-----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, KEjjLerwteGJs091GkrSXLeN1DX4NOEe2UHN4FXjffhe9kvnKWMaPra8/OXwxjGh UYsUPsYlKuictSF1G9S10w== 0000092195-04-000001.txt : 20040326 0000092195-04-000001.hdr.sgml : 20040326 20040326160028 ACCESSION NUMBER: 0000092195-04-000001 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20031231 FILED AS OF DATE: 20040326 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHERN INDIANA GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000092195 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 350672570 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03553 FILM NUMBER: 04693050 BUSINESS ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 BUSINESS PHONE: 8124914000 MAIL ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 10-K 1 sig10k_2003.txt SOUTHERN INDIANA GAS & ELECTRIC 2003 10K 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, 2003 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: 1-3553 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY - ------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) INDIANA 35-0672570 - -------------------------------- ---------------------- (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 20 N.W. Fourth Street, Evansville, Indiana 47708 - ------------------------------------------ ---------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 812-491-4000 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered - --------------------------- ------------------------------------------ None None 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, 2003, was zero. All shares outstanding of the Registrant's common stock were held by Vectren Corporation through its wholly owned subsidiary, Vectren Utility Holdings, Inc. 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 25,815,188 March 1, 2004 - -------------------------------- ---------- ------------- Class Number of Shares Date Omission of Information by Certain Wholly Owned Subsidiaries The Registrant is a wholly owned subsidiary of Vectren Utility Holdings, Inc. 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/millions of megawatt hours (gigawatt hour) FASB: Financial Accounting Standards NOx: nitrogen oxide Board IDEM: Indiana Department of OUCC: Indiana Office of the Utility Environmental Management Consumer Counselor IURC: Indiana Utility Regulatory SFAS: Statement of Financial Accounting Commission Standards MCF/BCF: millions/billions of cubic USEPA: United States Environmental 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 (A) .......................................................4 2 Properties .........................................................4 3 Legal Proceedings...................................................5 4 Submission of Matters to Vote of Security Holders (A)...............5 Part II 5 Market for the Company's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities (A)..............5 6 Selected Financial Data (A).........................................6 7 Management's Discussion and Analysis of Results of Operations and Financial Condition (A)..............................6 7A Qualitative and Quantitative Disclosures About Market Risk.........16 8 Financial Statements and Supplementary Data........................18 9 Change in and Disagreements with Accountants on Accounting and Financial Disclosure...........................................44 9A Controls and Procedures............................................44 and Procedures Part III 10 Directors and Executive Officers of the Registrant (A)............45 11 Executive Compensation (A)........................................45 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters (A)....................45 13 Certain Relationships and Related Transactions (A)................45 14 Principal Accountant Fees and Services............................46 Part IV 15 Exhibits (A), Financial Statement Schedules, and Reports on Form 8-K................................................47 Signatures.........................................................54 (A) - Omitted or amended as the Registrant is a wholly-owned subsidiary of Vectren Utility Holdings, Inc. 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 free of charge, including those of its wholly owned subsidiaries, through its website at www.vectren.com, or by request, directed to Investor Relations at the mailing address, phone number, or email address that follows: Mailing Address: Phone Number: Investor Relations Contact: P.O. Box 209 (812) 491-4000 Steven M. Schein Evansville, Indiana Vice President, Investor Relations 47702-0209 sschein@vectren.com 16 PART I ITEM 1. BUSINESS Description of the Business Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana corporation, provides electric generation, transmission, and distribution services to 8 counties in southwestern Indiana, including counties surrounding Evansville, and participates in the wholesale power market. The Company also provides natural gas distribution and transportation services to 10 counties in southwestern Indiana, including counties surrounding Evansville. SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). SIGECO generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren, an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. Vectren was organized on June 10, 1999, solely for the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with APB Opinion No. 16 "Business Combinations" (APB 16). Vectren's wholly owned subsidiary, VUHI, serves as the intermediate holding company for its three operating public utilities, Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Inc. (Indiana Energy), SIGECO, formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations, a utility jointly owned by Indiana Gas and Vectren Energy Delivery of Ohio, Inc. (VEDO). 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. The narrative description of the business, competition and personnel sections were intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation. ITEM 2. PROPERTIES Electric Utility Services SIGECO's installed generating capacity as of December 31, 2003, 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 a new 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 27 substations with an installed capacity of 4,235.9 megavolt amperes (Mva). The electric distribution system includes 3,224 pole miles of lower voltage overhead lines and 289 trench miles of conduit containing 1,622 miles of underground distribution cable. The distribution system also includes 92 distribution substations with an installed capacity of 1,901.7 Mva and 51,417 distribution transformers with an installed capacity of 2,368.6 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. Gas Utility Services 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 124,748 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 18,699 MCF per day. SIGECO has the ability to meet a total annual demand, utilizing all of its assets across various pipelines, of 28.4 BCF with a maximum peak day delivery capability of 228,943 MCF per day. SIGECO's gas delivery system includes 3,026 miles of distribution and transmission mains, all of which are located in Indiana. Property Serving as Collateral The Company's properties are subject to the lien of the First Mortgage Indenture dated as of April 1, 1932, between the Company and Bankers Trust Company, as Trustee, and Deutsche Bank, as successor Trustee, as supplemented by various supplemental indentures. ITEM 3. LEGAL PROCEEDINGS The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 8 of its financial statements included in "Item 8 Financial Statements and Supplementary Data" regarding the Clean Air Act and related legal proceedings. Legal proceedings regarding the Culley generating station's compliance with the Clean Air Act were substantially resolved during 2003. ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation. PART II ITEM 5. MARKET FOR COMPANY'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES All of the outstanding shares of the Company's common stock are owned by VUHI. The Company's common stock is not traded. There are no outstanding options or warrants to purchase the Company's common equity or securities convertible into the Company's common equity. Additionally, the Company has no plans to publicly offer any of its common equity. Dividends Paid to Parent During 2003, the Company paid dividends to its parent company of $10.9 million, $10.9 million, $11.3 million, and $19.0 million in the first, second, third, and fourth quarters, respectively. During 2002, the Company paid dividends to its parent company of $10.3 million, $11.6 million, $11.6 million, and $11.6 million in the first, second, third, and fourth quarters, respectively. On January 28, 2004, the board of directors declared a $12.3 million dividend, payable to its parent company on March 1, 2004. ITEM 6. SELECTED FINANCIAL DATA Intentionally omitted. See the table of contents of this Annual Report on Form 10-K for explanation. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Pursuant to General Instructions I(2)(a) of Form 10-K, the following analysis of the results of operations is presented in lieu of Management's Discussion and Analysis of Financial Condition and Results of Operations. The following discussion and analysis should be read in conjunction with the financial statements and notes thereto. Executive Summary of Results of Operations In 2003, net income applicable to common shareholder was $48.8 million, a decrease of $10.5 million when compared to 2002. The decrease in 2003 compared to 2002 was primarily driven by weather, a slowly recovering economy, and increased operating expenses, partially offset by increased wholesale power margins and retail electric rate recovery related to NOx compliance expenditures and related operating expenses. In 2002, net income applicable to common shareholder was $59.3 million, an increase of $18.6 million when compared to 2001. The year ended December 31, 2001, included nonrecurring merger, integration, and restructuring costs and other nonrecurring items totaling $4.0 million after tax. In addition to the nonrecurring 2001 items, the increase reflected improved margins and lower operating costs. These resulted from favorable weather and a return to lower gas prices and the related reduction in costs incurred in 2001. The Company generates revenue primarily from the delivery of electric service and natural gas 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 electric and gas 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. Nonrecurring Items in 2001 Merger & Integration Costs Merger and integration related costs incurred during 2001 totaled $0.6 million ($0.4 million after tax). These costs relate primarily to transaction costs, severance, and other merger and acquisition integration activities. The integration activities experienced by the Company included such things as information system consolidation, process review and definition, organization design and consolidation, and knowledge sharing. Merger and integration activities resulting from the 2000 merger forming Vectren were completed in 2001. Restructuring Costs As part of continued cost saving efforts, in June 2001, the Company's management and board of directors approved a plan to restructure, primarily, its regulated operations. The restructuring plan included the elimination of certain administrative and supervisory positions in its utility operations and corporate office. Charges of $4.3 million were expensed in June 2001 as a direct result of the restructuring plan. Additional charges of $1.5 million were incurred during the remainder of 2001 primarily for consulting fees and employee relocation costs. In total, the Company incurred restructuring charges of $5.8 million ($3.6 million after tax) in 2001. These charges were comprised of $4.4 million for employee severance, related benefits and other employee related costs and $1.4 million for consulting and other fees. The restructuring program was completed during 2001, except for the departure of certain employees impacted by the restructuring which occurred during 2002. Cumulative Effect of Change in Accounting Principle Resulting from the adoption of SFAS 133, certain contracts in the power marketing operations that are periodically settled net were required to be recorded at market value. Previously, the Company accounted for these contracts on settlement. The cumulative impact of the adoption of SFAS 133 resulting from marking these contracts to market on January 1, 2001, was an earnings gain of approximately $1.8 million ($1.1 million after tax) recorded as a cumulative effect of change in accounting principle in the Statements of Income. Loss on extinguishment of preferred stock In September 2001, the Company notified holders of its 4.80%, 4.75%, and 6.50% preferred stock of its intention to redeem the shares. The 4.80% preferred stock was redeemed at $110.00 per share, plus $1.35 per share in accrued and unpaid dividends. Prior to the redemption, there were 85,519 shares outstanding. The 4.75% preferred stock was redeemed at $101.00 per share, plus $0.97 per share in accrued and unpaid dividends. Prior to the redemption, there were 3,000 shares outstanding. The 6.50% preferred stock was redeemed at $104.23 per share, plus $0.73 per share in accrued and unpaid dividends. Prior to the redemption, there were 75,000 shares outstanding. The total redemption price was $17.7 million and the loss on redemption totaled $1.2 million. Significant Fluctuations Operating Margin Margin generated from the sale of electricity and natural gas to residential and commercial customers is seasonal and impacted by weather patterns in its service territory. Margin generated from sales to industrial and other contract customers is impacted by overall economic conditions. In general, operating margin is not sensitive to variations in fuel or gas costs. It is, however, impacted by the collection of state mandated taxes which fluctuate with gas costs and also some level of fluctuation 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. Electric Utility Margin Electric Utility margin by revenue type follows: Year Ended December 31, - ---------------------------------------------------------------------------- (In thousands) 2003 2002 2001 - ---------------------------------------------------------------------------- Residential & commercial $ 141,061 $ 145,667 $ 134,436 Industrial 53,533 54,874 49,590 