in 2028, and was redeemed at the principal amount. Pursuant to regulatory authority, the premiums paid to retire the net carrying value of these notes totaling $3.6 million were deferred in Regulatory assets. Other Financing Transactions During 2004, the Company remarketed two first mortgage bonds outstanding at SIGECO. The remarketing effort converted $32.8 million of outstanding fixed rate debt into variable rate debt where interest rates reset weekly. One bond, due in 2023, had a principal amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015, had a principal amount of $10.0 million and an interest rate of 4.3%. These remarketing efforts resulted in the extinguishment of debt and the reissuance of new debt at generally the same par value. These bonds are classified in Long-term debt. During 2003, the Company remarketed $26.6 million of adjustable rate senior unsecured bonds and $22.5 million of adjustable rate first mortgage bonds. Of the remarketed unsecured bonds, $4.6 million were placed through 2020 at a 4.5% fixed interest rate, $22.0 million were placed through 2030 at a 5.0% fixed interest rate, and the $22.5 million first mortgage bonds were placed through 2024 at a 4.65% fixed interest rate. These bonds are classified in Long-term debt. Other Company debt totaling $15.0 million in 2004, $18.5 million in 2003, and $6.5 million in 2002 was retired as scheduled. Future Long-Term Debt Sinking Fund Requirements & Maturities The annual sinking fund requirement of SIGECO's first mortgage bonds is one percent 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 2005 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2005 is excluded from Current liabilities in the Consolidated Balance Sheets. At December 31, 2004, $563.9 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. SIGECO's gross utility plant balance subject to the Mortgage Indenture approximated $1.8 billion at December 31, 2004. Consolidated maturities and sinking fund requirements on long-term debt during the five years following 2004 (in millions) are zero in 2005 and in 2006, $6.5 in 2007, and zero in 2008 and in 2009. 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, 2004, the Company was in compliance with all financial covenants. 6. Cumulative Preferred Stock of Subsidiary Currently outstanding 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, 2004, and 2003, there were 1,177 shares and 2,277 shares outstanding, respectively. 7. Additional Capital Contributions During the years ended December 31, 2004 and 2003, the Company received $3.1 million and $204.1 million, respectively, in equity contributions from Vectren. The 2004 contribution and $5.9 million of the 2003 contribution was funded by new share issues from Vectren's dividend reinvestment plan. Vectren funded $163.2 million of the 2003 contribution with proceeds from an offering of its common stock and the remaining $35.0 million was funded by Vectren's nonregulated operations. 8. Commitments & Contingencies Commitments Firm purchase commitments for commodities total $99.1 million in 2005. Firm purchase commitment for utility and non-utility plant total $20.5 million. Securities & Exchange Commission Inquiry into PUCHA Exemption In July 2004, the Company received a letter from the SEC regarding its exempt status under the Public Utility Holding Company Act of 1935 (PUHCA). The letter asserts that the Company's out of state electric power sales exceed the amount previously determined by the SEC to be acceptable in order to qualify for the exemption. There is pending a request by Vectren and VUHI for an order of exemption under Section 3(a)(1) of PUHCA. Vectren and VUHI also claim the benefit of the exemption pursuant to Rule 2 under Section 3(a)(1) of PUHCA by filing an annual statement on SEC Form U-3A-2. The Company has responded to the SEC inquiry and filed an amended Form U-3A-2 for the year ended December 31, 2003. The amendment changed the method of aggregating wholesale power sales and purchases outside of Indiana from that previously reported. The new method is to aggregate by delivery point. The amendment also submitted clarifications as to activity outside of Indiana related to gas utility operations. 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. 9. Environmental Matters Clean Air Act NOx SIP Call Matter The Company has taken steps to comply with Indiana's State Implementation Plan (SIP) of the Clean Air Act (the Act). 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 currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required. The IURC has issued orders that approve: o the Company's project to achieve environmental compliance by investing in clean coal technology; o a total capital cost investment for this project up to $244 million (excluding AFUDC), subject to periodic review of the actual costs incurred; o a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and o ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service. Based on the level of system-wide emissions reductions required and the control technology utilized to achieve the reductions, the current estimated construction cost is consistent with amounts approved in the IURC's orders. Through December 31, 2004, $238 million has been expended, and three of the four SCR's are operational. Once all equipment is installed and operational, related annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million. The Company is recovering the operational costs associated with the SCR's and related technology. The 8% return on capital investment approximates the return authorized in the Company's last electric rate case in 1995 and includes a return on equity. The Company has achieved timely compliance through the reduction of 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 During 2003, the U.S. District Court for the Southern District of Indiana entered a consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley Generating Station for (1) making modifications to generating station without obtaining required permits, (2) making major modifications to the generating station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications. Under the terms of the agreement, the DOJ and USEPA agreed to drop all challenges of past maintenance and repair activities at the Culley Generating Station. In reaching the agreement, SIGECO did not admit to any allegations in the government's complaint, and SIGECO continues to believe that it acted in accordance with applicable regulations and conducted only routine maintenance on the units. SIGECO entered into this agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation. Under the agreement, SIGECO committed to o either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR control technology for further reduction of nitrogen oxide, or cease operation of the unit by December 31, 2006; o operate the existing SCR control technology recently installed on Culley Unit 3 (287 MW) year round at a lower emission rate than that currently required under the NOx SIP Call, resulting in further nitrogen oxide reductions; o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions; o install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007; o conduct a Sulphuric Acid Reduction Demonstration Project as an environmental mitigation project designed to demonstrate an advance in pollution control technology for the reduction of sulfate emissions; and o pay a $600,000 civil penalty. The Company notified the USEPA of its intention to shut down Culley Unit 1 effective December 31, 2006. The Company does not believe that implementation of the settlement will have a material effect to its results from operations or financial condition. The $600,000 civil penalty was accrued during 2003 and is reflected in Other-net. Information Request On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Clean Air Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested with the most recent correspondence provided on March 26, 2001. Manufactured Gas Plants In the past, Indiana Gas, SIGECO, 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, SIGECO, 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 (VRP) 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 VRP. 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 been initiated by the Company to confirm that the sites continue to pose no such risk. On October 6, 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program. The total investigative costs, and if necessary, costs of remediation at the four SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot be determined at this time. Jacobsville Superfund Site On July 22, 2004, the USEPA listed the Jacobsville Neighborhood Soil Contamination site in Evansville, Indiana, on the National Priorities List under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The USEPA has identified four sources of historic lead contamination. These four sources shut down manufacturing operations years ago. When drawing up the boundaries for the listing, the USEPA included a 250 acre block of properties surrounding the Jacobsville neighborhood, including Vectren's Wagner Operations Center. Vectren's property has not been named as a source of the lead contamination, nor does the USEPA's soil testing to date indicate that the Vectren property contains lead contaminated soils. Vectren's own soil testing, completed during the construction of the Operations Center, did not indicate that the Vectren property contains lead contaminated soils. At this time, Vectren anticipates only additional soil testing, if required by the USEPA. 10. Rate & Regulatory Matters SIGECO and Indiana Gas Base Rate Settlements On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO's gas distribution business, and on November 30, 2004, approved a $24 million base rate increase for Indiana Gas' gas distribution business. The new rate designs include a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in SIGECO's service territory was implemented on July 1, 2004, resulting in additional 2004 revenues of $2.5 million. The base rate change in Indiana Gas' service territory was implemented on December 1, 2004, resulting in additional 2004 revenues of $2.2 million. The orders also permit SIGECO and Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter for SIGECO and $2.5 million per year for Indiana Gas. Any costs incurred in excess of these annual caps are to be deferred for future recovery. VEDO Pending Base Rate Increase Settlement On February 4, 2005, the Company filed with the PUCO a settlement agreement that had been entered into with several parties, including the PUCO staff, in its base rate case. The Ohio Office of the Consumer Counselor (OCC) is opposing the settlement. Earlier in 2004 VEDO had filed with the PUCO a request to adjust its base rates and charges for its gas distribution business serving more than 315,000 customers located in west central Ohio. The settlement provides for a $15.7 million increase in VEDO's base distribution rates to cover the ongoing costs of operating, maintaining, and expanding the approximately 5,200-mile distribution system. The settlement increase includes $1.1 million of funding for weatherization and conservation programs for low income customers. Evidentiary hearings were completed in the case on February 9, 2005. Review and approval by the PUCO is necessary before the settlement is effective. The proposed new rate design includes a larger service charge, which will address, to some extent, earnings volatility related to weather. The settlement also permits VEDO the annual recovery of on-going costs associated with the Pipeline Safety Improvement Act of 2002. Based upon the PUCO's actions in other proceedings, the Company would expect an order near the end of the first quarter of 2005. Ohio Uncollectible Accounts Expense Tracker On December 17, 2003, the PUCO approved a request by VEDO and several other regulated Ohio gas utilities to establish a mechanism to recover uncollectible account expense outside of base rates. The tariff mechanism establishes an automatic adjustment procedure to track and recover these costs instead of providing the recovery of the historic amount in base rates. Through this order, VEDO received authority to defer its 2003 uncollectible accounts expense to the extent it differs from the level included in base rates. The Company estimated the difference to approximate $4 million in excess of that included in base rates, and reversed and deferred that amount for future recovery. In 2004, the Company recorded revenues of $3.3 million which is equal to the level of uncollectible accounts expense recognized for Ohio residential customers. Gas Cost Recovery (GCR) Audit Proceedings There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of their gas acquisition practices in connection with the gas cost recovery (GCR) mechanism. In the case of VEDO, a two-year audit period ended in November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The external auditor retained by the PUCO staff submitted an audit report in the fall of 2003 wherein it recommended a disallowance of approximately $7 million of previously recovered gas costs. The Company believes a large portion of the third party auditor recommendations is without merit. A hearing has been held, and the PUCO staff has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has recommended an $11.5 million disallowance. For this PUCO audit period, any disallowance relating to the Company's ProLiance arrangement will be shared by the Company's joint venture partner. Based on a review of the matters, the Company has recorded $1.1 million for its estimated share of a potential disallowance. A PUCO decision on this matter is yet to be issued. The Company is also unable to determine the effects that a PUCO decision for the audit period ended in November 2002 may have on results in audit periods beginning after November 2002. 