Municipalities & other 20,174 16,962 16,773 - ---------------------------------------------------------------------------- Total retail & firm wholesale 214,768 217,503 200,799 Asset optimization 18,277 12,727 19,105 - ---------------------------------------------------------------------------- Total electric utility margin $ 233,045 $ 230,230 $ 219,904 ============================================================================ Retail & Firm Wholesale Margin For the year ended December 31, 2003, margin from serving native load and firm wholesale customers was $214.8 million, a decrease of $2.7 million when compared to 2002. It is estimated that summer weather 19% cooler than normal and 34% cooler than last year caused an $8 million decrease in residential and commercial margin. The estimated effect of weather was partially offset by a $7.1 million increase in retail electric rates related to recovery of NOx compliance expenditures and related operating expenses. A slowly recovering economy continued to negatively impact industrial sales which decreased $1.3 million compared to 2002. As a result primarily of the mild weather and slow economic conditions, retail and firm wholesale volumes sold decreased 5% to 5.90 GWh in 2003 compared to 6.19 GWh in 2002. Volumes sold in 2001 were 5.82 GWh. The current year decrease in native load and firm wholesale margin has been offset by increased margin from asset optimization activities as more fully described below. For the year ended December 31, 2002, margin from serving native load and firm wholesale customers increased $16.7 million or 8%, when compared to 2001. The increase results primarily from the effect on residential and commercial sales of cooling weather considerably warmer than the prior year. Weather in 2002 was 27% warmer than 2001 and 23% warmer than normal. In addition to weather, 2002 was positively affected by increased industrial and other wholesale volumes and rate recovery related to NOx compliance expenditures as the expenditures are made pursuant to a rate recovery rider approved by the IURC in August 2001. As a result of warmer weather and increased volumes sold, native load and firm wholesale volumes sold increased 6%. It is estimated that weather contributed $7 million to the increase in electric utility margin, and the increased industrial and other wholesale volumes and the NOx recovery rider contributed $8 million. 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 these contracts 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 thousands) 2003 2002 2001 - ----------------------------------------------------------------------------------------- Beginning of Year Net Asset Optimization Position $ (718) $ 3,321 $ - Statement of Income Activity Cumulative effect at adoption of SFAS 133 - - 1,783 Mark-to-market gains (losses) recognized 654 (3,585) 1,537 Realized gains recognized 17,623 16,312 17,568 - ----------------------------------------------------------------------------------------- Net activity in electric utility margin 18,277 12,727 19,105 - ----------------------------------------------------------------------------------------- Net cash received & other adjustments (17,983) (16,766) (17,567) - ----------------------------------------------------------------------------------------- End of Year Net Asset Optimization Position $ (424) $ (718) $ 3,321 ========================================================================================= Included in: Prepayments & other current assets $ 2,373 $ 3,506 $ 6,128 Accrued liabilities (2,797) (4,224) (2,807)
For the years ended December 31, 2003, 2002, and 2001, volumes sold into the wholesale market were 4.3 GWh, 10.7 GWh, and 3.4 GWh, respectively, while volumes purchased were 4.1 GWh in 2003, 10.3 GWh in 2002, and 2.9 GWh in 2001. A portion of volumes purchased in the wholesale market is used to serve native load and firm wholesale customers, and in 2003, greater amounts of purchased power have been required for native load due to scheduled outages, which has reduced capacity available for optimization. Additionally, volumes sold and purchased were lower in 2003 compared to 2002 due to a shorter term focus in hedging and optimization strategies. While volumes both sold and purchased in the wholesale market have decreased during 2003, margin from optimization activities has increased compared to 2002 due primarily to price volatility. Despite the increased volumes in 2002, margins were lower in 2002 compared to 2001 due to reduced price volatility. In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not "Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF 03-11 states that determining whether realized gains and losses on physically settled derivative contracts should be reported in the Statement of Income on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The EITF contains a presumption that net settled derivative contracts should be reported net in the Statement of Income. The Company adopted EITF 03-11 as required on October 1, 2003. After considering the facts and circumstances relevant to the asset optimization portfolio, the Company believes presentation of these optimization activities on a net basis is appropriate and has reclassified purchase contracts and mark-to-market activity related to optimization activities from Purchased electric energy to Electric utility revenues. Prior year financial information has also been reclassified to conform to this net presentation. Following is information regarding asset optimization activities included in Electric utility revenues and Fuel for electric generation in the Statements of Income. Year Ended December 31, - ------------------------------------------------------------------------------- (In thousands) 2003 2002 2001 - ------------------------------------------------------------------------------- Activity related to: Sales contracts $ 152,795 $ 302,764 $ 101,418 Purchase contracts (126,969) (275,851) (74,311) Mark-to-market gains (losses) 654 (3,585) 1,537 - ------------------------------------------------------------------------------- Net asset optimization revenue 26,480 23,328 28,644 - ------------------------------------------------------------------------------- Fuel for electric generation (8,203) (10,601) (9,539) - ------------------------------------------------------------------------------- Asset optimization margin $ 18,277 $ 12,727 $ 19,105 =============================================================================== Gas Utility Margin Gas Utility margin and throughput by customer type follows: Year Ended December 31, - -------------------------------------------------------------------------------- (In thousands) 2003 2002 2001 - -------------------------------------------------------------------------------- Residential $ 18,989 $ 21,215 $ 18,614 Commercial 5,367 6,146 4,705 Contract 4,024 4,062 4,284 Other 929 938 (1,736) - -------------------------------------------------------------------------------- Total gas utility margin $ 29,309 $ 32,361 $ 25,867 ================================================================================ Volumes in MMDth: Sold to residential & commercial customers 12,495 12,336 11,215 Sold & transported to contract customers 19,052 19,652 20,708 - -------------------------------------------------------------------------------- Total throughput 31,547 31,988 31,923 ================================================================================ Gas Utility margin for the year ended December 31, 2003, of $29.3 million decreased $3.1 million, or 9%, compared to 2002. The decrease is primarily due to estimates for unbilled revenue, the pricing of unaccounted for gas, and reduced consumption per degree day per customer, all of which decreased margin by approximately $2.8 million. Utility receipts taxes collected from customers also decreased margin $0.5 million. Furthermore, the negative effect of high gas prices on customer usage contributed to the decrease. Weather near normal and 2% cooler than the prior year increased margin an estimated $0.2 million. Gas Utility margin for the year ended December 31, 2002, of $32.4 million increased $6.5 million compared to 2001. The increase is primarily due to weather 4% cooler for the year and 26% colder in the fourth quarter and customer growth of almost 1%. Gas cost fluctuations have impacted customer usage during the years ended December 31, 2003, 2002, and 2001. The average cost per dekatherm of gas purchased in those years was $5.78 in 2003, $4.20 in 2002, and $5.20 in 2001. Operating Expenses Other Operating For the year ended December 31, 2003, other operating expenses increased $5.6 million compared to 2002. The increase is principally caused by increased distribution, plant, and transmission operating expenses; power plant and other maintenance; customer service initiative costs; higher insurance premiums; and prior year insurance recoveries. Other operating expenses decreased $7.2 million for the year ended December 31, 2002, when compared to 2001. The decrease results primarily from insurance recovery in 2002 of $2.8 million of maintenance costs incurred in 2001, and a return to lower gas prices in 2002 compared to 2001. Depreciation & Amortization For the year ended December 31, 2003, depreciation and amortization increased $2.6 million in 2003 compared to 2002, and $1.8 million in 2002 compared to 2001. The increased depreciation expense reflects depreciation of utility plant placed into service including a full year for a gas-fired peaker unit placed into service in June 2002, customer system upgrades, and other upgrades to existing transmission and distribution facilities. Income Taxes For the year ended December 31, 2003, federal and state income taxes were comparable to 2002. The increase in the effective rate from 33.3% for 2002, to 38.6% for 2003, reflects an increase in the Indiana state income tax rate from 4.5 % to 8.5% and other changes in the effective tax rate recognized in 2002. The $9.0 million increase in 2002 compared to 2001 is principally due to higher pre-tax earnings. Taxes Other Than Income Taxes Taxes other than income taxes increased $0.7 million in 2003 compared to 2002. Utility plant additions have increased property values and as a result have increased property taxes in 2003. The increase was partially offset by lower utility receipts taxes. Taxes other than income taxes decreased $1.3 million in 2002 compared to 2001 as a result of lower revenues subject to gross receipts tax. Interest Expense Interest expense increased $1.6 million in 2003 compared to 2002 and increased $2.2 million in 2002 compared to 2001. The 2003 increase results from increased debt outstanding which is due primarily to increased working capital requirements resulting from the higher gas prices and NOx expenditures. The 2003 increase also reflects the impact of permanent financing completed in the third quarter of 2003 whereby short term borrowings from VUHI and $65 million of higher coupon third party debt were replaced with $25 million in equity and $61.9 in long-term debt payable to VUHI. The 2002 increase is attributable to higher outstanding borrowings during 2002 due to the funding of NOx expenditures with short-term borrowing. Rate Case Proceedings On March 12, 2004, SIGECO (d/b/a Vectren Energy Delivery of Indiana, Inc.) filed a petition with the IURC to adjust its base rates and charges for its gas distribution business in southwestern Indiana. If the filing is approved, SIGECO expects to increase its base (non-gas cost) rates by approximately $5.7 million to cover the ongoing cost of operating and maintaining the approximately 3,000-mile distribution and storage system used to serve more than 110,000 customers. If finalized by the OUCC and ultimately approved by the IURC, the agreement in principle would result in about a 5 percent increase for the typical SIGECO residential customer who uses natural gas to heat his/her home. The proposal will not affect the electric portion of the Company's customer bills. The petition only addresses "non-gas" costs, which are incurred to build, operate and maintain the pipes, other equipment and systems that are used to deliver gas. The petition indicates that SIGECO has reached an agreement in principle with the OUCC regarding the proposed changes to the rates and charges. The agreement in principle further provides for SIGECO's recovery through a tracking mechanism of costs required to comply with a new federal law dealing with pipeline safety. As required by the regulatory process, SIGECO will be required to submit information substantiating the proposed adjustment to its base rates. During the processing of the case by the IURC, there will also be one or more public hearings conducted regarding the proposal. The timing and ultimate outcome of this regulatory initiative is uncertain. Critical Accounting Policies Management is required to make judgments, assumptions, and estimates that affect the amounts reported in the financial statements and the related disclosures that conform to accounting principles generally accepted in the United States. Note 2 to the financial statements describes the significant accounting policies and methods used in the preparation of the 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 impairment 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 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 11 to the 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 both 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 in 2003 or 2002. 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 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. 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 FAS 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. 