11. Derivatives & Other Financial Instruments Accounting Policy for Derivatives The Company executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. The Company accounts for its derivative contracts in accordance with SFAS 133, "Accounting for Derivatives" and its related amendments and interpretations. In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met. When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale, it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives 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. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its 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 or as an adjustment to the underlying's basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company's use of mark-to-market accounting in three primary areas: asset optimization, natural gas procurement, and interest rate management. Asset Optimization Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of the margin from these activities is generated from contracts that are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk. Contracts with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. Asset optimization contracts are recorded at market value. Asset optimization contracts recorded at market value at December 31, 2004, totaled $2.5 million of Prepayments & other current assets and $3.1 million of Accrued liabilities, compared to $2.4 million of Prepayments & other current assets and $2.8 million of Accrued liabilities at December 31, 2003. The proceeds received and paid upon settlement of both purchase and sale contracts along with changes in market value of open contracts are recorded in Electric utility revenues. The change in market value is a function of the normal decline in market value as earnings are realized and the fluctuation in market value resulting from price volatility. Net revenues from asset optimization activities totaled $23.8 million in 2004, $26.5 million in 2003, and $23.3 million in 2002. Natural Gas Procurement Activity 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. Although Vectren'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. The Company mitigates these risks by executing derivative contracts that manage the price of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. At December 31, 2004 and 2003, the market values of these contracts were not significant. Interest Rate Management The Company is exposed to interest rate risk associated with its borrowing arrangements. Its risk management program seeks to reduce the potentially adverse effects that market volatility may have on interest expense. The Company has used interest rate swaps and treasury locks to hedge forecasted debt issuances and other interest rate swaps to manage interest rate exposure. Hedging instruments are recorded at market value. Changes in market value, when effective, are recorded in Accumulated other comprehensive income for cash flow hedges, as an adjustment to the outstanding debt balance for fair value hedges, or as regulatory asset/liability when regulation is involved. Amounts are recorded to interest expense as settled. At December 31, 2004, approximately $5.5 million remains in Regulatory liabilities related to future interest payments. Of the existing regulatory liability, $0.6 million will be reclassified to earnings in 2005, $0.6 million was reclassified to earnings in 2004, and $0.3 million was reclassified to earnings during 2003. Fair Value of Other Financial Instruments The carrying values and estimated fair values of the Company's other financial instruments follow: At December 31, - ----------------------------------------------------------------------- 2004 2003 ------------------- -------------------- In millions Carrying Est. Fair Carrying Est. Fair Amount Value Amount Value - ---------------------------- ----------------------------------------- Long-term debt $ 955.6 $ 1,108.9 $ 993.5 $ 1,056.8 Short-term borrowings 308.3 308.3 185.2 185.2 Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt 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 results of operations. 12. Additional Operational & Balance Sheet Information Prepayments and other current assets in the Consolidated Balance Sheets consist of the following: At December 31, - ------------------------------------------------------------- (In millions) 2004 2003 - ------------------------------------------------------------- Prepaid gas delivery service $116.9 $ 97.6 Prepaid taxes 12.3 26.8 Other prepayments & current assets 9.0 6.9 - ------------------------------------------------------------- Total prepayments & other current assets $138.2 $131.3 ============================================================= Accrued liabilities in the Consolidated Balance Sheets consist of the following: At December 31, - ------------------------------------------------------------- (In millions) 2004 2003 - ------------------------------------------------------------- Refunds to customers & customer deposits $ 31.0 $ 24.5 Accrued taxes 27.6 29.4 Accrued interest 15.1 15.7 Refundable gas costs 6.3 - Deferred income taxes 4.5 6.9 Accrued salaries & other 31.8 17.4 - ------------------------------------------------------------- Total accrued liabilities $116.3 $ 93.9 ============================================================= Other - net in the Consolidated Statements of Income consists of the following: Year Ended December 31, - ----------------------------------------------------------------------------- (In millions) 2004 2003 2002 - ----------------------------------------------------------------------------- AFUDC & capitalized interest $ 4.6 $ 5.9 $ 5.3 Interest income 0.5 0.6 0.8 Gains on sale of investments & assets 0.6 - 1.8 Other income 0.8 3.3 1.5 Other expense (1.3) (5.0) (2.3) - ----------------------------------------------------------------------------- Total other - net $ 5.2 $ 4.8 $ 7.1 ============================================================================= 13. Segment Reporting The Company's operations consist of regulated operations and other operations that provide information technology and other support services to those regulated operations. The Company segregates its regulated operations into a Gas Utility Services operating segment and an Electric Utility Services operating segment. The Gas Utility Services segment provides natural gas distribution and transportation services to nearly two-thirds of Indiana and to west central Ohio. The Electric Utility Services segment provides electric distribution services primarily to southwestern Indiana, and includes the Company's power generating and marketing operations. The Company cross manages its regulated operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and marketing operations. For these regulated operations the Company uses after tax operating income as a measure of profitability, consistent with regulatory reporting requirements. For the Utility Group's other operations, net income is used as the measure of profitability. In total, there are three operating segments as defined by SFAS 131 "Disclosure About Segments of an Enterprise and Related Information" (SFAS 131). Information related to the Company's business segments is summarized below: Year Ended December 31, - ----------------------------------------------------------------------------------- (In millions) 2004 2003 2002 - ----------------------------------------------------------------------------------- Revenues Gas Utility Services $ 1,126.2 $ 1,112.3 $ 908.0 Electric Utility Services 371.3 335.7 328.6 Other Operations 32.9 26.5 22.4 Eliminations (32.4) (25.7) (22.1) - ----------------------------------------------------------------------------------- Total revenues $ 1,498.0 $ 1,448.8 $ 1,236.9 =================================================================================== Profitability Measure Regulated Operating Income (Operating Income Less Applicable Income Taxes) Gas Utility Services $ 70.9 $ 74.9 $ 80.7 Electric Utility Services 65.6 63.8 73.2 - ----------------------------------------------------------------------------------- Total regulated operating income 136.5 138.7 153.9 - ----------------------------------------------------------------------------------- Regulated other income - net 2.1 5.1 5.1 Regulated interest expense & preferred dividends (62.7) (62.0) (63.7) - ----------------------------------------------------------------------------------- Regulated Net Income 75.9 81.8 95.3 - ----------------------------------------------------------------------------------- Other Operations Net Income 7.2 3.8 1.8 - ----------------------------------------------------------------------------------- Net Income $ 83.1 $ 85.6 $ 97.1 ===================================================================================
Year Ended December 31, - ----------------------------------------------------------------------------------- (In millions) 2004 2003 2002 - ----------------------------------------------------------------------------------- Amounts Included in Profitability Measures Depreciation & Amortization Gas Utility Services $ 57.0 $ 61.1 $ 56.8 Electric Utility Services 53.3 42.6 40.0 Other Operations 17.5 14.2 13.9 - ----------------------------------------------------------------------------------- Total depreciation & amortization $ 127.8 $ 117.9 $ 110.7 =================================================================================== Interest Expense Regulated Operations $ 62.7 $ 62.0 $ 63.7 Other Operations 4.7 4.1 5.4 - ----------------------------------------------------------------------------------- Total interest expense $ 67.4 $ 66.1 $ 69.1 =================================================================================== Equity in Earnings/(Losses) of Unconsolidated Affiliates Other Operations $ 0.2 $ (0.5) $ (1.8) =================================================================================== Income Taxes Gas Utility Services $ 17.5 $ 19.5 $ 18.2 Electric Utility Services 30.8 29.8 27.5 Other Operations 4.8 2.3 1.1 - ----------------------------------------------------------------------------------- Total income taxes $ 53.1 $ 51.6 $ 46.8 =================================================================================== Capital Expenditures Gas Utility Services $ 89.1 $ 95.0 $ 63.0 Electric Utility Services 150.6 124.1 88.8 Other Operations 27.9 15.9 65.5 - ----------------------------------------------------------------------------------- Total capital expenditures $ 267.6 $ 235.0 $ 217.3 =================================================================================== Investments in Equity Method Investees Other Operations $ - $ - $ 0.3 ===================================================================================
At December 31, - ---------------------------------------------------------------------- (In millions) 2004 2003 - ---------------------------------------------------------------------- Assets Utility Group Gas Utility Services $ 1,892.8 $ 1,805.0 Electric Utility Services 1,090.1 974.6 Other Operations 175.0 162.4 Eliminations (10.2) (16.9) - ---------------------------------------------------------------------- Total assets $ 3,147.7 $ 2,925.1 ====================================================================== 14. Subsidiary Guarantor and Consolidating Information The Company's three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of VUHI's $350 million in short-term credit facilities, of which $308.0 million is outstanding at December 31, 2004, and VUHI's $550.0 million unsecured senior notes outstanding at December 31, 2004. The guarantees are full and unconditional and joint and several, and VUHI has no subsidiaries other than the subsidiary guarantors. However, VUHI does have operations other than those of the subsidiary guarantors. Pursuant to Article 3-10 of Regulation S-X, disclosure of the results of operations and balance sheets of the subsidiary guarantors separate from the parent company's operations is required. Following are consolidating financial statements including information on the combined operations of the subsidiary guarantors separate from the other operations of the parent company. Consolidating Balance Sheet as of December 31, 2004 (in millions): - ------------------------------------------------------------------------------------------ ASSETS Subsidiary Parent ------ Guarantors Company Eliminations Consolidated ---------- ------- ------------ ------------ Current Assets Cash & cash equivalents $ 4.7 $ 1.0 $ - $ 5.7 Accounts receivable - less reserves 147.4 0.1 - 147.5 Receivables due from other Vectren companies 1.7 327.0 (324.7) 4.0 Accrued unbilled revenues 161.2 - - 161.2 Inventories 53.0 - - 53.0 Recoverable fuel & natural gas costs 17.7 - - 17.7 Prepayments & other current assets 136.4 4.2 (2.4) 138.2 - ----------------------------------------------------------------------------------------- Total current assets 522.1 332.3 (327.1) 527.3 - ----------------------------------------------------------------------------------------- Utility Plant Original cost 3,465.2 - - 3,465.2 Less: accumulated depreciation & amortization 1,309.0 - - 1,309.0 - ----------------------------------------------------------------------------------------- Net utility plant 2,156.2 - - 2,156.2 - ----------------------------------------------------------------------------------------- Investments in consolidated subsidiaries - 951.5 (951.5) - Notes receivable from consolidated subsidiaries - 443.1 (443.1) - Investments in unconsolidated affiliates 0.2 - - 0.2 Other investments 13.5 6.1 - 19.6 Non-utility property - net 5.3 144.3 - 149.6 Goodwill - net 205.0 - - 205.0 Regulatory assets 76.8 5.7 - 82.5 Other assets 3.8 3.5 - 7.3 - ----------------------------------------------------------------------------------------- TOTAL ASSETS $ 2,982.9 $1,886.5 $(1,721.7) $3,147.7 =========================================================================================
- ------------------------------------------------------------------------------------------ LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent ---------------------------------- Guarantors Company Eliminations Consolidated ---------- -------- ------------ ------------ Current Liabilities Accounts payable $ 87.9 $ 9.4 $ - $ 97.3 Accounts payable to affiliated companies 98.6 0.2 - 98.8 Payables to other Vectren companies 26.0 0.6 (10.8) 15.8 Accrued liabilities 107.1 11.6 (2.4) 116.3 Short-term borrowings 0.3 308.0 - 308.3 Short-term borrowings from other Vectren companies 313.8 - (313.8) - Current maturities of long-term debt - - - - Long-term debt subject to tender 10.0 - - 10.0 - ------------------------------------------------------------------------------------------ Total current liabilities 643.7 329.8 (327.0) 646.5 - ------------------------------------------------------------------------------------------ Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 393.4 547.9 - 941.3 Long-term debt due to VUHI 443.1 - (443.1) - - ------------------------------------------------------------------------------------------ Total long-term debt - net 836.5 547.9 (443.1) 941.3 - ------------------------------------------------------------------------------------------ Deferred Income Taxes & Other Liabilities Deferred income taxes 226.8 14.0 - 240.8 Regulatory liabilities 246.2 5.5 - 251.7 Deferred credits & other liabilities 78.0 3.9 - 81.9 - ------------------------------------------------------------------------------------------ Total deferred credits & other liabilities 551.0 23.4 - 574.4 - ------------------------------------------------------------------------------------------ Cumulative, Redeemable Preferred Stock of a Subsidiary 0.1 - - 0.1 Common Shareholder's Equity Common stock (no par value) 611.3 592.9 (611.3) 592.9 Retained earnings 340.3 392.5 (340.3) 392.5 - ------------------------------------------------------------------------------------------ Total common shareholder's equity 951.6 985.4 (951.6) 985.4 - ------------------------------------------------------------------------------------------ TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $2,982.9 $1,886.5 $(1,721.7) $3,147.7 ==========================================================================================
Consolidating Balance Sheet as of December 31, 2003 (in millions): - ------------------------------------------------------------------------------------------ ASSETS Subsidiary Parent ------ Guarantors Company Eliminations Consolidated ---------- -------- ------------ ------------ Current Assets Cash & cash equivalents $ 7.4 $ 0.7 $ - $ 8.1 Accounts receivable - less reserves 113.6 0.4 - 114.0 Receivables due from other Vectren companies 0.2 190.8 (189.3) 1.7 Accrued unbilled revenues 128.7 - - 128.7 Inventories 55.1 - - 55.1 Recoverable fuel & natural gas costs 20.3 - - 20.3 Prepayments & other current assets 138.2 0.9 (7.8) 131.3 - ------------------------------------------------------------------------------------------ Total current assets 463.5 192.8 (197.1) 459.2 - ------------------------------------------------------------------------------------------ Utility Plant Original cost 3,250.7 - - 3,250.7 Less: accumulated depreciation & amortization 1,247.0 - - 1,247.0 - ------------------------------------------------------------------------------------------ Net utility plant 2,003.7 - - 2,003.7 - ------------------------------------------------------------------------------------------ Investments in consolidated subsidiaries - 956.2 (956.2) - Notes receivable from consolidated subsidiaries - 443.1 (443.1) - Investments in unconsolidated affiliates 0.2 1.6 - 1.8 Other investments 14.3 6.3 - 20.6 Non-utility property - net 5.6 135.7 - 141.3 Goodwill - net 205.0 - - 205.0 Regulatory assets 83.4 6.2 - 89.6 Other assets 3.9 - - 3.9 - ------------------------------------------------------------------------------------------ TOTAL ASSETS $2,779.6 $1,741.9 $(1,596.4) $2,925.1 ==========================================================================================
- ------------------------------------------------------------------------------------------ LIABILITIES & SHAREHOLDER'S EQUITY Subsidiary Parent ---------------------------------- Guarantors Company Eliminations Consolidated ---------- -------- ------------ ------------ Current Liabilities Accounts payable $ 57.5 $ 5.5 $ - $ 63.0 Accounts payable to affiliated companies 80.2 0.1 - 80.3 Payables to other Vectren companies 22.3 - (9.0) 13.3 Accrued liabilities 95.7 8.8 (10.6) 93.9 Short-term borrowings 0.8 184.4 - 185.2 Short-term borrowings from other Vectren companies 177.6 - (177.6) - Current maturities of long-term debt 15.0 - - 15.0 Long-term debt subject to tender 13.5 - - 13.5 - ------------------------------------------------------------------------------------------ Total current liabilities 462.6 198.8 (197.2) 464.2 - ------------------------------------------------------------------------------------------ Long-Term Debt Long-term debt - net of current maturities & debt subject to tender 412.9 547.6 - 960.5 Long-term debt due to VUHI 443.0 - (443.0) - - ------------------------------------------------------------------------------------------ Total long-term debt - net 855.9 547.6 (443.0) 960.5 - ------------------------------------------------------------------------------------------ Deferred Income Taxes & Other Liabilities Deferred income taxes 194.8 6.7 - 201.5 Regulatory liabilities 228.8 6.2 - 235.0 Deferred credits & other liabilities 81.1 2.8 - 83.9 - ------------------------------------------------------------------------------------------ Total deferred credits & other liabilities 504.7 15.7 - 520.4 - ------------------------------------------------------------------------------------------ Cumulative, Redeemable Preferred Stock of a Subsidiary 0.2 - - 0.2 Common Shareholder's Equity Common stock (no par value) 611.3 589.8 (611.3) 589.8 Retained earnings 344.9 390.0 (344.9) 390.0 - ------------------------------------------------------------------------------------------ Total common shareholder's equity 956.2 979.8 (956.2) 979.8 - ------------------------------------------------------------------------------------------ TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $2,779.6 $1,741.9 $(1,596.4) $2,925.1 ==========================================================================================
Consolidating Statement of Income for the year ended December 31, 2004 (in millions): - ----------------------------------------------------------------------------------- Subsidiary Parent Guarantors Company Eliminations Consolidated - --------------------------------- ---------- ------- ------------ ------------ OPERATING REVENUES Gas utility $ 1,126.2 $ - $ - $ 1,126.2 Electric utility 371.3 - - 371.3 Other - 32.9 (32.4) 0.5 - ----------------------------------------------------------------------------------- Total operating revenues 1,497.5 32.9 (32.4) 1,498.0 - ----------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 778.5 - - 778.5 Fuel for electric generation 96.1 - - 96.1 Purchased electric energy 20.7 - - 20.7 Other operating 249.8 1.1 (32.4) 218.5 Depreciation & amortization 110.1 17.5 0.2 127.8 Taxes other than income taxes 57.5 0.6 0.1 58.2 - ----------------------------------------------------------------------------------- Total operating expenses 1,312.7 19.2 (32.1) 1,299.8 - ----------------------------------------------------------------------------------- OPERATING INCOME 184.8 13.7 (0.3) 198.2 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies - 75.9 (75.9) - Equity in losses of unconsolidated affiliates - 0.2 - 0.2 Other - net 2.4 35.4 (32.6) 5.2 - ----------------------------------------------------------------------------------- Total other income (expense) 2.4 111.5 (108.5) 5.4 - ----------------------------------------------------------------------------------- Interest expense 62.9 37.5 (33.0) 67.4 - ----------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 124.3 87.7 (75.8) 136.2 - ----------------------------------------------------------------------------------- Income taxes 48.4 4.6 0.1 53.1 - ----------------------------------------------------------------------------------- NET INCOME $ 75.9 $ 83.1 $(75.9) $ 83.1 ===================================================================================