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 2003 periodic benefit cost: a discount rate of 6.75%, an expected return on plan assets before expenses of 9.0%, a rate of compensation increase of 4.25%, and a health care cost trend rate of 10% in 2003 declining to 5% in 2006. During 2003, Vectren reduced the discount rate and rate of compensation increase by 75 basis points to value 2003 ending pension and postretirement obligations due to a decline in benchmark interest rates. The Company also lengthened to 2009 the time in which the health care trend rate declines to 5% primarily due to increases in healthcare costs. In addition, the Company reduced its 2004 expected return on plan assets 50 basis points from that used to estimate 2003 expense due to recent lower investment returns and lower interest rates. Future changes in health care costs, work force demographics, interest rates, or plan changes could significantly affect the estimated cost of these future benefits that are allocated to VUHI and its subsidiaries. Impact of Recently Issued Accounting Guidance SFAS 143 In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company's results of operations or financial condition. The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. As of December 31, 2003, and 2002, such removal costs approximated $48 million and $44 million, respectively. In 2002, the cost of removal has been included in Other removal costs, which is in noncurrent liabilities. In 2003, the Company re-characterized other removal costs to Regulatory liabilities upon adoption of SFAS 143. SFAS 149 In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and clarifies the accounting guidance on (1) derivative instruments (including certain derivative instruments embedded in other contracts) and (2) hedging activities that fall within the scope of FASB Statement No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends SFAS 133 to reflect decisions that were made (1) as part of the process undertaken by the Derivatives Implementation Group (DIG), which necessitated amending SFAS 133, (2) in connection with other projects dealing with financial instruments, and (3) regarding implementation issues related to the application of the definition of a derivative. SFAS 149 also amends certain other existing pronouncements which will result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. SFAS 149 is effective (1) for contracts entered into or modified after June 30, 2003, with certain exceptions and (2) for hedging relationships designated after June 30. The guidance is to be applied prospectively. The adoption did not have a material effect on the Company's results of operations or financial condition. SFAS 150 In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150). SFAS 150 requires issuers to classify as liabilities the following three types of freestanding financial instruments: mandatorily redeemable financial instruments, obligations to repurchase the issuer's equity shares by transferring assets, and certain obligations to issue a variable number of shares. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003; otherwise, the standard was effective for all other financial instruments at the beginning of the Company's third quarter of 2003. In October 2003, the FASB issued further guidance regarding mandatorily redeemable stock which is effective January 1, 2004, for the Company. The adoption of SFAS 150 on January 1, 2004, did not affect the Company's results of operations or financial condition. FASB Interpretation (FIN) 45 In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for a guarantor's accounting for and disclosure of certain guarantees issued and outstanding and that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligations it has undertaken. The initial recognition and measurement provisions were applicable on a prospective basis to guarantees issued or modified after December 31, 2002. Since that date, the adoption has not had a material effect on the Company's results of operations or financial condition. FIN 46/46-R (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 46-R). FIN 46-R 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 46 is to be adopted no later than the end of the first interim or annual reporting period ending after March 15, 2004. Although management is still evaluating the impact of FIN 46 and related Staff Positions on its financial position and results of operations, the adoption is not expected to have a material effect. Staff Accounting Bulletin No. 104 In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104, "Revenue Recognition". This SAB updates portions of the SEC staff's interpretive guidance provided in SAB 101 and included in Topic 13 of the Codification of Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer necessary and conforms the interpretive material retained because of pronouncements issued by the FASB's EITF on various revenue recognition topics, including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The Company's adoption of the standard did not have an impact on its revenue recognition policies. United States Securities and Exchange Commission (SEC) Informal Inquiry As more fully described in the 2002 financial statements, the Company restated its annual financial statements for 2000 and 2001, and its 2002 quarterly results. The Company received an informal inquiry from the SEC with respect to this restatement. In response, the Company met with the SEC staff and provided information in response to their requests, with the most recent response provided on July 26, 2003. 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, 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 our credit rating, 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. 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 electric sales to certain municipalities and large industrial customers are exposed to commodity price risk associated with fluctuating commodity prices. The Company's wholesale power marketing activities include asset optimization activities that manage the utilization of available electric generating capacity by 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, 2003, and 2002, a 10% adverse change in forward commodity prices would have decreased earnings by $3.0 million and $1.7 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's risk management objective is for between 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, 2003, such debt obligations represented 18% 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 2003 and 2002, the weighted average combined borrowings under these arrangements were $49.8 million and $92.4 million, respectively. At December 31, 2003, and 2002, combined borrowings under these arrangements were $83.8 million and $61.9 million, respectively. Based upon average borrowing rates under these facilities during the years ended December 31, 2003, and 2002, an increase of 100 basis points (one percentage point) in the rates would have increased interest expense by $0.5 million and $0.9 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. 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 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of Southern Indiana Gas and Electric Company (SIGECO) is responsible for the preparation of the financial statements and the related financial data contained in this report. The financial statements are prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities. The integrity and objectivity of the data in this report, including required estimates and judgments, is the responsibility of management. Management maintains a system of internal control and utilizes an internal auditing program to provide reasonable assurance of compliance with Company policies and procedures and the safeguard of assets. The board of directors of Vectren Corporation (Vectren), the ultimate parent company of SIGECO, pursues its responsibility for these financial statements through its audit committee, which meets periodically with management, the internal auditors, and the independent auditors, to assure that each is carrying out its responsibilities. Both the internal auditors and the independent auditors meet with the audit committee of Vectren's board of directors, with and without management representatives present, to discuss the scope and results of their audits, their comments on the adequacy of internal accounting control, and the quality of financial reporting. /s/ Niel C. Ellerbrook - ------------------------------------- Niel C. Ellerbrook Chairman & Chief Executive Officer February 12, 2004 INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of Southern Indiana Gas and Electric Company: We have audited the accompanying balance sheets of Southern Indiana Gas and Electric Company as of December 31, 2003 and 2002, and the related statements of income, common shareholder's equity, and cash flows for each of the three years in the period ended December 31, 2003. 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Southern Indiana Gas and Electric Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, 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 financial statements taken as a whole, presentS fairly in all material respects the information set forth therein. As discussed in Note 2-F, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards ("SFAS") 143, "Accounting for Asset Retirement Obligations." As discussed in Note 2-E, effective January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other Intangibles." As discussed in Note 10, effective January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. As discussed in Note 10, in 2003 the Company adopted EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and "Not Held for Trading Purposes" as Defined in Issue No. 02-3." Amounts for the years 2002 and 2001 have been reclassified in the accompanying statements of income to conform to this new method of presentation. /s/ DELOITTE & TOUCHE LLP - ----------------------------------------------- DELOITTE & TOUCHE LLP Indianapolis, Indiana February 12, 2004 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY BALANCE SHEETS (In thousands) December 31, - ------------------------------------------------------------------------------- 2003 2002 - ------------------------------------------------------------------------------- ASSETS Utility Plant Original cost $ 1,659,527 $ 1,531,141 Less: Accumulated depreciation & amortization 719,787 684,832 - ------------------------------------------------------------------------------- Net utility plant 939,740 846,309 - ------------------------------------------------------------------------------- Current Assets Cash & cash equivalents 3,675 2,145 Accounts receivable - less reserves of $1,202 & $3,662, respectively 38,817 50,454 Receivables from other Vectren companies 76 18,015 Accrued unbilled revenues 28,162 33,027 Inventories 37,214 39,653 Recoverable fuel & natural gas costs 3,900 9,615 Prepayments & other current assets 4,875 5,926 - ------------------------------------------------------------------------------- Total current assets 116,719 158,835 - ------------------------------------------------------------------------------- Investments in unconsolidated affiliates 150 150 Other investments 10,474 10,019 Non-utility property - net 3,769 3,569 Goodwill - net 5,557 5,557 Regulatory assets 54,625 44,811 Other assets 688 344 - ------------------------------------------------------------------------------- TOTAL ASSETS $1,131,722 $ 1,069,594 =============================================================================== The accompanying notes are an integral part of these financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY BALANCE SHEETS (In thousands) December 31, - ----------------------------------------------------------------------------------- 2003 2002 - ----------------------------------------------------------------------------------- LIABILITIES & SHAREHOLDER'S EQUITY Capitalization Common shareholder's equity Common stock (no par value) $ 128,258 $ 103,258 Retained earnings 266,911 270,181 - ----------------------------------------------------------------------------------- Total common shareholder's equity 395,169 373,439 - ----------------------------------------------------------------------------------- Cumulative redeemable preferred stock 228 344 Long-term debt payable to third parties - net of current maturities & debt subject to tender 216,330 264,238 Long-term debt payable to VUHI 148,484 86,574 - ----------------------------------------------------------------------------------- Total capitalization 760,211 724,595 - ----------------------------------------------------------------------------------- Commitments & Contingencies (Notes 3, 7, 8, & 9) Current Liabilities Accounts payable 18,437 25,215 Accounts payable to affiliated companies 8,312 10,013 Payables to other Vectren companies 11,456 14,677 Accrued liabilities 38,619 31,247 Short-term borrowings 830 - Short-term borrowings from VUHI 82,929 39,419 Long-term debt subject to tender 9,975 26,640 Current maturities of long-term debt - 1,000 - ----------------------------------------------------------------------------------- Total current liabilities 170,558 148,211 - ----------------------------------------------------------------------------------- Deferred Income Taxes & Other Liabilities Deferred income taxes 109,951 112,004 Regulatory liabilities & other removal costs 48,153 43,936 Deferred credits & other liabilities 42,849 40,848 - ----------------------------------------------------------------------------------- Total deferred income taxes & other liabilities 200,953 196,788 - ----------------------------------------------------------------------------------- TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 1,131,722 $ 1,069,594 ===================================================================================