Consolidating Statement of Income for the year ended December 31, 2003 (in millions): - ----------------------------------------------------------------------------------- Subsidiary Parent Guarantors Company Eliminations Consolidated - --------------------------------- ---------- ------- ------------ ------------ OPERATING REVENUES Gas utility $ 1,112.3 $ - $ - $ 1,112.3 Electric utility 335.7 - - 335.7 Other - 26.5 (25.7) 0.8 - ----------------------------------------------------------------------------------- Total operating revenues 1,448.0 26.5 (25.7) 1,448.8 - ----------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 762.5 - - 762.5 Fuel for electric generation 86.5 - - 86.5 Purchased electric energy 16.2 - - 16.2 Other operating 235.2 0.6 (25.7) 210.1 Depreciation & amortization 103.7 14.2 - 117.9 Taxes other than income taxes 55.9 0.7 - 56.6 - ----------------------------------------------------------------------------------- Total operating expenses 1,260.0 15.5 (25.7) 1,249.8 - ----------------------------------------------------------------------------------- OPERATING INCOME 188.0 11.0 - 199.0 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies - 81.8 (81.8) - Equity in losses of unconsolidated affiliates - (0.5) - (0.5) Other - net 5.0 28.0 (28.2) 4.8 - ----------------------------------------------------------------------------------- Total other income (expense) 5.0 109.3 (110.0) 4.3 - ----------------------------------------------------------------------------------- Interest expense 62.0 32.3 (28.2) 66.1 - ----------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 131.0 88.0 (81.8) 137.2 - ----------------------------------------------------------------------------------- Income taxes 49.2 2.4 - 51.6 - ----------------------------------------------------------------------------------- NET INCOME $ 81.8 $ 85.6 $ (81.8) $ 85.6 ===================================================================================
Consolidating Statement of Income for the year ended December 31, 2002 (in millions): - ----------------------------------------------------------------------------------- Subsidiary Parent Guarantors Company Eliminations Consolidated - --------------------------------- ---------- ------- ------------ ------------ OPERATING REVENUES Gas utility $ 908.0 $ - $ - $ 908.0 Electric utility 328.6 - - 328.6 Other - 22.3 (22.0) 0.3 - ----------------------------------------------------------------------------------- Total operating revenues 1,236.6 22.3 (22.0) 1,236.9 - ----------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 570.8 - - 570.8 Fuel for electric generation 81.6 - - 81.6 Purchased electric energy 16.8 - - 16.8 Other operating 220.2 0.4 (22.0) 198.6 Depreciation & amortization 96.8 13.9 - 110.7 Taxes other than income taxes 50.8 (0.1) - 50.7 - ----------------------------------------------------------------------------------- Total operating expenses 1,037.0 14.2 (22.0) 1,029.2 - ----------------------------------------------------------------------------------- OPERATING INCOME 199.6 8.1 - 207.7 OTHER INCOME (EXPENSE) Equity in earnings of consolidated companies - 95.3 (95.3) - Equity in losses of unconsolidated affiliates - (1.8) - (1.8) Other - net 5.0 27.6 (25.5) 7.1 - ----------------------------------------------------------------------------------- Total other income (expense) 5.0 121.1 (120.8) 5.3 - ----------------------------------------------------------------------------------- Interest expense 63.6 31.0 (25.5) 69.1 - ----------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 141.0 98.2 (95.3) 143.9 - ----------------------------------------------------------------------------------- Income taxes 45.7 1.1 - 46.8 - ----------------------------------------------------------------------------------- $ 95.3 $ 97.1 $(95.3) $ 97.1 ===================================================================================
Consolidating Statement of Cash Flows for the year ended December 31, 2004 (in millions): - ---------------------------------------------------------------------------------------- Subsidiary Parent Guarantors Company Eliminations Consolidated - ---------------------------------------- ---------- ------- ------------ ------------ NET CASH FLOWS FROM OPERATING ACTIVITIES $ 219.0 $ 35.3 $ - $ 254.3 - ---------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution - 3.1 - 3.1 Long-term debt - net of issuance costs & hedging proceeds 32.4 - - 32.4 Requirements for: Retirement of long-term debt, including premiums paid (70.5) - - (70.5) Dividends to parent (80.6) (80.6) 80.6 (80.6) Redemption of preferred stock of subsidiary (0.1) - - (0.1) Net change in short-term borrowings, including from other Vectren companies 135.7 123.6 (136.2) 123.1 Other activity - - - - - ---------------------------------------------------------------------------------------- Net cash flows from financing activities 16.9 46.1 (55.6) 7.4 - ---------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions - 80.6 (80.6) - Other investing activities 1.1 2.4 - 3.5 Requirements for: Capital expenditures, excluding AFUDC equity (239.7) (27.9) - (267.6) Consolidated subsidiary investments - - - - Unconsolidated affiliate & other investments - - - - Net change in notes receivable from other Vectren companies - (136.2) 136.2 - - ---------------------------------------------------------------------------------------- Net cash flows from investing activities (238.6) (81.1) 55.6 (264.1) - ---------------------------------------------------------------------------------------- Net (decrease) increase in cash & cash equivalents (2.7) 0.3 - (2.4) Cash & cash equivalents at beginning of period 7.4 0.7 - 8.1 - ---------------------------------------------------------------------------------------- Cash & cash equivalents at end of period $ 4.7 $ 1.0 $ - $ 5.7 ========================================================================================
Consolidating Statement of Cash Flows for the year ended December 31, 2003 (in millions): - ---------------------------------------------------------------------------------------- Subsidiary Parent Guarantors Company Eliminations Consolidated - ---------------------------------------- ---------- ------- ------------ ------------ NET CASH FLOWS FROM OPERATING ACTIVITIES $ 129.4 $ 39.8 $ - $ 169.2 - ---------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution 150.0 204.1 (150.0) 204.1 Long-term debt - net of issuance costs & hedging proceeds 99.0 202.9 (99.0) 202.9 Requirements for: Retirement of long-term debt, including premiums paid (121.9) - - (121.9) Dividends to parent (77.9) (78.0) 77.9 (78.0) Redemption of preferred stock of subsidiary (0.1) - - (0.1) Net change in short-term borrowings, including from other Vectren companies 30.9 (150.1) (21.6) (140.8) Other activity (1.7) - - (1.7) - ---------------------------------------------------------------------------------------- Net cash flows from financing activities 78.3 178.9 (192.7) 64.5 - ---------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions - 77.9 (77.9) - Requirements for: Capital expenditures, excluding AFUDC equity (219.0) (16.0) - (235.0) Consolidated subsidiary investments - (150.0) 150.0 - Unconsolidated affiliate & other investments - (1.1) - (1.1) Net change in notes receivable from other Vectren companies 8.5 (129.1) 120.6 - - ---------------------------------------------------------------------------------------- Net cash flows from investing activities (210.5) (218.3) 192.7 (236.1) - ---------------------------------------------------------------------------------------- Net (decrease) increase in cash & cash equivalents (2.8) 0.4 - (2.4) Cash & cash equivalents at beginning of period 10.2 0.3 - 10.5 - ---------------------------------------------------------------------------------------- Cash & cash equivalents at end of period $ 7.4 $ 0.7 $ - $ 8.1 ========================================================================================
Consolidating Statement of Cash Flows for the year ended December 31, 2002 (in millions): - ---------------------------------------------------------------------------------------- Subsidiary Parent Guarantors Company Eliminations Consolidated - ---------------------------------------- ---------- ------- ------------ ------------ NET CASH FLOWS FROM OPERATING ACTIVITIES $ 269.4 $ 8.2 $ - $ 277.6 - ---------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution 25.0 - (25.0) - Long-term debt - net of issuance costs & hedging proceeds 37.1 - (37.1) - Requirements for: Retirement of long-term debt, including premiums paid (6.5) - - (6.5) Dividends to parent (74.7) (69.7) 74.7 (69.7) Redemption of preferred stock of subsidiary (0.2) - - (0.2) Net change in short-term borrowings, including from other Vectren companies (88.4) 32.2 79.0 22.8 - ---------------------------------------------------------------------------------------- Net cash flows from financing activities (107.7) (37.5) 91.6 (53.6) - ---------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Consolidated subsidiary distributions - 74.7 (74.7) - Other investing 1.5 8.9 - 10.4 Requirements for: Capital expenditures, excluding AFUDC equity (147.6) (69.7) - (217.3) Consolidated subsidiary investments - (25.0) 25.0 - Unconsolidated affiliate & other investments (3.9) (7.9) - (11.8) Net change in notes receivable from other Vectren companies (8.5) 50.4 (41.9) - - ---------------------------------------------------------------------------------------- Net cash flows from investing activities (158.5) 31.4 (91.6) (218.7) - ---------------------------------------------------------------------------------------- Net increase in cash & cash equivalents 3.2 2.1 - 5.3 Cash & cash equivalents at beginning of period 7.0 (1.8) - 5.2 - ---------------------------------------------------------------------------------------- Cash & cash equivalents at end of period $ 10.2 $ 0.3 $ - $ 10.5 ========================================================================================
15. Impact of Recently Issued Accounting Guidance FIN 46/46R (Revised in December 2003) 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 (VIE) and significantly changes the consolidation requirements for those entities. FIN 46 is intended to achieve more consistent application of consolidation policies related to VIE's and thus improves comparability between enterprises engaged in similar activities when those activities are conducted through VIE's. In December 2003, the FASB completed its deliberations of proposed modifications to FIN 46 and decided to codify both the proposed modifications and other decisions previously issued through certain FASB Staff Positions into one document that was issued as a revision to the original Interpretation (FIN 46R). FIN 46R currently applies to VIE's created after January 31, 2003, and to VIE's in which an enterprise obtains an interest after that date. For entities created prior to January 31, 2003, FIN 46R is to be adopted no later than the end of the first interim or annual reporting period ending after March 15, 2004. The Company has neither created nor obtained an interest in a VIE since January 31, 2003. Adoption of FIN 46R did not have a material impact on the Company's results of operations or financial position. 16. Quarterly Financial Data (Unaudited) 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 2004 and 2003 follows: - ------------------------------------------------------------------------------- (In millions, except per share amounts) Q1 Q2 Q3 Q4 - ------------------------------------------------------------------------------- 2004 Results of Operations: Operating revenues $ 594.2 $ 243.4 $ 214.7 $ 445.7 Operating income 89.3 19.9 21.7 67.3 Net income 44.7 2.8 4.5 31.1 2003 Results of Operations: Operating revenues $ 592.9 $ 239.9 $ 210.7 $ 405.3 Operating income 95.7 17.4 19.4 66.5 Net income 47.3 1.4 2.4 34.5 ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES Changes in Internal Controls over Financial Reporting During the quarter ended December 31, 2004, there have been no changes to the Company's internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures As of December 31, 2004, the Company conducted 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 at providing reasonable assurance that 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) is brought to their attention on a timely basis. ITEM 9B. OTHER INFORMATION None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation. Vectren's Corporate Governance Guidelines, its charters for each of its Audit, Compensation and Nominating and Corporate Governance Committees, and its Code of Ethics covering the Company's directors, officers and employees are available on the Company's website, www.vectren.com, and a copy will be mailed upon request to Investor Relations, Attention: Steve Schein, 20 N.W. Fourth Street, Evansville, Indiana 47708. The Company intends to disclose any amendments to the Code of Ethics or waivers of the Code of Ethics on behalf of the Company's directors or officers including, but not limited to, the principal executive officer, principal financial officer, principal accounting officer or controller and persons performing similar functions on the Company's website at the internet address set forth above promptly following the date of such amendment or waiver and such information will also be available by mail upon request to Investor Relations, Attention: Steve Schein, 20 N.W. Fourth Street, Evansville, Indiana 47708. ITEM 11. EXECUTIVE COMPENSATION Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The following tabulation shows the audit and non-audit fees incurred and payable to Deloitte & Touche, LLP (Deloitte) for the years ending December 31, 2004, and December 31, 2003. The fees presented below represents total Vectren fees, not just the portion allocated to VUHI. - --------------------------------------------------------------------- 2004 2003(6) - --------------------------------------------------------------------- Audit Fees(1) $ 1,424,910 $ 736,928 Audit-Related Fees(2) 13,650 150,049 Tax Fees(3) 103,663 91,830 All Other Fees(4) - - - --------------------------------------------------------------------- Total Fees Paid to Deloitte(5) $ 1,542,223 $ 978,807 ===================================================================== (1) Aggregate fees incurred and payable to Deloitte for professional services rendered for the audits of the Company's 2004 and 2003 fiscal year annual financial statements and the review of financial statements included in Company's Forms 10-Q filed during the Company's 2004 and 2003 fiscal years. This includes fees incurred for audit services related to regulatory filings and certain of the Company's subsidiaries in connection with the audit of the Company's financial statements, and, in 2004, includes fees related to the attestation to the Company's assertion pursuant to Section 404 of the Sarbanes Oxley Act of 2002. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $74,185 and $76,478 in 2004 and 2003, respectively. (2) Audit related fees consisted principally of consultation on various accounting issues and reviews related to various financing transactions in 2004 and 2003. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $650 and $2,600 in 2004 and 2003, respectively. (3) Tax fees consisted of fees paid to Deloitte for the review of tax returns and consultation on other tax matters of the Company. In addition, this amount includes the reimbursement of out-of-pocket costs incurred related to the provision of these services totaling $2,788 and $1,255 in 2004 and 2003, respectively. (4) All Other Fees--None. (5) Pursuant to its charter, the Audit committee is responsible for selecting, approving professional fees and overseeing the independence, qualifications and performance of the independent accounting firm. The Audit committee has adopted a formal policy with respect to the pre-approval of audit and permissible non-audit services provided by the independent accounting firm. Pre-approval is assessed on a case-by-case basis. In assessing requests for services to be provided by the independent accounting firm, the Audit committee considers whether such services are consistent with the auditors' independence, whether the independent accounting firm is likely to provide the most effective and efficient service based upon the firm's familiarity with the Company, and whether the service could enhance the Company's ability to manage or control risk or improve audit quality. The audit-related, tax and other services provided by Deloitte in the last fiscal year and related fees were approved by the Audit committee in accordance with this policy. (6) Amounts differ from the 2004 Proxy Statement. In 2004 the amounts reported were amounts actually paid to Deloitte in the indicated period. As noted above, this report reflects amounts incurred and payable for services performed related to the indicated period, regardless of when paid, consistent with current proxy disclosure rules. PART IV 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, 2004, 2003, and 2002, the Company's Schedule II - -- Valuation and Qualifying Accounts Consolidated Financial Statement Schedules is presented herein. 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. SCHEDULE II Vectren Utility Holdings, Inc. and Subsidiary Companies 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: Year 2004 - Accumulated provision for uncollectible accounts $ 3.1 $ 10.7 $ - $ 11.9 $ 1.9 Year 2003 - Accumulated provision for uncollectible accounts $ 5.5 $ 12.2 $ - $ 14.6 $ 3.1 Year 2002 - Accumulated provision for uncollectible accounts $ 5.1 $ 11.7 $ - $ 11.3 $ 5.5 OTHER RESERVES: Year 2004 - Restructuring costs $ 3.2 $ - $ - $ 0.5 $ 2.7 Year 2003 - Restructuring costs $ 3.6 $ - $ - $ 0.4 $ 3.2 Year 2002 - Restructuring costs $ 4.3 $ - $ - $ 0.7 $ 3.6 Year 2002 - Merger & integrattion costs $ 0.4 $ - $ - $ 0.4 $ -
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 attached to this filing filed electronically with the SEC are listed below. Exhibits for the Company are listed in the Index to Exhibits beginning on page 60. Vectren Utility Holdings, Inc. 2004 Form 10-K Attached Exhibits The following Exhibits are included in this Annual Report on Form 10-K. Exhibit Number Document - ------- -------- 31.1 Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. The following Exhibits were filed electronically with the SEC with this filing. Exhibit Number Document - ------- -------- 10.21 Agreement for the Supply of Coal to F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Sigcorp Fuels, Inc., dated December 17, 1997 and effective January 1, 1998 (portions redacted pursuant to a request for confidental treatment.) 21.1 List of Company's Significant Subsidiaries INDEX TO EXHIBITS 2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession 2.1 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.) 3. Articles of Incorporation and By-Laws 3.1 Articles of Incorporation of Vectren Utility Holdings, Inc. (Filed and designated in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit 3.1) 3.2 Bylaws of Vectren Utility Holdings, Inc. (Filed and designated in Registration Statement on Amendment 3 to Form 10, File No. 1-16739, as Exhibit 3.2) 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.) 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.) August 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.1.) October 1, 2004. (Filed and designated in Form 10-K for the year ended December 31, 2004, File No. 1-15467, as Exhibit 4.2.) 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 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.) First Amendment, effective April 16, 1997 (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.). 10.2 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.) 10.3 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.) 10.4 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.) 10.5 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.) First Amendment, 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.). 10.6 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.) First Amendment, 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.) Second Amendment, 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.) Third Amendment, 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.) 10.7 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.) 10.8 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.) 10.9 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.) 10.10 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.) 10.11 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.) 10.12 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.) 10.13 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.) 10.14 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.) 10.15 Vectren Corporation At Risk Compensation Plan specimen Restricted Stock Grant Agreement for officers, effective January 1, 2005. (Filed and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit 99-1.) 10.16 Vectren Corporation At Risk Compensation Plan specimen Stock Option Grant Agreement for officers, effective January 1, 2005. (Filed and designated in Form 8-K, dated January 1, 2005, File No. 1-15467, as Exhibit 99-2.) 10.17 Vectren Corporation specimen employment agreement dated February 1, 2005. (Filed and designated in Form 8-K, dated February 1, 2005, File No. 1-15467, as Exhibit 99-1.) 10.18 Gas Sales and Portfolio Administration Agreement between Indiana Gas Company, Inc. and ProLiance Energy, LLC, effective August 30, 2003. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.15.) 10.19 Gas Sales and Portfolio Administration Agreement between Southern Indiana Gas and Electric Company and ProLiance Energy, LLC, effective September 1, 2002. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.16.) 10.20 Gas Sales and Portfolio Administration Agreement between Vectren Energy Delivery of Ohio and ProLiance Energy, LLC, effective October 31, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-15467, as Exhibit 10-24.) 10.21 Agreement for the Supply of Coal to F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Sigcorp Fuels, Inc., dated December 17, 1997 and effective January 1, 1998. Portions of the document have been omitted pursuant to a request for confidential treatment in accordance with Exchange Act Rule 24b-2. (redacted version is filed here with). 10.22 Amendment 1, effective January 1, 2003, to Coal Supply Agreement between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally dated December 17, 1997. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.19.) 10.23 Coal Supply Agreement for Generating Stations at Yankeetown, Warrick County, Indiana, and West Franklin, Posey County, Indiana between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated January 19, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.20.) 10.24 Amendment 1, effective January 1, 2004, to Coal Supply Agreement between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc originally dated January 19, 2000. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.21.) 10.25 Coal Supply Agreement for Warrick Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc. dated October 1, 2003. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.22.) 10.26 Coal Supply Agreement for Warrick Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc. dated January 1, 2004. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No. 1-15467, as Exhibit 10.23.) 10.27 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.) 21. Subsidiaries of the Company The list of the Company's significant subsidiaries is attached hereto as Exhibit 21.1. 31. Certification Pursuant To Section 302 of the Sarbanes-Oxley Act of 2002 Chief Executive Officer Certification Pursuant to Section 302 Of The Sarbanes- Oxley Act Of 2002 is attached hereto as Exhibit 31.1 Chief Financial Officer Certification Pursuant to Section 302 Of The Sarbanes- Oxley Act Of 2002 is attached hereto as Exhibit 31.2 32. Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 Certification Pursuant To Section 906 of the Sarbanes-Oxley Act Of 2002 is attached hereto as Exhibit 32.1 99. Additional Exhibits 99.1 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.) 99.2 Amended and Restated Code of By-Laws of Vectren Corporation as of October 29, 2003. (Filed and designated in Quarterly Report on Form 10-Q filed November 13, 2003, File No. 1-15467, as Exhibit 3.1.) 99.3 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.) SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. VECTREN UTILITY HOLDINGS, INC. Dated February 23, 2005 /s/ Niel C. Ellerbrook -------------------------- Niel C. Ellerbrook, Chairman, Chief Executive Officer, and Director Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in capacities and on the dates indicated. Signature Title Date Chairman, Chief Executive /s/ Niel C. Ellerbrook Officer, & Director February 23, 2005 - ---------------------------- (Principal Executive Officer) ------------------- Niel C. Ellerbrook /s/ Jerome A. Benkert, Jr. Executive Vice President, February 23, 2005 - ---------------------------- Chief Financial Officer, & ------------------- Jerome A. Benkert, Jr. Director (Principal Financial Officer) /s/ M. Susan Hardwick Vice President & Controller February 23, 2005 - ---------------------------- (Principal Accounting Officer) ------------------- M. Susan Hardwick /s/ Ronald E. Christian Director February 23, 2005 - ---------------------------- ------------------- Ronald E. Christian /s/ William S. Doty Director February 23, 2005 - ---------------------------- ------------------- William S. Doty