The accompanying notes are an integral part of these financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (In thousands) Year Ended December 31, - ------------------------------------------------------------------------------ 2003 2002 2001 - ------------------------------------------------------------------------------ OPERATING REVENUES Electric utility $ 335,694 $ 328,620 $ 308,458 Gas utility 102,736 84,392 98,580 - ------------------------------------------------------------------------------ Total operating revenues 438,430 413,012 407,038 - ------------------------------------------------------------------------------ COST OF OPERATING REVENUES Fuel for electric generation 86,477 81,559 74,401 Purchased electric energy 16,172 16,831 14,153 Cost of gas sold 73,427 52,031 72,713 - ------------------------------------------------------------------------------ Total cost of operating revenues 176,076 150,421 161,267 - ------------------------------------------------------------------------------ TOTAL OPERATING MARGIN 262,354 262,591 245,771 OPERATING EXPENSES Other operating 102,994 97,362 104,535 Merger & integration costs - - 588 Restructuring costs - - 5,825 Depreciation & amortization 47,649 45,098 43,287 Income taxes 30,640 30,637 21,648 Taxes other than income taxes 12,448 11,760 13,090 - ------------------------------------------------------------------------------ Total operating expenses 193,731 184,857 188,973 - ------------------------------------------------------------------------------ OPERATING INCOME 68,623 77,734 56,798 Other income - net 5,048 4,794 5,629 Interest expense 24,814 23,168 20,924 - ------------------------------------------------------------------------------ INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 48,857 59,360 41,503 - ------------------------------------------------------------------------------ Cumulative effect of change in accounting principle - net of tax - - 1,107 - ------------------------------------------------------------------------------ NET INCOME 48,857 59,360 42,610 Preferred stock dividends 23 33 758 Loss on extinguishment of preferred stock - - 1,170 - ------------------------------------------------------------------------------ NET INCOME APPLICABLE TO COMMON SHAREHOLDER $ 48,834 $ 59,327 $ 40,682 ============================================================================== The accompanying notes are an integral part of these financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, - ----------------------------------------------------------------------------------------- 2003 2002 2001 - ----------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 48,857 $ 59,360 $ 42,610 Adjustments to reconcile net income to cash from operating activities: Depreciation & amortization 47,649 45,098 43,287 Deferred income taxes & investment tax credits (6,195) (6,461) 467 Pension & postretirement periodic benefit cost 2,896 3,128 2,841 Net unrealized (loss) gain on derivative instruments, including cumulative effect of change in accounting principle (654) 3,585 8,935 Other non-cash charges - net (1,521) 39 (1,936) Changes in working capital accounts: Accounts receivable, including to Vectren companies & accrued unbilled revenue 33,538 (24,950) 19,633 Inventories 2,439 (2,020) (6,578) Recoverable fuel & natural gas costs 5,715 12,591 6,497 Prepayments & other current assets 608 (5,419) (12,054) Accounts payable, including to Vectren companies & affiliated companies (11,700) 34,332 (40,682) Accrued liabilities 9,458 (345) (18,784) Changes in noncurrent assets (6,015) (3,085) (939) Changes in noncurrent liabilities 60 (49) 905 - ----------------------------------------------------------------------------------------- Net cash flows from operating activities 125,135 115,804 44,202 - ----------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt due to VUHI 61,900 37,114 49,460 Additional capital contribution 25,000 25,000 - Requirements for: Dividends to parent (52,104) (45,088) (38,909) Retirement of long-term debt, including premiums paid (68,438) - - Redemption of preferred stock (116) (116) (17,676) Dividends on preferred stock (23) (33) (758) Net change in short-term borrowings, including from VUHI 44,340 (42,119) 41,384 Other activity (1,744) - - - ----------------------------------------------------------------------------------------- Net cash flows from financing activities 8,815 (25,242) 33,501 - ----------------------------------------------------------------------------------------- CASH FLOWS INVESTING ACTIVITIES Proceeds from sale of investments and assets - 1,400 - Requirements for: Capital expenditures (132,420) (89,747) (77,760) Other investments - (1,626) - - ----------------------------------------------------------------------------------------- Net cash flows from investing activities (132,420) (89,973) (77,760) - ----------------------------------------------------------------------------------------- Net increase (decrease) in cash & cash equivalents 1,530 589 (57) Cash & cash equivalents at beginning of period 2,145 1,556 1,613 - ----------------------------------------------------------------------------------------- Cash & cash equivalents at end of period $ 3,675 $ 2,145 $ 1,556 ========================================================================================= Cash paid during the year for: Interest $ 24,512 $ 20,598 $ 18,992 Income taxes 30,595 41,441 47,960
The accompanying notes are an integral part of these financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (In thousands) Common Retained Stock Earnings Total - -------------------------------------------------------------------------------- Balance at January 1, 2001 $ 78,258 $ 261,135 $ 339,393 Net income & comprehensive income 42,610 42,610 Common stock dividends to parent (38,909) (38,909) Preferred stock dividends (758) (758) Distribution of assets to parent (6,966) (6,966) Loss on redemption of preferred stock (1,170) (1,170) - -------------------------------------------------------------------------------- Balance at December 31, 2001 78,258 255,942 334,200 Net income & comprehensive income 59,360 59,360 Common stock: Additional capital contribution 25,000 25,000 Dividends to parent (45,088) (45,088) Preferred stock dividends (33) (33) - -------------------------------------------------------------------------------- Balance at December 31, 2002 103,258 270,181 373,439 - -------------------------------------------------------------------------------- Net income & comprehensive income 48,857 48,857 Common stock: Additional capital contribution 25,000 25,000 Dividends to parent (52,104) (52,104) Preferred stock dividends (23) (23) - -------------------------------------------------------------------------------- Balance at December 31, 2003 $ 128,258 $ 266,911 $ 395,169 ================================================================================ The accompanying notes are an integral part of these financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY NOTES TO THE FINANCIAL STATEMENTS 1. Organization and Nature of Operations Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana corporation, provides electric generation, transmission, and distribution services to 8 counties in southwestern Indiana, including counties surrounding Evansville, and participates in the wholesale power market. SIGECO also provides natural gas distribution and transportation services to 10 counties in southwestern Indiana, including counties surrounding Evansville. SIGECO is a direct subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). SIGECO generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren, an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. Vectren was organized on June 10, 1999, solely for the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with Accounting Principles Board (APB) Opinion No. 16 "Business Combinations." Vectren's wholly owned subsidiary, VUHI, serves as the intermediate holding company for its three operating public utilities: Indiana Gas, formerly a wholly owned subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations. Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935. 2. Summary of Significant Accounting Policies A. 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. B. Inventories Inventories consist of the following: At December 31, - -------------------------------------------------------------------------------- (In thousands) 2003 2002 - -------------------------------------------------------------------------------- Materials & supplies $ 17,304 $ 15,836 Gas in storage - at LIFO cost 8,599 12,880 Fuel (coal and oil) for electric generation 10,680 10,030 Emission allowances 631 907 - -------------------------------------------------------------------------------- Total inventories $ 37,214 $ 39,653 ================================================================================ 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, 2003, and 2002, by approximately $30.1 million and $19.0 million, respectively. Gas in storage of the Indiana regulated operations is stated at LIFO. All other inventories are carried at average cost. C. Utility Plant & Depreciation Utility plant is stated at historical cost, including AFUDC. Depreciation of utility property is provided using the straight-line method over the estimated service lives of the depreciable assets. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:
At & For the Year Ended December 31, - ------------------------------------------------------------------------------------------------- (In thousands) 2003 2002 - ------------------------------------------------------------------------------------------------- Depreciation Depreciation Rates as a Rates as a Percent of Percent of Original Cost Original Cost Original Cost Original Cost - ------------------------------------------------------------------------------------------------- Electric utility plant $ 1,322,365 3.4% $ 1,216,083 3.3% Gas utility plant 170,865 3.0% 164,510 2.9% Common utility plant 44,295 2.7% 41,621 2.6% Construction work in progress 122,002 - 108,927 - - ------------------------------------------------------------------------------------------------- Total original cost $ 1,659,527 $ 1,531,141 =================================================================================================
AFUDC represents the cost of borrowed and equity funds used for construction purposes and is charged to construction work in progress during the construction period and is included in Other - net in the 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 thousands) 2003 2002 2001 - ------------------------------------------------------------------------------- AFUDC - equity funds $ 2,863 $ 1,746 $ 1,653 AFUDC - borrowed funds 1,904 1,933 1,371 - ------------------------------------------------------------------------------- Total AFUDC capitalized $ 4,767 $ 3,679 $ 3,024 =============================================================================== Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred unless deferral is authorized by a rate order. When property that represents a retirement unit is replaced or removed, the cost of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation and Regulatory liabilities for the cost of removal. D. 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. E. 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 changed the accounting for goodwill from an amortization approach to an impairment-only approach. Thus, amortization of goodwill that was not included as an allowable cost for rate-making purposes ceased upon SFAS 142's adoption. Goodwill is to be tested for impairment at a reporting unit level at least annually. The impairment review consists of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Prior to the adoption of SFAS 142, the Company amortized goodwill on a straight-line basis over 40 years. SFAS 142 required an initial impairment review of all goodwill within six months of the adoption date. As required by SFAS 142, amortization of goodwill ceased on January 1, 2002. Amortization approximated $0.2 million ($0.1 million after tax) in 2001. The Company's goodwill is included in the Gas Utility Services operating segment. Initial impairment reviews to be performed within six months of adoption of SFAS 142 were completed and resulted in no impairment. The impairment test is performed at the beginning of each year. F. Regulation SFAS 71 Retail public utility operations affecting Indiana customers are subject to regulation by the IURC. 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 thousands) 2003 2002 - ------------------------------------------------------------------------------- Future amounts recoverable from ratepayers: Income taxes $ 9,184 $ 7,334 Other 858 - - ------------------------------------------------------------------------------- 10,042 7,334 Amounts deferred for future recovery: Demand side management programs 24,888 23,844 Other 5,347 3,713 - ------------------------------------------------------------------------------- 30,235 27,557 Amounts currently recovered through base rates: Unamortized debt issue costs 4,515 3,011 Premiums paid to reacquire debt 5,915 3,739 Demand side management programs 2,746 3,170 - ------------------------------------------------------------------------------- 13,176 9,920 Amounts currently recovered through authorized Indiana tracking mechanisms 1,172 - - ------------------------------------------------------------------------------- Total regulatory assets $ 54,625 $ 44,811 =============================================================================== The $13.2 million currently being recovered through base rates is earning a return with a weighted average recovery period of 15.4 years. The Company has rate orders for all deferred costs not yet in rates and therefore believes that future recovery is probable. Regulatory liabilities & other removal costs consist of the following: At December 31, - ------------------------------------------------------------------------------- (In thousands) 2003 2002 - ------------------------------------------------------------------------------- Cost of removal $ 48,153 $ - Other removal costs - 43,936 - ------------------------------------------------------------------------------- Total regulatory liabilities & other removal costs $ 48,153 $ 43,936 =============================================================================== SFAS 143 & Other Removal Costs In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company's results of operations. The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. As of December 31, 2003, and 2002, such removal costs approximated $48 million and $44 million, respectively. In 2002, the cost of removal has been included in Other removal costs, which is in noncurrent liabilities. In 2003, the Company re-characterized other removal costs to Regulatory liabilities upon adoption of SFAS 143. 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 and the net energy cost of purchased power. Metered electric rates also allow recovery, through a quarterly rate adjustment mechanism, for the margin on electric sales lost due to the implementation of demand side management programs. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel for electric generation is charged to operating expense when consumed. G. 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. H. 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. Excise and utility receipts taxes paid are recorded as a component of Taxes other than income taxes. I. Earnings Per Share Earnings per share are not presented as SIGECO's common stock is wholly owned by Vectren Utility Holdings, Inc. J. Other Significant Policies Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 3) and derivatives (Note 10). K. 