EX-10.21 2 vuhi10k_exh10-21culley2004.txt AGREEMENT FOR SUPPLY OF COAL Exhibit 10.21 CONFIDENTIAL PORTIONS OMITTED AGREEMENT FOR THE SUPPLY OF COAL BETWEEN SOUTHERN INDIANA GAS AND ELECTRIC COMPANY (Buyer) AND SIGCORP FUELS, INC. (Seller) December 17, 1997 TABLE OF CONTENTS SECTIONS HEADINGS PAGE NO. SECTION 1. TERM 1 SECTION 2. QUANTITY, ANNUAL PRICE REVISION, DELIVERIES 2 SECTION 3. SOURCE AND DELIVERY 3 SECTION 4. QUALITY 5 SECTION 5. WEIGHING, SAMPLING AND ANALYSIS 10 SECTION 6. PRICE 12 SECTION 7. INVOICES, BILLING AND PAYMENT 15 SECTION 8. FORCE MAJEURE 16 SECTION 9. AUDIT AND INSPECTION 20 SECTION 10. NOTICES 20 SECTION 11. RIGHT TO USE AND RESELL 21 SECTION 12. LIABILITY 21 SECTION 13. STATUS AND RELIANCE OF BUYER 22 SECTION 14. TERMINATION FOR DEFAULT 23 SECTION 15. CONSTRUCTION OF AGREEMENT 23 SECTION 16. INDEPENDENT CONTRACTOR 25 SECTION 17. PERMITS AND LICENSES 26 SECTION 18. CONFIDENTIALITY 26 THIS COAL SUPPLY AGREEMENT ("Agreement") entered into this 17th day of December, 1997 by and between SOUTHERN INDIANA GAS AND ELECTRIC COMPANY, a public utility organized and existing under the laws of Indiana ("Buyer") and SIGCORP FUELS, INC., an Indiana corporation ("Seller"). W I T N E S S E T H : WHEREAS, Buyer is an electric utility which desires to purchase a supply of coal of the quality hereafter described for use in its F.B.Culley Generating Station at Yankeetown, Warrick County, Indiana, and; WHEREAS, Seller desires to sell coal produced by its Cypress Creek Mine, Warrick County, Indiana, to Buyer and Buyer desires to buy such coal from Seller for the purposes of and in accordance with the provisions of this Agreement; NOW THEREFORE, in consideration of the mutual covenants contained herein, Seller agrees to sell and deliver and Buyer agrees to purchase and accept delivery of coal of the quality and quantity hereinafter described and in accordance with the terms and conditions set forth herein as follows: SECTION 1. TERM Section 1.1 Term. This Agreement shall commence on January 1, 1998, or upon Contract filing with the Indiana Utility Regulatory Commission ("IURC") and the Federal Energy Regulatory Commission ("FERC") and inaction or approval by the IURC and FERC, whichever occurs earlier, and unless sooner terminated as provided herein, shall continue until and including December 31, 2002. Buyer and Seller acknowledge that the source of coal to be furnished under this Agreement is a new mine operation to be developed subsequent to the execution of this document. It is anticipated that deliveries will begin hereunder during the fourth quarter of 1997. Accordingly, the initial term of this Agreement will include calendar years 1998 through 2002 and any portion of 1997 in which coal is produced by Seller from the Cyprus Creek Mine and delivered to Buyer. Buyer shall have the right, but not the obligation, to renew this Agreement for an additional five (5) year period, such right to be exercised by notice in writing to Seller no later than six (6) months prior to the expiration of the initial term of this Agreement. SECTION 2. QUANTITY, ANNUAL PRICE REVISION, DELIVERIES Section 2.1 Quantity. [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] Section 2.2 Rate of Shipment. [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] Section 2.3 Notification. (a) Quarterly Delivery Schedule - By November 1 of each year, Buyer shall specify by written notice to Seller the monthly quantities to be delivered in the following calendar year subject to the limitation contained in subparagraph (b). Quantities shall be specified on quarterly schedules. Revisions to any quarterly schedule shall be made by Buyer no later than the 1st of the month preceding the start of that quarter. (Eg, March 1 for the second quarter, etc.) (b) Modification of Quantity - On or before November 1, Buyer may change the Quantity to be delivered in the following year within a range of +/- 10% of the Quantity specified in Section2.1 above. SECTION 3. SOURCE AND DELIVERY. Section 3.1 Source - [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] Section 3.2 Warranties of Operation and Reserves. Seller represents and warrants that The Mine contains economically recoverable coal of a quality and in quantities which will be sufficient to satisfy all the requirements of this Agreement. Seller agrees and warrants that it is the legal owner of The Mine, and that it will have or cause to have at The Mine adequate machinery, equipment and other facilities to produce, prepare and deliver coal in the quantity and of the quality required by this Agreement. Seller further agrees to operate and maintain such machinery, equipment and facilities in accordance with good mining practices so as to efficiently and economically produce, prepare and deliver such coal, or to contract therefor. Seller agrees that Buyer is not providing any capital for the purchase of such machinery, equipment and/or facilities and that Seller shall operate and maintain same at its sole expense, including Seller's acquisition of all required permits and licenses or Seller shall contract therefor. Seller hereby dedicates to this Agreement from The Mine sufficient reserves of coal meeting the quarterly delivery requirement and quality specifications provided for herein. Section 3.3 Non-Diversion of Coal. Seller agrees and warrants that it will not, without Buyer's express prior written consent, use, mine or sell coal from The Mine in a way that will reduce the economically recoverable balance of coal in The Mine to an amount less than that required to be supplied to Buyer hereunder. Section 3.4 Truck Delivery, Title, Risk of Loss. Buyer and Seller hereby select truck transportation as the method of shipment for all coal under this Agreement. Coal will be delivered FOB Buyer's F. B. Culley Generating Station, and title to and risk of loss of coal will pass to Buyer when the coal is unloaded at the Culley Plant and placed on its stockpile (the "Delivery Point"). Seller will contract and pay for transportation from The Mine to the F. B. Culley Generating Station and unloading from trucks onto Buyer's stockpile. Section 3.5 Alternative Delivery Mode. Buyer shall be entitled, upon one hundred twenty days (120) days prior notice to Seller, to change the specified mode of delivery at its option for all or a portion of the Quantity. In the event any such change will result in an adjustment to Seller's costs (increase or decrease), Seller shall give Buyer prompt written notice thereof, such notice to include a detailed statement and itemization of such costs, and Buyer and Seller shall jointly make an adjustment to the Base Price of coal sold hereunder if Buyer agrees to the adjustment, otherwise the mode of delivery shall not change. SECTION 4. QUALITY Section 4.1 The coal delivered hereunder shall conform to the specifications in Exhibit A attached hereto. The specifications in Exhibit A are hereby made a part of, are a fundamental basis of this Agreement, and create an express warranty by Seller that the coal shall conform in every respect to all specifications. The coal shall have a top size of not larger than two (2) inches. Intermediate sizes shall not be removed. Not more than 35% by weight of each delivery shall be less than 1/4 inch in size. The fine content of the coal shall be that resulting from the normal mining and preparation sizing of the coal, and no fine screenings or slurry shall be added. The coal shall be substantially uniform in quality and physical appearance and shall be free flowing and substantially free from excess water and impurities such as, but not limited to, rock, bone, wood, slate, earth, or metal. Section 4.2 Change in Specification. Seller may, with the written permission of Buyer, deliver coal which does not conform to the foregoing Section 4.1 and the specifications in Exhibit A, provided that Buyer shall have the right to take such reasonable measures and precautions as it deems necessary to assure itself that any divergence in specifications does not adversely impact the costs or operation of Buyer's F.B. Culley Generating Station. Section 4.3 Rejection. (a) A ("Shipment") is defined as the entire quantity of coal prepared for delivery for which sampling and analysis has been performed pursuant to Section 5.2. A shipment shall not include more than 5,000 tons. (b) Seller shall notify Buyer prior to Buyer's receipt of any shipment if such shipment fails to conform to the specifications in Exhibit A. Buyer shall then have the option to accept or reject such shipment (a "Nonconforming Shipment"). If Seller fails to notify Buyer of a Nonconforming Shipment, then Buyer may request service at any time or, if the Nonconforming Shipment of coal is burnt, then Seller shall pay Buyer all costs, expenses and damages therefor, including, but not limited to, environmental costs, damages and expenses. (c) In the event Buyer rejects any Nonconforming Shipment, Buyer shall return the coal to Seller or, at Seller's request, divert such coal to Seller's designee, all at Seller's cost. Buyer may request replacement of the rejected coal by Seller within five (5) working days with coal at least equal to the specifications in Section4.1 and Exhibit A. If Seller fails to replace the rejected coal within five (5) working days or the replacement coal is rejected, Buyer may purchase an equivalent amount of conforming specification coal from another source in order to replace the rejected coal and Seller shall reimburse Buyer for any amount by which the total delivered cost to Buyer of such conforming coal purchased from another source exceeds the then current delivered cost of coal under this Agreement. Seller shall reimburse Buyer for any and all freight or transportation expenses that it incurs for rejected coal. (d) After receipt of notice from Seller of a shipment, or upon Buyer's own discovery of a Nonconforming Shipment, Buyer may, by notice to Seller, voluntarily elect to accept a Nonconforming Shipment. If Buyer accepts a Nonconforming Shipment, the price therefor shall be reduced by an amount mutually agreed upon by Buyer and Seller, and the quantity Buyer is obligated to purchase from Seller, shall be reduced in each calendar year by the amount of any Nonconforming Shipment voluntarily accepted by Buyer. (e) Failure to Give Notice - Failure on the part of Seller to give Buyer advance notice of any nonconforming shipment as required in (a) above shall constitute a default within the meaning of Section 14 of this Agreement. Section 4.4 Suspension and Termination. (a) Buyer may, upon notice in writing, suspend future shipments if sampling and analysis pursuant to Section 5.2 of this Agreement indicates that a shipment of coal fails to meet any of the specifications in Section 4.1 and in Exhibit A. Seller shall, within 15 days, provide Buyer with reasonable assurances that subsequent deliveries of coal shall meet or exceed such specifications. If Seller fails to provide such assurances within said 15 day period, or provides such assurance but does not correct the violation(s) prior to the next scheduled shipment after giving such assurance, Buyer may on 15 days notice, terminate this Agreement without any cost or penalty to Buyer. If Seller provides such assurances to Buyer's reasonable satisfaction, shipments hereunder shall resume and any tonnage deficiencies resulting from suspension may be made up by Seller, with Buyer's approval, in accordance with a mutually agreed schedule. Buyer shall not unreasonably withhold its acceptance of Seller's assurances, or delay the resumption of shipments. (b) Notwithstanding any other provisions of this Agreement, if the coal specifications set forth in Exhibit A are adjusted at any time due to new or revised applicable laws, rules or regulations, Seller and Buyer agree to enter into negotiations in good faith to arrive at a mutually agreeable price adjustment under which Seller can continue to supply coal that conforms with such new laws, rules or regulations and meets the adjusted specifications. The parties shall also negotiate an agreement as to any necessary lead time to permit the receipt and delivery of coal conforming to the new specifications. If mutually agreeable terms cannot be negotiated, either party may on not less than thirty (30) days' notice, terminate this Agreement. Section 4.5 Remedies. Seller shall be responsible for all costs incurred by Buyer resulting from Seller's failure to comply with this Agreement. Buyer, at its option, may allow Seller to supply replacement coal at the Base Price as adjusted pursuant to Section 6; however, Buyer may procure coal to replace all or any part of the quantity of coal which Seller has failed to deliver. The Seller shall be liable to Buyer for the excess delivered cost occasioned by Buyer's purchase of replacement coal and any other loss or damage directly caused by the Seller's breach of this Agreement. Buyer may also recover damages for all losses sustained as a result of Seller's breach of Agreement based upon any applicable legal theory, including, but not limited to, environmental costs, expenses, penalties, losses and damages. Buyer may deduct the excess cost, loss, or damage from any amount due Seller under this Agreement and, if such amount is insufficient, Buyer shall recover the balance due from Seller directly through appropriate legal action. Remedies provided under this Agreement shall be cumulative and in addition to other remedies provided by law or in equity. SECTION 5. WEIGHING, SAMPLING AND ANALYSIS Section 5.1 Weights. The weight of the coal delivered hereunder shall be determined on a per shipment basis by Buyer on the basis of scale weights at the generating station unless another method is mutually agreed upon by the parties. Such scales shall be duly certified by an appropriate testing agency and maintained in an accurate condition. Seller shall have the right, at Seller's expense and upon reasonable notice, to have the scales checked for accuracy at any reasonable time or frequency. If the scales are found to be inaccurate, over or under a tolerance range of 0.5%, either party shall pay to the other any amounts owed due to such inaccuracy for a period not to exceed thirty (30) days before the time any inaccuracy of scales is determined. Section 5.2 Sampling and Analysis. The sampling and analysis of the coal delivered hereunder shall be performed at Seller's expense at the Mine by an independent commercial testing laboratory ("Independent Lab") mutually selected by Buyer and Seller. The results thereof shall be accepted and used for the quality and characteristics of the coal delivered under this Agreement. All analyses shall be made in accordance with American Society of Testing Materials ("A.S.T.M.") or other mutually agreed to specifications. Samples for analysis shall be taken in accordance with A.S.T.M. standards, may be composited, and shall be taken with a frequency and regularity sufficient to provide accurate representative samples of the deliveries made hereunder. Each sample shall be divided into 3 parts and put into airtight containers, properly labeled and sealed. One part shall be used for analysis by the Independent Lab, one part shall be made available to Buyer as a check sample, if Buyer in its sole judgment determines it is necessary, and one part ("Referee Sample") shall be retained for a period of 30 days. Buyer shall be given timely and routine copies of all analyses made by the Independent Lab. Seller will fax results and relevant coal quality information to Buyer's designee and to its Plant Manager, 24 hours prior to shipment. Buyer, on reasonable notice to Seller shall have the right to have a representative present to observe the sampling and analysis. Unless Buyer requests a Referee Sample analysis, the Independent Lab analysis shall be used to determine the quality of the coal delivered hereunder. If any dispute arises within 30 days of the date of sampling, the Referee Sample shall be submitted for analysis to another independent commercial testing laboratory ("Second Lab") selected by Buyer. The analysis of the Second Lab shall control to the extent provided in this Section. A dispute shall be deemed not to exist and the Independent Lab analysis shall prevail if such analysis differs from the analysis of the Second Lab by an amount equal to or less than any of the following ("as received"): [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] SECTION 6. PRICE Section 6.1 Price. [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] Section 6.2 Revised Renewal Period Price. [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] Section 6.3 Diesel Fuel Price Adjustment. [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] Section 6.4 Government Impositions. [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] SECTION 7. INVOICES, BILLING AND PAYMENT Section 7.1 Invoice Procedures for Coal Shipments. Seller shall invoice Buyer twice each month at the current Base Price for all coal unloaded in the previous calendar half-month. Section 7.2 Payment Procedures for Coal Shipments. Payment for coal unloaded shall be mailed within 15 days after receipt of invoice in form and detail satisfactory to Buyer. Buyer shall mail all payments to Seller's account as directed by Seller. Section 7.3 Withholding. Buyer shall have the right to withhold from payment of any billing or billings the amount of any sums which it is not able in good faith to verify or which it otherwise in good faith disputes, such right to withhold to continue for the duration of the dispute or inability to verify. Buyer shall notify Seller promptly in writing of any such issue, stating the basis of its claim and the amount it intends to withhold, and the parties agree to review the matter in detail within ten (10) days after Seller's receipt of such notice. In the event and to the extent that any dispute or verification issue is resolved in Seller's favor, Seller shall add the unpaid amount to the next invoice, plus interest at the prime rate of borrowed funds as published in the most recently published edition of the Wall Street Journal for the period between the date on which the amount would normally be paid and the actual payment date, and Buyer shall pay such extra amount in accordance with the procedures hereof. In the event and to the extent that any dispute or verification issue is resolved in Buyer's favor, Seller shall promptly issue a credit memorandum covering the amount in question. Payment by Buyer, whether knowing or inadvertent, of any amount in dispute shall not be deemed a waiver of any claims or rights by Buyer with respect to any disputed amounts or payments made. SECTION 8. FORCE MAJEURE Section 8.1 Events of Force Majeure. Performance of the obligations of either party hereto except as to any obligation by either party to make payment to the other shall be excused to the extent prevented by an event of Force Majeure. As used herein, an event of Force Majeure shall mean an act of God; strike, lockout or other labor dispute; sabotage; fire; flood; war; riot or insurrection; explosion; accident; embargo; blockade; inability to secure supplies, fuel, power, governmental authorization or permit; unscheduled or forced outages at the generating station (see Section 8.5 below); breakdown of or damage to machinery, plants or equipment; interruption or shortage of transportation arrangements or equipment; regulation, rule, law, order, act or restraint of any civil or military authority; or any other event, whether of the kind herein enumerated or otherwise, which is beyond the control and without the fault or negligence of the party affected thereby and which wholly or partially prevents, interrupts or delays performance hereunder. An event is beyond the control of a party if it cannot be prevented or eliminated by the exercise of due diligence or its prevention or elimination would be accomplished only at an excessive or unreasonable cost. The party claiming excuse hereunder shall give the other party prompt notice of such event. As used herein, the term "Seller" shall include any party mining, preparing, hauling, loading or transporting coal to Seller for resale to Buyer under this Agreement. The party experiencing the Force Majeure shall use its best efforts to remedy the Force Majeure as soon as practicable. Section 8.2 Notice and Suspension. If because of Force Majeure either Buyer or Seller is unable to carry out its obligations under this Agreement, such party shall promptly give the other party written notice of the Force Majeure, whereupon the obligations and liabilities of the party giving such notice and the corresponding obligations of the other party shall be suspended to the extent made necessary by and during the continuance of such Force Majeure. Subject to the provisions of this Section if (a) a condition of Force Majeure occurs, (b) mutual obligations are suspended as contemplated by the paragraph next hereinabove, (c) such condition (alone or extended by other conditions of Force Majeure) continues so that the mutual obligations remain suspended for a period of six months, and (d) at the end of said six months or at any time thereafter either party, in the exercise of reasonable judgment, concludes that there is no likelihood of ending the condition(s) in the immediate future, then either party may terminate this Agreement without liability to the other party by giving to the other 90 days' notice in writing of its intention to terminate. Section 8.3 Deficiencies in Shipments. In the event Seller is prevented, in whole or in part, from producing, processing or shipping coal hereunder due to Force Majeure, deficiencies in shipments so resulting may be added to subsequent shipments of like coal, but only if Seller is requested to do so by Buyer, and then pursuant to a reasonable schedule provided to Seller by Buyer. Section 8.4 Environmental Force Majeure. The parties recognize that, during the continuance of this Agreement, legislative or regulatory bodies or the courts may adopt laws, regulations, policies and/or restrictions relating to air pollution or other environmental matters which will make it impossible or commercially impracticable for Buyer to utilize this or like kind and quality coal which thereafter would be delivered hereunder. If as a result of the adoption of such laws, regulations, policies, or restrictions, or change in the interpretation or enforcement thereof, Buyer decides that it will be impossible or commercially impracticable (uneconomical) for Buyer to utilize such coal, Buyer shall so notify Seller, and thereupon Buyer and Seller shall promptly consider whether corrective actions can be taken in the mining and preparation of the coal at Seller's mine and/or in the handling and utilization of the coal at Buyer's generating station; and if in Buyer's judgment such actions will not, without unreasonable expense to Buyer, make it possible and commercially practicable for Buyer to so utilize coal which thereafter would be delivered hereunder without violating any applicable law, regulation, policy or order, Buyer shall have the right, upon the later of 60 days' notice to Seller or the effective date of such restriction, to terminate this Agreement without further obligation hereunder on the part of either party. Any expense contemplated by this Section shall be deemed unreasonable and the alternative under consideration shall thereby be deemed impossible or commercially impracticable, if it would result in a total cost to Buyer (including the cost of any equipment amortized over its useful life), in using Seller's coal, in excess of the total cost of using competitive fuels including, without