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. L. Reclassification Certain prior year amounts have been reclassified in the financial statements and accompanying notes to conform to 2003 classifications. 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. SIGECO received corporate allocations totaling $42.3 million, $45.2 million, and $43.5 million for the years ended December 31, 2003, 2002, and 2001, 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, 2003, 2002, and 2001, totaled $77.0 million, $62.1 million, and $58.4 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 FAS 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, 2003, 2002, and 2001, periodic pension costs totaling $2.4 million, $2.6 million and $2.3 million, respectively, was directly charged by Vectren to the Company. For the years ended December 31, 2003, 2002, and 2001, other periodic postretirement benefit costs totaling $0.5 million, $0.6 million, and $0.5 million, respectively, was directly charged by Vectren to the Company. As of December 31, 2003, and 2002, $26.4 million and $24.1 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. The recently enacted Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) provides a prescription drug benefit as well as a federal subsidy to sponsors of certain retiree health care benefit plans. As allowed by FASB Staff Position No. 106-1 (FSP 106-1), Vectren has elected to defer reflecting the effects of the Medicare Act on the accumulated benefit obligation and net periodic postretirement benefit cost in its 2003 financial statements. Vectren's deferral election expires upon the occurrence of any event that triggers a required remeasurement of plan assets or obligations, or upon the issuance of specific authoritative guidance on the accounting for the federal subsidy. Such guidance is pending and when issued could require the Company to adjust previously reported information. Upon expiration of Vectren's deferral or the issuance of guidance, Vectren's implementation of the Medicare Act may impact SIGECO's financial statements. 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. See Note 5 regarding long-term and short-term intercompany borrowing arrangements. Guarantees of Parent Company Debt Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of VUHI's $346 million commercial paper program, of which approximately $184.4 million is outstanding at December 31, 2003, and VUHI's $550 million unsecured senior notes outstanding at December 31, 2003. The guarantees are full and unconditional and joint and several, and VUHI has no subsidiaries other than the subsidiary guarantors. Equity-Based Incentive Plans The Company does not have equity-based compensation plans separate from Vectren. An insignificant number of the Company's employees participate in Vectren's equity-based compensation plans. Income Taxes Vectren and subsidiary companies file a consolidated federal income tax return. For financial reporting purposes, SIGECO's current and deferred tax expense is computed on a separate company basis. The components of income tax expense and utilization of investment tax credits follow: Year Ended December 31, - -------------------------------------------------------------------------------- (In thousands) 2003 2002 2001 - -------------------------------------------------------------------------------- Current: Federal $ 27,440 $ 30,300 $ 18,403 State 9,447 5,766 2,999 - -------------------------------------------------------------------------------- Total current taxes 36,887 36,066 21,402 - -------------------------------------------------------------------------------- Deferred: Federal (2,358) (1,199) 1,640 State (2,534) (3,916) 180 - -------------------------------------------------------------------------------- Total deferred taxes (4,892) (5,115) 1,820 - -------------------------------------------------------------------------------- Amortization of investment tax credits (1,303) (1,346) (1,353) - -------------------------------------------------------------------------------- Total income tax expense 30,692 29,605 21,869 Less: Income tax expense included in other - net 52 (1,032) 221 - -------------------------------------------------------------------------------- Total income tax expense in operating income $ 30,640 $ 30,637 $ 21,648 ================================================================================ A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, - -------------------------------------------------------------------------------- 2003 2002 2001 - -------------------------------------------------------------------------------- Statutory rate 35.0 % 35.0 % 35.0 % State & local taxes, net of federal benefit 5.6 2.2 2.9 Amortization of investment tax credit (1.6) (1.5) (2.2) All other - net (0.4) (2.4) (0.8) - -------------------------------------------------------------------------------- Effective tax rate 38.6 % 33.3 % 34.9 % ================================================================================ 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 thousands) 2003 2002 - ------------------------------------------------------------------------------ Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 111,404 $ 119,739 Regulatory assets recoverable through future rates 15,614 23,352 Regulatory liabilities to be settled through future rates (6,430) (16,018) Employee benefit obligations (10,371) (13,585) Other - net (266) (1,484) - ------------------------------------------------------------------------------ Net noncurrent deferred tax liability 109,951 112,004 - ------------------------------------------------------------------------------ Current deferred tax liability: Deferred fuel costs - net 3,691 4,680 - ------------------------------------------------------------------------------ Net current deferred tax liability 3,691 4,680 - ------------------------------------------------------------------------------ Net deferred tax liability $ 113,642 $ 116,684 ============================================================================== At December 31, 2003, and 2002, investment tax credits totaling $11.9 million and $13.2 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. The Company has no tax credit carryforwards at December 31, 2003. 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 Indiana Gas, the Ohio operations, Citizens Gas and others. ProLiance also began providing service to SIGECO in 2002. ProLiance's primary business is optimizing the gas portfolios of utilities and providing services to large end use customers. Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2003 and 2002, totaled $72.8 million and $25.6 million, respectively. Amounts owed to ProLiance at December 31, 2003, and 2002, for those purchases were $8.3 million and $10.0 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility. 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, 2003, 2002, and 2001, fees for these services and construction-related expenditures paid by the Company to Vectren affiliates totaled $0.3 million, less than $0.1 million, and zero in 2001, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates other than ProLiance totaled less than $0.1 million and zero at December 31, 2003, and 2002, respectively. 5. Borrowing Arrangements & Other Financing Transactions Short-Term Borrowings SIGECO mainly relies on the short-term borrowing arrangements of VUHI for its short-term working capital needs. Borrowings, including third party borrowings, outstanding at December 31, 2003, and 2002, were $83.8 million and $39.4 million, respectively. The intercompany credit line totals $150 million, but periodically may be limited by VUHI's available capacity ($162 million of additional capacity at December 31, 2003) and is subject to the same terms and conditions as VUHI's commercial paper program. Short-term borrowings bear interest at VUHI's weighted average daily cost of short-term funds. Additionally, at December 31, 2003, the Company has approximately $5 million of short-term borrowing capacity with third parties to supplement its intercompany borrowing arrangements, of which $4.2 million is available. See the table below for interest rates and outstanding balances:
Year ended December 31, - ------------------------------------------------------------------------------------- 2003 2002 2001 - ------------------------------------------------------------------------------------- Weighted average total outstanding during the year payable to VUHI (in thousands) $ 41,456 $ 68,034 $ 34,791 Weighted average total outstanding during the year payable to third parties (in thousands) $ 928 $ 1,875 $ 12,930 Weighted average interest rates during the year: VUHI 1.31% 2.03% 5.24% Bank loans 1.86% 2.56% 5.77%
Long-Term Debt Senior unsecured obligations and first mortgage bonds outstanding and classified as long-term follow: At December 31, - ------------------------------------------------------------------------------- (In thousands) 2003 2002 - ------------------------------------------------------------------------------- Senior Unsecured Notes Payable to VUHI: 2011, 6.625% $ 86,584 $ 86,574 2018, 5.75% 61,900 - - ------------------------------------------------------------------------------- Total long-term debt payable to VUHI $ 148,484 $ 86,574 =============================================================================== First Mortgage Bonds Payable to Third Parties: 2003, 1978 Series B, 6.25%, tax exempt $ - $ 1,000 2016, 1986 Series, 8.875% 13,000 13,000 2023, Series, 7.60% - 45,000 2023, Series B, 6.00%, tax exempt 22,800 22,800 2025, 1993 Series, 7.625% - 20,000 2029, 1999 Senior Notes, 6.72% 80,000 80,000 2015, 1985 Pollution Control Series A, adjustable rate presently 4.30%, tax exempt, next rate adjustment: 2004 9,975 9,975 2025, 1998 Pollution Control Series A, adjustable rate presently 4.75%, tax exempt, next rate adjustment: 2006 31,500 31,500 '2024, 2000 Environmental Improvement Series A, fixed in April 2003 at 4.65%, tax exempt, weighted average for year: 3.69% 22,500 22,500 - ------------------------------------------------------------------------------- Total first mortgage bonds 179,775 245,775 - ------------------------------------------------------------------------------- Senior Unsecured Bonds Payable to Third Parties: 2020, 1998 Pollution Control Series B, fixed in April 2003 at 4.50%, tax exempt, weighted average for year: 4.16% 4,640 4,640 2030, 1998 Pollution Control Series B, fixed in April 2003 at 5.00%, tax exempt, weighted average for year: 4.48% 22,000 22,000 2030, 1998 Pollution Control Series C, adjustable rate presently 5.00%, tax exempt, next rate adjustment: 2006 22,200 22,200 - ------------------------------------------------------------------------------- Total senior unsecured bonds 48,840 48,840 - ------------------------------------------------------------------------------- Total long-term debt outstanding payable to third parties 228,615 294,615 Long-term debt subject to tender (9,975) (26,640) Current maturities of long-term debt - (1,000) Unamortized debt premium & discount & other - net (2,310) (2,737) - ------------------------------------------------------------------------------- Long-term debt payable to third parties - net of current maturities & debt subject to tender $ 216,330 $ 264,238 =============================================================================== Issuance Payable to VUHI in 2003 In 2003, the Company issued $61.9 million of long-term debt payable to VUHI. The note has terms identical to the terms of notes issued by VUHI in July 2003 through a public offering. Those notes have an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity and are due August 2018. 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 VUHI's indenture, plus 25 basis points. Issuances Payable to VUHI in 2001 and 2002 In 2001, the Company issued a note payable to VUHI for $49.5 million, and in 2002 issued a note payable to VUHI for $37.1 million. These two notes comprise the $86.6 million of long-term debt due to VUHI at December 31, 2002. The terms of these notes are identical to the terms of notes issued by VUHI in December 2001 through a public offering (December Notes). The December Notes have an aggregate principal amount of $250.0 million and an interest rate of 6.625%, priced at 99.302% to yield 6.69% to maturity. The December Notes have no sinking fund requirements, and interest payments are due semi-annually. The December Notes are due December 2011, but 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 of the notes to be redeemed 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 VUHI's indenture, plus 25 basis points. Debt Call During 2003, the Company called two first mortgage bonds. The first 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 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. Pursuant to regulatory authority, the premiums paid to retire the net carrying value of these notes totaling $2.4 million were deferred in Regulatory assets. The proceeds to fund the early redemption were received from VUHI in the form of new long-term debt discussed above and $25 million in additional equity. To generate the initial proceeds to fund these transactions, in July 2003, VUHI completed a public offering of long-term debt netting proceeds of approximately $203 million, and, in August 2003, Vectren completed a public offering of common stock netting proceeds of approximately $163 million. Other Financing Transactions 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. The bonds are now classified in Long-term debt. 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. 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 2004 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2004 is excluded from Current liabilities in the Balance Sheets. At December 31, 2003, $502.0 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. There are no maturities and/or sinking fund requirements on long-term debt during the five years following 2003. 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. Debt which may be put to the Company during the years following 2003 (in millions) is $10.0 in 2004, zero in 2005, $53.7 in 2006, zero in 2007, zero in 2008, and $80.0 thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities. 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, 2003, the Company was in compliance with all financial covenants. 