limitation, coal from alternative sources which are then reasonably available to Buyer and which can be utilized in conformity with all such restrictions (including the cost of any addition or modification to Buyer's generating station necessary to permit the delivery and utilization of such fuel). The cost of using such fuels over the remainder of the term of this Agreement, including anticipated increases in the price of such other fuel and of any required modifications, adjustments or additions to Buyer's generating station, shall be considered for purposes of this Section. Buyer's decisions and opinions with respect to this Section 8.4 shall be final and not subject to question or dispute by Seller. Section 8.5 Redirection of Coal. Notwithstanding any other provision of this section, Buyer will have the absolute right and discretion, but in no event any obligation, during any period of Force Majeure, to redirect shipments of coal delivered under this Agreement to any of its generating stations, provided that Buyer agrees to reimburse Seller for any additional transportation or handling costs that are incurred by Seller to effect such redirected deliveries. SECTION 9. AUDIT AND INSPECTION Buyer shall have the right to inspect, review, and audit (or to have its representatives inspect, review, and audit) at any time during regular business hours, and upon reasonable notice so as not to disrupt any part of Seller's operations, including, without limitation the source of Seller's coal, management, and/or processes by which coal is mined, handled, processed, hauled, sampled, analyzed and loaded hereunder. Buyer shall maintain, and cause its representatives to maintain, all data and information discovered pursuant to this Section in confidence except to the extent that disclosure thereof may be required by law. SECTION 10. NOTICES Section 10.1 Form and Place of Notice. Any official notice, request for approval or other document required to be given under this Agreement shall be in writing, unless otherwise provided herein, and shall be deemed to have been sufficiently given if delivered in person, transmitted by telegraph, telex, or telecopier, or dispatched in the United States mail, postage prepaid, for mailing by first class, certified, or registered mail, return receipt requested and addressed as follows: If to Seller: President SIGCORP Fuels, Inc. 20 N.W. Fourth Street Evansville, IN 47741 If to Buyer: President Southern Indiana Gas and Electric Company 20 N. W. Fourth Street Evansville, Indiana 47741 Section 10.2 Change of Person or Address. Either party may change the person or address specified above upon giving notice to the other party of such change. SECTION 11. RIGHTS TO USE AND RESELL Buyer shall have the unqualified right to resell all or any of the coal purchased under this Agreement, and to use any and all such coal in any of its generating stations including the transfer from one plant to another, all in it's absolute discretion, provided that Buyer agrees to reimburse Seller for any additional transportation or handling costs incurred by Seller to effect such deliveries. SECTION 12. LIABILITY Section 12.1 Indemnity - Seller agrees to indemnify and save harmless Buyer, its officers, directors, employees and representatives from any responsibility and liability for any and all claims, demands, losses (including reasonable attorney's fees) arising out of or resulting from any failure of the coal sold hereunder to comply with any laws, regulations or ordinances, including, without limitation, any laws, regulations or ordinances relating to air quality or emissions standards, or which otherwise arise out of the acts or omissions of Seller in the performance of this Agreement. Seller further agrees to indemnify, defend and hold Buyer and its agents and employees harmless from any claims, demands or liability of any kind or nature for injuries or damage to any person or property arising out of or resulting from the performance of the Agreement. Section 12.2 Consequential Damages - In no event shall either party be liable to the other or to any third party for any indirect, special or consequential damages including, without limitation, those based on loss of revenue, profit or business opportunity, whether or not either party had or should have had any knowledge, actual or constructive, that such damages might be incurred. SECTION 13. STATUS AND RELIANCE OF BUYER Seller recognizes that Buyer is a public utility which has power sales contracts with other utilities and provides electrical service to customers within the State of Indiana. Throughout this Agreement Buyer, its customers and such other utilities will be relying on the continued operation of the generating station as a source of electricity for their various needs. Seller further acknowledges that an adequate and continuous fuel supply to the generating station, at prices reasonably in conformity to then prevailing market prices for coal comparable in quality to that sold hereunder, are essential to Buyer's ability to provide electricity and services at affordable rates. By signing this Agreement Buyer is placing reliance upon Seller to furnish a significant portion of its fuel supply at competitive prices. Seller agrees, in meeting its obligations hereunder, to give due consideration to the status and reliance of Buyer and Buyer's customers. SECTION 14. TERMINATION FOR DEFAULT In the event of the failure of either party to comply with any material obligation of this Agreement, either party shall have the right to terminate this Agreement at any time by giving to the other 120 days' notice in writing of its intention to do so, specifying the default complained of. At the expiration of said 120 days, unless the party in default shall have made good such default, the party not in default shall have the right at its election to terminate this Agreement forthwith. This right shall be in addition to the rights provided to either party in other portions of this Agreement and by law, or in equity. SECTION 15. CONSTRUCTION OF AGREEMENT Section 15.1 Applicable Law. This Agreement shall be deemed to be executed in the State of Indiana and shall be interpreted and enforced according to the laws of the State of Indiana. Only the courts in the State of Indiana shall have jurisdiction over this Agreement and any controversies arising out of the Agreement. Any controversies arising out of this Agreement shall be submitted only to the courts of the State of Indiana. Seller hereby submits to the jurisdiction of the courts in the State of Indiana for the purposes of interpretation and enforcement of this Agreement. Section 15.2 Headings. The paragraph headings appearing in this Agreement are for convenience only and shall not affect the meaning or interpretation of the Agreement. Section 15.3 Waiver. The failure of either party to insist on strict performance of any provision of this Agreement, or to take advantage of any rights hereunder, shall not be construed as a waiver of such provision or right. Section 15.4 Remedies Cumulative. Remedies provided under this Agreement shall be cumulative and in addition to other remedies provided by law. Section 15.5 Severability. If any provision of this Agreement is found contrary to law or unenforceable by any court of law, the remaining provisions shall be severable and enforceable in accordance with their terms, unless such unlawful or unenforceable provision is material to the transactions contemplated hereby, in which case the parties shall negotiate in good faith a substitute provision. Section 15.6 Binding Effect. This Agreement shall bind and inure to the benefit of the parties and their successors and assigns. Section 15.7 Assignment. Neither party may assign this Agreement or any rights or obligations hereunder without the prior written consent of the other party, which consent shall not be unreasonably withheld or denied; provided, however, that Buyer shall have the right, without consent of Seller, to assign all or any part of this Agreement to any company, controlling, controlled by, or under common control with Buyer. Section 15.8 Entire Agreement. This instrument contains the entire Agreement between the parties as to coal produced and sold from the Coal Property, and there are no representations, understandings or agreements, oral or written, which are not included herein. Section 15.9 Amendments. Except as otherwise provided herein, this Agreement may not be amended, supplemented or otherwise modified except by written instrument signed by parties hereto. SECTION 16. INDEPENDENT CONTRACTOR Seller shall be an independent contractor with respect to the work to be performed hereunder. Neither Seller nor its subcontractors, nor the employees of either, shall be deemed to be the servants, employees or agents of Buyer. SECTION 17. PERMITS AND LICENSES Both parties shall, at their own expense, obtain any necessary permits and licenses in connection with the performance of their work, unless otherwise specified in this Agreement, and shall be responsible for conducting the work in accordance with the provisions of such permits and licenses. SECTION 18. CONFIDENTIALITY Subject to Buyer's obligations of disclosure to AMAX Coal Company under a pre-existing agreement, Seller and Buyer agree to retain in confidence this Agreement and any information obtained as a result of negotiation and performance of this Agreement which either party identifies to the other as being proprietary in nature. It is agreed and understood, however, that such information may be disclosed when requested by a court or government agency, to consultants or subcontractors of either of the parties subject to the same conditions of confidentiality as provided herein, or as otherwise provided by law, regulation, or administrative requirement. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed as of the date first above written. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY By: /s/ Ronald Jochum ----------------------------------------- Ronald Jochum Its: Vice President, Power Supply for SIGECO ATTEST: /s/ Susan Fester - ------------------- Susan Fester SIGCORP FUELS, INC. By: /s/ Kent Stump ----------------------------------------- Kent Stump Its: President ATTEST: /s/ Kimberly Snow - ------------------- Kimberly Snow EXHIBIT A SIGCORP FUELS, INC. COAL SPECIFICATIONS [CONFIDENTIAL MATERIAL OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION PURSUANT TO A REQUEST FOR CONFIDENTIAL TREATMENT.] EX-21.1 3 vuhi10k_exh21-1.txt LISTING OF SIGNIFICANT SUBSIDIARIES EXHIBIT 21.1
VECTREN UTILITY HOLDINGS, INC. Subsidiaries Wholly Owned Subsidiaries: State of Incorporation/ Doing Business As Name of Entity Jurisdiction - -------------------------------------- ----------------------- --------------------------- |X| Southern Indiana Gas and Electric Indiana Vectren Energy Delivery of Company, Inc. Indiana, Inc. |X| Indiana Gas Company, Inc. Indiana, Ohio Vectren Energy Delivery of Indiana, Inc. |X| Vectren Energy Delivery of Ohio, Ohio Inc.
EX-31.1 4 vuhi10k_exh31-1.txt CFO CERTIFICATION EX: 31-1 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 Annual Report on Form 10-K of Vectren Utility Holdings, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 23, 2005 /s/ Niel C. Ellerbrook ---------------------------------- Niel C. Ellerbrook Chairman & Chief Executive Officer EX-31.2 5 vuhi10k_exh31-2.txt CFO CERTIFICATION Exhibit 31.2 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 Annual Report on Form 10-K of Vectren Utility Holdings, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: February 23, 2005 /s/ Jerome A. Benkert, Jr. ---------------------------------- Jerome A. Benkert, Jr. Executive Vice President & Chief Financial Officer EX-32.1 6 vuhi10k_exh32-1.txt CERTIFICATION Exhibit 32.1 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 Annual Report on Form 10-K 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 Utility Holdings, Inc. Signed this 23rd day of February, 2005. /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 & Chief Financial Officer Chairman & Chief Executive Officer - ------------------------------------ -------------------------------------- (Title) (Title) -----END PRIVACY-ENHANCED MESSAGE-----