6. Cumulative Preferred Stock Redemption of Preferred Stock Nonredeemable preferred stock containing call options was redeemed during September 2001 for a total redemption price of $9.8 million. The 4.80%, $100 par value preferred stock was redeemed at its stated call price of $110 per share, plus accrued and unpaid dividends totaling $1.35 per share. The 4.75%, $100 par value preferred stock was redeemed at its stated call price of $101 per share, plus accrued and unpaid dividends totaling $0.97 per share. Prior to the redemptions, there were 85,519 shares of the 4.80% Series outstanding and 3,000 shares of the 4.75% Series outstanding. In September 2001, the 6.50%, $100 par value of redeemable preferred stock was redeemed for a total redemption price of $7.9 million at $104.23 per share, plus $0.73 per share in accrued and unpaid dividends. Prior to the redemption, there were 75,000 shares outstanding. The loss on redemption of $1.2 million in 2001 is reflected in Retained earnings. Redeemable, Special This series of redeemable preferred stock has a dividend rate of 8.50% and in the event of involuntary liquidation the amount payable is $100 per share, plus accrued dividends. This series may be redeemed at $100 per share, plus accrued dividends on any of its dividend payment dates, and is also callable at the Company's option at a rate of 1,160 shares per year. As of December 31, 2003, and 2002, there were 2,277 shares and 3,437 shares outstanding, respectively. 7. Commitments & Contingencies Commitments Firm purchase commitments for commodities total (in millions) $26.3 in 2004 and $8.4 in 2005. Firm purchase commitment for utility and non-utility plant total $98.4 million. United States Securities and Exchange Commission (SEC) Informal Inquiry As more fully described in the 2002 financial statements, the Company restated its annual financial statements for 2000 and 2001, and its 2002 quarterly results. The Company received an informal inquiry from the SEC with respect to this restatement. In response, the Company met with the SEC staff and provided information in response to their requests, with the most recent response provided on July 26, 2003. Legal Proceedings The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 8 regarding environmental matters. 8. Environmental Matters Clean Air Act NOx SIP Call Matter The Clean Air Act (the Act) requires each state to adopt a State Implementation Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS) for a number of pollutants, including ozone. If the USEPA finds a state's SIP inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its SIP (a SIP Call). In October 1998, the USEPA issued a final rule "Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed. Reg. 57355). This ruling found that the SIP's of certain states, including Indiana, were substantially inadequate since they allowed for nitrogen oxide (NOx) emissions in amounts that contributed to non-attainment with the ozone NAAQS in downwind states. The USEPA required each state to revise its SIP to provide for further NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx emissions from Indiana. In June 2001, the Indiana Air Pollution Control Board adopted final rules to achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP requires the Company to lower its system-wide NOx emissions to .141 lbs./MMBTU by May 31, 2004, (the compliance date). This is a 65% reduction in emission levels. The Company has initiated steps toward compliance with the revised regulations. These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to currently be the most effective method of reducing 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 eight percent return on its weighted capital costs for the project; and o ongoing recovery of operating costs, including depreciation and purchased emission allowances through a rider mechanism, 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 clean coal technology construction cost is consistent with amounts approved in the IURC's orders and is expected to be expended during the 2001-2006 period. Through December 31, 2003, $145.2 million has been expended. After the equipment is installed and operational, related annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million. A portion of those expenses began in October 2003 when the Culley SCR became operational. The 8 percent 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 expects to achieve timely compliance as a result of the project. Construction of the first SCR at Culley was placed into service in October 2003, and construction of the Warrick 4 and Brown SCR's is proceeding on schedule. Installation of SCR technology as planned is expected to reduce the Company's overall NOx emissions to levels compliant with Indiana's NOx emissions budget allotted by the USEPA. Therefore, the Company has recorded no accrual for potential penalties that may result from noncompliance. Culley Generating Station Litigation In the late 1990's, the USEPA initiated an investigation under Section 114 of the Act of SIGECO's coal-fired electric generating units in commercial operation by 1977 to determine compliance with environmental permitting requirements related to repairs, maintenance, modifications, and operations changes. The focus of the investigation was to determine whether new source review permitting requirements were triggered by such plant modifications, and whether the best available control technology was, or should have been used. Numerous electric utilities were, and are currently, being investigated by the USEPA under an industry-wide review for compliance. In July 1999, SIGECO received a letter from the Office of Enforcement and Compliance Assurance of the USEPA discussing the industry-wide investigation, vaguely referring to an investigation of SIGECO and inviting SIGECO to participate in a discussion of the issues. No specifics were noted; furthermore, the letter stated that the communication was not intended to serve as a notice of violation. Subsequent meetings were conducted in September and October 1999 with the USEPA and targeted utilities, including SIGECO, regarding potential remedies to the USEPA's general allegations. On November 3, 1999, the USEPA filed a lawsuit against seven utilities, including SIGECO. SIGECO's suit was filed in the U.S. District Court for the Southern District of Indiana. The USEPA alleged that, beginning in 1992, SIGECO violated the Act by (1) making modifications to its Culley Generating Station in Yankeetown, Indiana without obtaining required permits, (2) making major modifications to the Culley Generating Station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications. In addition, the lawsuit alleged that the modifications to the Culley Generating Station required SIGECO to begin complying with federal new source performance standards at its Culley Unit 3. The USEPA also issued an administrative notice of violation to SIGECO making the same allegations, but alleging that violations began in 1977. On June 6, 2003, SIGECO, the Department of Justice (DOJ), and the USEPA announced an agreement that would resolve the lawsuit. The agreement was embodied in a consent decree filed in U.S. District Court for the Southern District of Indiana. The mandatory public comment period has expired, and no comments were received. The Court entered the consent decree on August 13, 2003. Under the terms of the agreement, the DOJ and USEPA have agreed to drop all challenges of past maintenance and repair activities at the Culley coal-fired units. 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 has 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 has committed to: o either repower Culley Unit 1 (50 MW) with natural gas, which would significantly reduce air emissions from this unit, 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 anticipates that the settlement would result in total capital expenditures through 2007 in a range between $16 million and $28 million. Other than the $600,000 civil penalty, which was accrued in the second quarter of 2003, the implementation of the settlement, including these capital expenditures and related operating expenses, are expected to be recovered through rates. Information Request On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested with the most recent correspondence provided on March 26, 2001. Manufactured Gas Plants 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 is adding its 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. The total costs, net of other potentially responsible parties involvement and insurance recoveries, that may be incurred in connection with further investigation, and if necessary, remedial work at the four SIGECO sites cannot be determined at this time. 9. Rate & Regulatory Matters As a result of an appeal of a generic order issued by the IURC in August 1999 regarding guidelines for the recovery of purchased power costs, SIGECO entered into a settlement agreement with the OUCC that provides certain terms with respect to the recoverability of such costs. The settlement, originally approved by the IURC in August 2000, has been extended by agreement through March 2004, and discussions regarding further extension of the settlement term are ongoing. Under the settlement, SIGECO can recover the entire cost of purchased power up to an established benchmark, and during forced outages, SIGECO will bear a limited share of its purchased power costs regardless of the market costs at that time. Based on this agreement, SIGECO believes it has limited its exposure to unrecoverable purchased power costs. 10. 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. 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 all 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 retail and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of these contracts are integrated with portfolio requirements around power supply and delivery and are primarily short-term purchase and sale contracts that expose the Company to limited market risk. Contracts with counter-parties subject to master netting arrangements are presented net in the Balance Sheets. Asset optimization contracts are recorded at market value. Changes in market value, which is a function of the normal decline in market value as earnings are realized and the fluctuation in market value resulting from price volatility, are recorded in Electric utility revenues. Asset optimization contracts recorded at market value at December 31, 2003, totaled $2.4 million of Prepayments & other current assets and $2.8 million of Accrued liabilities, compared to $3.5 million of Prepayments & other current assets and $4.2 million of Accrued liabilities at December 31, 2002. In July 2003, the EITF released EITF 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not "Held for Trading Purposes" as Defined in Issue No. 02-3" (EITF 03-11). EITF 03-11 states that determining whether realized gains and losses on physically settled derivative contracts should be reported in the Statement of Income on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The EITF contains a presumption that net settled derivative contracts should be reported net in the Statement of Income. The Company adopted EITF 03-11 as required on October 1, 2003. After considering the facts and circumstances relevant to the asset optimization portfolio, the Company believes presentation of these optimization activities on a net basis is appropriate and has reclassified purchase contracts and mark-to-market activity related to optimization activities from Purchased electric energy to Electric utility revenues. Prior year financial information has also been reclassified to conform to this net presentation. Following is information regarding asset optimization activities included in Electric utility revenues and Fuel for electric generation in the Statements of Income: Year Ended December 31, - ---------------------------------------------------------------------------- 2003 2002 2001 - ---------------------------------------------------------------------------- Activity related to: Sales contracts $ 152,795 $ 302,764 $ 101,418 Purchase contracts (126,969) (275,851) (74,311) Mark-to-market gains (losses) 654 (3,585) 1,537 - ---------------------------------------------------------------------------- Net asset optimization revenue 26,480 23,328 28,644 - ---------------------------------------------------------------------------- Fuel for electric generation (8,203) (10,601) (9,539) - ---------------------------------------------------------------------------- Asset optimization margin $ 18,277 $ 12,727 $ 19,105 ============================================================================ Natural Gas Procurement Activity The Company's operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Although the Company's 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. The market value of natural gas procurement derivative contracts at December 31, 2003, was not significant. Impact of Adoption of SFAS 133 In June 1998, the FASB issued SFAS 133 which required that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met. SFAS 133, as amended, required that as of the date of initial adoption, the difference between the market value of derivative instruments recorded on the balance sheet and the previous carrying amount of those derivatives be reported in net income or other comprehensive income, as appropriate. Resulting from the adoption of SFAS 133, certain asset optimization contracts that are periodically settled net were required to be recorded at market value. Previously, the Company accounted for these contracts on settlement. The cumulative impact of the adoption of SFAS 133 resulting from marking these contracts to market on January 1, 2001, was an earnings gain of approximately $1.8 million ($1.1 million net of tax) recorded as a cumulative effect of accounting change. SFAS 133 did not impact other commodity contracts because they were normal purchases and sales specifically excluded from the provisions of SFAS 133 and did not impact the Company's cash flow hedges because they had no value on the date of adoption. Fair Value of Other Financial Instruments The carrying values and estimated fair values of the Company's other financial instruments follow:
At December 31, - ------------------------------------------------------------------------------------- 2003 2002 ---------------------- ---------------------- Carrying Est. Fair Carrying Est. Fair (In thousands) Amount Value Amount Value - ----------------------------------- --------- --------- --------- --------- Long term debt $ 228,615 $ 239,407 $ 294,615 $ 313,202 Long term debt payable to VUHI 148,484 159,927 86,574 93,820 Short-term borrowings 830 830 - - Short-term borrowings from VUHI 82,929 82,929 39,419 39,419
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's other financial instruments was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value. Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's financial position or results of operations. 11. Segment Reporting The Company has two operating segments: (1) Gas Utility Services and (2) Electric Utility Services as defined by SFAS 131 "Disclosure About Segments of an Enterprise and Related Information" (SFAS 131). Gas Utility Services provides natural gas distribution and transportation services in southwestern Indiana, including counties surrounding Evansville. Electric Utility Services provides electricity primarily to southwestern Indiana, and includes the Company's power generating and marketing operations. For its operations the Company uses after tax operating income as a measure of profitability, consistent with regulatory reporting requirements. The Company cross manages its margin, other operating expenses, and capital expenditures 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. The Company makes decisions on finance and dividends at the corporate level. Information related to the Company's business segments is summarized below:
Year Ended December 31, - ------------------------------------------------------------------------------------ (In thousands) 2003 2002 2001 - ------------------------------------------------------------------------------------ Revenues Electric Utility Services $ 335,694 $ 328,620 $ 308,458 Gas Utility Services 102,736 84,392 98,580 - ------------------------------------------------------------------------------------ Total operating revenues $ 438,430 $ 413,012 $ 407,038 ==================================================================================== Profitability Measure Operating Income Electric Utility Services $ 63,767 $ 73,152 $ 56,490 Gas Utility Services 4,856 4,582 308 - ------------------------------------------------------------------------------------ Total operating income $ 68,623 $ 77,734 $ 56,798 ==================================================================================== Amounts Included in Profitability Measures Depreciation & Amortization Electric Utility Services $ 42,627 $ 40,003 $ 38,691 Gas Utility Services 5,022 5,095 4,596 - ------------------------------------------------------------------------------------ Total depreciation & amortization $ 47,649 $ 45,098 $ 43,287 ==================================================================================== Income Taxes Electric Utility Services $ 29,808 $ 27,500 $ 21,058 Gas Utility Services 832 3,137 590 - ------------------------------------------------------------------------------------ Total income taxes $ 30,640 $ 30,637 $ 21,648 ====================================================================================
At December 31, - ----------------------------------------------------------------------- (In thousands) 2003 2002 - ----------------------------------------------------------------------- Assets Electric Utility Services $ 974,576 $ 891,612 Gas Utility Services 157,146 177,982 - ----------------------------------------------------------------------- Total assets $1,131,722 $1,069,594 =======================================================================
Year Ended December 31, - ------------------------------------------------------------------------------------ (In thousands) 2003 2002 2001 - ------------------------------------------------------------------------------------ Capital Expenditures Electric Utility Services $ 124,058 $ 88,804 $ 69,833 Gas Utility Services 8,362 943 7,927 - ------------------------------------------------------------------------------------ Total capital expenditures $ 132,420 $ 89,747 $ 77,760 ====================================================================================
12. Additional Operational & Balance Sheet Information Other - net in the Statements of Income consists of the following:
Year ended December 31, - ------------------------------------------------------------------------------------ (In thousands) 2003 2002 2001 - ------------------------------------------------------------------------------------ AFUDC $ 4,767 $ 3,679 $ 3,024 Other income 1,699 2,394 5,923 Other expense (1,418) (1,279) (3,318) - ------------------------------------------------------------------------------------ Total other - net $ 5,048 $ 4,794 $ 5,629 ====================================================================================
Accrued liabilities in the Balance Sheets consist of the following: At December 31, - ----------------------------------------------------------------------- (In thousands) 2003 2002 - ----------------------------------------------------------------------- Accrued taxes $ 15,979 $ 8,707 Deferred income taxes 3,691 4,680 Accrued interest 5,710 6,127 Refunds to customers & customer deposits 5,124 4,576 Accrued salaries & other 8,115 7,157 - ----------------------------------------------------------------------- Total accrued liabilities $ 38,619 $ 31,247 ======================================================================= 13. Special Charges for 2001 Restructuring & Related Charges As part of continued cost saving efforts, in June 2001, Vectren's management and the board of directors approved a plan to restructure, primarily, its regulated operations. The restructuring plan included the elimination of certain administrative and supervisory positions in its utility operations and corporate office. Charges of $4.3 million were expensed in June 2001 as a direct result of the restructuring plan. Additional charges of $1.5 million were incurred during the remainder of 2001 primarily for consulting fees and employee relocation costs. In total, the Company incurred restructuring charges of $5.8 million. These charges were comprised of $4.4 million for employee severance, related benefits, and other employee related costs, and $1.4 million for consulting and other fees incurred. The $4.4 million of severance and related costs included $0.8 million of non-cash pension costs. Restructuring expenses were incurred by the Company's operating segments as follows: $1.0 million by the Gas Utility Services segment and $4.8 million by the Electric Utility Services segment. Employee severance and related costs are associated with approximately 40 employees. Employee separation benefits include severance, healthcare, and outplacement services. During 2001, 37 employees had exited the business. The restructuring program was completed during 2001, except for the departure of the remaining employees impacted by the restructuring which occurred during 2002. At the beginning of 2002, the remaining accrual related to the restructuring was $0.2 million. Of that amount, almost all relates to structured compensation arrangements payable through 2004. During 2003 and 2002, the accrual for severance did not substantially change. At December 31, 2003, and 2002, the restructuring accrual was $0.6 million and $0.9 million, respectively. The restructuring accrual is included in Accrued liabilities. Merger & Integration Costs Merger and integration costs incurred for the year ended December 31, 2001, totaled $0.6 million. Those costs related primarily to transaction costs, severance, and other merger and acquisition integration activities. The integration activities experienced by the Company included such things as information system consolidation, process review and definition, organization design and consolidation, and knowledge sharing. Merger and integration activities resulting from the 2000 merger were completed in 2001. 14. Impact of Recently Issued Accounting Guidance SFAS 149 In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and clarifies the accounting guidance on (1) derivative instruments (including certain derivative instruments embedded in other contracts) and (2) hedging activities that fall within the scope of FASB Statement No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities." SFAS 149 amends SFAS 133 to reflect decisions that were made (1) as part of the process undertaken by the Derivatives Implementation Group (DIG), which necessitated amending SFAS 133, (2) in connection with other projects dealing with financial instruments, and (3) regarding implementation issues related to the application of the definition of a derivative. SFAS 149 also amends certain other existing pronouncements which will result in more consistent reporting of contracts that are derivatives in their entirety or that contain embedded derivatives that warrant separate accounting. SFAS 149 is effective (1) for contracts entered into or modified after June 30, 2003, with certain exceptions and (2) for hedging relationships designated after June 30. The guidance is to be applied prospectively. The adoption did not have a material effect on the Company's results of operations or financial condition. SFAS 150 In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS 150). SFAS 150 requires issuers to classify as liabilities the following three types of freestanding financial instruments: mandatorily redeemable financial instruments, obligations to repurchase the issuer's equity shares by transferring assets, and certain obligations to issue a variable number of shares. SFAS 150 was effective immediately for financial instruments entered into or modified after May 31, 2003; otherwise, the standard was effective for all other financial instruments at the beginning of the Company's third quarter of 2003. In October 2003, the FASB issued further guidance regarding mandatorily redeemable stock which is effective January 1, 2004, for the Company. The adoption of SFAS 150 on January 1, 2004, did not affect the Company's results of operations or financial condition. FASB Interpretation (FIN) 45 In November 2002, the FASB issued FIN 45. FIN 45 clarifies the requirements for a guarantor's accounting for and disclosure of certain guarantees issued and outstanding and that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligations it has undertaken. The initial recognition and measurement provisions were applicable on a prospective basis to guarantees issued or modified after December 31, 2002. Since that date, the adoption has not had a material effect on the Company's results of operations or financial condition. FIN 46/46-R (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 46-R). FIN 46-R 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 46 is to be adopted no later than the end of the first interim or annual reporting period ending after March 15, 2004. Although management is still evaluating the impact of FIN 46 and related Staff Positions on its financial position and results of operations, the adoption is not expected to have a material effect. Staff Accounting Bulletin No. 104 In December 2003, the SEC published Staff Accounting Bulletin (SAB) No. 104, "Revenue Recognition". This SAB updates portions of the SEC staff's interpretive guidance provided in SAB 101 and included in Topic 13 of the Codification of Staff Accounting Bulletins. SAB 104 deletes interpretative material no longer necessary and conforms the interpretive material retained because of pronouncements issued by the FASB's EITF on various revenue recognition topics, including EITF 00-21, "Revenue Arrangements with Multiple Deliverables." The Company's adoption of the standard did not have an impact on its revenue recognition policies. 15. Subsequent Event On March 12, 2004, SIGECO (d/b/a Vectren Energy Delivery of Indiana, Inc.) filed a petition with the IURC to adjust its base rates and charges for its gas distribution business in southwestern Indiana. If the filing is approved, SIGECO expects to increase its base (non-gas cost) rates by approximately $5.7 million to cover the ongoing cost of operating and maintaining the approximately 3,000-mile distribution and storage system used to serve more than 110,000 customers. If finalized by the OUCC and ultimately approved by the IURC, the agreement in principle would result in about a 5 percent increase for the typical SIGECO residential customer who uses natural gas to heat his/her home. The proposal will not affect the electric portion of the Company's customer bills. The petition only addresses "non-gas" costs, which are incurred to build, operate and maintain the pipes, other equipment and systems that are used to deliver gas. The petition indicates that SIGECO has reached an agreement in principle with the OUCC regarding the proposed changes to the rates and charges. The agreement in principle further provides for SIGECO's recovery through a tracking mechanism of costs required to comply with a new federal law dealing with pipeline safety. As required by the regulatory process, SIGECO will be required to submit information substantiating the proposed adjustment to its base rates. During the processing of the case by the IURC, there will also be one or more public hearings conducted regarding the proposal. The timing and ultimate outcome of this regulatory initiative is uncertain. 16. Quarterly Financial Data (Unaudited) Quarterly operating revenues presented below have been adjusted to reflect the adoption of EITF 03-11. See Note 10 to the financial statements for further information on the adoption of EITF 03-11. 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 2003 and 2002 follows: - ---------------------------------------------------------------------------- (In thousands) Q1 Q2 Q3 Q4 - ---------------------------------------------------------------------------- 2003 Results of Operations: Operating revenues $135,067 $89,600 $106,257 $107,506 Operating margin 68,325 56,685 71,328 66,016 Operating income 17,883 12,781 21,361 16,598 Net income applicable to common shareholder 13,381 6,050 16,182 13,221 2002 Results of Operations: Operating revenues $ 99,945 $94,241 $108,636 $110,190 Operating margin 61,207 59,290 78,766 63,328 Operating income 15,739 13,225 27,013 21,757 Net income applicable to common shareholder 11,435 9,439 22,212 16,241 ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9a. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures As of December 31, 2003, the Company carried out an evaluation under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the effectiveness and the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective 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. Disclosure controls and procedures, as defined by the Exchange Act in Rules 13a-15(e) and 15d-15(e), are controls and other procedures of the Company that are designed to ensure that information required to be disclosed by the Company in the reports filed or submitted by it under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms. "Disclosure controls and procedures" include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in its Exchange Act reports is accumulated and communicated to the Company's management, including its principal executive and financial officers, as appropriate, to allow timely decisions regarding required disclosure. Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2003, there have been no significant changes to the Company's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. Internal control over financial reporting is defined by the SEC in Final Rule: Management's Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports. The final rule defines internal control over financial reporting as a process designed by, or under the supervision of, the registrant's principal executive and principal financial officers, or persons performing similar functions, and effected by the registrant's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (1) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the registrant, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the registrant's assets that could have a material effect on the financial statements. 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 Vectren's directors, officers and employees are available on Vectren'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. Vectren intends to disclose any amendments to the Code of Ethics or waivers of the Code of Ethics on behalf of its 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 Vectren'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 paid to Deloitte & Touche, LLP (Deloitte) for the years ending December 31, 2003, and December 31, 2002. The fees presented below represent total fees incurred by Vectren Corporation, the ultimate parent of the Company. The fees represent amounts applicable to audits and audit-related and tax services for all of Vectren Corporation and its subsidiary companies. - -------------------------------------------------------------------------- 2003 2002 - -------------------------------------------------------------------------- Audit Fees(1) $ 1,187,950 $ 350,000 Audit-Related Fees(2) 234,000 135,555 Tax Fees(3) 92,000 73,625 All Other Fees(4) - - - -------------------------------------------------------------------------- Total Fees Paid to Deloitte $ 1,513,950 $ 559,180 ========================================================================== (1) Aggregate fees incurred payable to Deloitte for professional services rendered for the audit of Vectren's 2003 fiscal year annual financial statements and the review of financial statements included in Vectren's Forms 10-Q filed during Vectren's 2003 fiscal year. This includes fees incurred for audit services related to certain of Vectren's subsidiaries in connection with the audit of Vectren's financial statements. The amount also includes fees paid to Deloitte for the audits of Vectren's 2000 and 2001 financial statements and the completion of the audit of the 2002 financial statements. The 2002 amount relates to the audit of Vectren's 2002 financial statements and reviews of Vectren's Forms 10-Q filed during the 2002 fiscal year. (2) Audit related fees consisted principally of consultation on various accounting issues in 2003 and 2002, and reviews related to various financing transactions completed during 2003. (3) Tax fees consisted of fees paid to Deloitte for tax planning and review of tax returns of Vectren. (4) All Other Fees - None. Pursuant to its charter, Vectren's Audit Committee is responsible for selecting, approving professional fees, and overseeing the independence, qualifications and performance of the independent auditors. 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 auditors. Pre-approval is assessed on a case-by-case basis. In assessing requests for services to be provided by the independent auditors, the Audit committee considers whether such services are consistent with the auditors' independence, whether the independent auditors are likely to provide the most effective and efficient service based upon their familiarity with Vectren, and whether the service could enhance Vectren'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. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K List Of Documents Filed As Part Of This Report Financial Statements The 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, 2003, 2002, and 2001, the Company's Schedule II - -- Valuation and Qualifying Accounts Financial Statement Schedules is presented on page 48. 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 Financial Statements or related notes in Item 8. List of Exhibits The Company has incorporated by reference herein certain exhibits as specified below pursuant to Rule 12b-32 under the Exchange Act. Exhibits for the Company attached to this filing filed electronically with the SEC are listed on page 49. Exhibits for the Company are listed in the Index to Exhibits beginning on page 50. Reports On Form 8-K During The Last Calendar Quarter On October 22, 2003, the Company filed a Current Report on Form 8-K with respect to the release of financial information to the investment community regarding Vectren Corporation's results of operations, financial position and cash flows for the three, nine, and twelve month periods ended September 30, 2003. The financial information was released to the public through this filing. Item 7. Exhibits 99-1 - Press Release - Vectren Corporation Reports Third Quarter 2003 Results 99-2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 Item 12. Results of Operations and Financial Condition On December 11, 2003, the Company filed a Current Report on Form 8-K with respect to an analyst meeting where a discussion of Vectren Corporation's current financial and operating results and plans for the future will occur. Item 9. Regulation FD Disclosure Index to Exhibits 99-1 - Press Release - Vectren Corporation Provides 2004 Earnings Guidance 99-2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 SCHEDULE II
Southern Indiana Gas and Electric Company 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 thousands) VALUATION AND QUALIFYING ACCOUNTS: Year 2003 - Accumulated provision for uncollectible accounts $ 3,662 $ 903 $ - $ 3,363 $ 1,202 Year 2002 - Accumulated provision for uncollectible accounts $ 3,188 $ 2,500 $ - $ 2,026 $ 3,662 Year 2001 - Accumulated provision for uncollectible accounts $ 2,639 $ 2,387 $ - $ 1,838 $ 3,188 OTHER RESERVES: Year 2001 - Reserve for merger and integration charges $ 526 $ - $ - $ 526 $ - Year 2003 - Reserve for restructuring costs $ 850 $ - $ - $ 250 $ 600 Year 2002 - Reserve for restructuring costs $ 180 $ - $ 670 $ - $ 850 Year 2001 - Reserve for restructuring costs $ - $ 3,321 $ - $ 3,141 $ 180
Southern Indiana Gas and Electric Company 2003 Form 10-K Attached Exhibits The following Exhibits were filed electronically with the SEC with this filing. See Page 50 of this Annual Report on Form 10-K for a complete list of exhibits. Exhibit Number Document 4.5 Promissory Note for Long-Term Loans dated September 1, 2003, between Southern Indiana Gas and Electric Company and Vectren Utility Holdings, Inc. 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. INDEX TO EXHIBITS 2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession Not applicable. 3. Articles of Incorporation and By-Laws 3.1 Amended and Restated Articles of Incorporation of Southern Indiana Gas and Electric Company effective January 24, 2003. (Filed and designated in Form 10-K for the year ended December 31, 2002, File No. 1-3553, as Exhibit 3.1.) 3.2 Amended and Restated Code of By-Laws of Southern Indiana Gas and Electric Company as of January 16, 2003. (Filed and designated in Form 10-K for the year ended December 31, 2002, File No. 1-3553, 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.) 4.2 Indenture dated October 19, 2001, among 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, among 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); Third Supplemental Indenture, among 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 July 24, 2003, File No. 1-16739, as Exhibit 4.1). 4.3 Promissory Note for Long-Term Loans dated November 30, 2001, between Southern Indiana Gas and Electric Company and Vectren Utility Holdings, Inc. (Filed and designated in Form 10-K, for the year ended December 31, 2001, File No. 1-3553, as Exhibit 4.4). 4.4 Promissory Note for Long-Term Loans dated December 1, 2002, between Southern Indiana Gas and Electric Company and Vectren Utility Holdings, Inc. (Filed and designated in Form 10-K for the year ended December 31, 2002, File No. 1-3553, as Exhibit 4.4.) 4.5 Promissory Note for Long-Term Loans dated September 1, 2003, between Southern Indiana Gas and Electric Company and Vectren Utility Holdings, Inc. (Filed herewith.) 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 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.) 10.12 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.) 10.13 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.) 10.14 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 1-1567, as Exhibit 10.16.) 10.15 Coal Supply Agreement for F.B. Culley Generating Station between Southern Indiana Gas and Electric Company and Vectren Fuels, Inc., dated December 17, 1997 and effective January 1, 1998. (Filed and designated in Form 10-K, for the year ended December 31, 2003, File No 1-1567, as Exhibit 10.18.). Portions of the document has been omitted pursuant to a request to a request for confidential treatment. 10.16 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 1-1567, as Exhibit 10.19.) 10.17 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 1-1567, as Exhibit 10.20.) 10.18 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 1-1567, as Exhibit 10.21.) 10.19 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 1-1567, as Exhibit 10.22.) 10.20 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 1-1567, as Exhibit 10.23.) 21. Subsidiaries of the Company Not applicable. 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. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY Dated February 25, 2004 /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 /s/ Niel C. Ellerbrook Chairman, Chief Executive February 25, 2004 - -------------------------- Officer, & Director ----------------- Niel C. Ellerbrook (Principal Executive Officer) /s/ Jerome A. Benkert, Jr. Executive Vice President, February 25, 2004 - -------------------------- Chief Financial Officer, & ----------------- Jerome A. Benkert, Jr. Director (Principal Financial Officer) /s/ M. Susan Hardwick Vice President, Controller & February 25, 2004 - -------------------------- Director (Principal Accounting ----------------- M. Susan Hardwick Officer) /s/ Ronald E. Christian Director February 25, 2004 - -------------------------- ----------------- Ronald E. Christian /s/ William S. Doty Director February 25, 2004 - -------------------------- ----------------- William S. Doty /s/ Robert L. Goocher Director February 25, 2004 - -------------------------- ----------------- Robert L. Goocher EX-4.5 3 sig_note-ex.txt PROMISSORY NOTE FOR LONG-TERM EXHIBIT 4.5 PROMISSORY NOTE FOR LONG-TERM LOANS $62,500,000 September 1, 2003 FOR VALUE RECEIVED, Southern Indiana Gas and Electric Company, an Indiana corporation ("Borrower") hereby promises to pay to VECTREN UTILITY HOLDINGS, INC., an Indiana corporation ("Lender"), in same day funds at its principal offices in Evansville, Indiana, or at such other place Lender may from time to time designate, the principal sum of Sixty-two Million, Five Hundred Thousand Dollars ($62,500,000), together with interest thereon from the date hereof until paid in full, all without relief from valuation or appraisement laws. Interest shall be charged on the unpaid outstanding balance of this Note at a rate per annum equal to the rate paid and to be paid by Lender with respect to the borrowings it made in order to provide funds to Borrower hereunder. Interest on borrowings shall be due and payable in immediately available funds on the same business day on which Lender must pay interest on the borrowings it made in order to provide funds to the Borrower hereunder. The principal hereof shall be due and payable hereunder at such times and in such amounts and in such installments hereunder as Lender must pay with respect to the borrowings it made in order to provide funds to Borrower hereunder. Lender has provided Borrower with a copy of the documentation evidencing the borrowings made by Lender in order to provide funds to Borrower hereunder. Borrower's share under this Note of the Lender borrowings represents 62.5% of the underlying 5.75% VUHI Senior Notes due August 1, 2018 and net proceeds approximate $61.9 million. In the absence of manifest error, such documentation and the records maintained by Lender of the amount and term, if any, of borrowings hereunder shall be deemed conclusive. The terms and conditions of the borrowings made by Lender in order to provide funds to Borrower hereunder, such documentation of which is attached hereto, are hereby incorporated by reference and made a part hereof; provided, however, that the principal sum under this Note shall be in such amount as set forth in this Note. In the event of any conflict or inconsistency between the terms of this Note and the terms of the borrowings made by Lender in order to provide funds to Borrower hereunder, the terms of this Note shall govern. Presentment, notice of dishonor and demand, protest and diligence and collection and bringing suit are hereby severally waived by Borrower and each endorser hereby consents that the time for payment of this Note or any installment hereunder may be extended from time to time without notice by Lender. No waiver of any default or failure or delay to exercise any right or remedy by Lender shall operate as a waiver of any other default or of the same default in the future or as a waiver of any right or remedy with respect to the same or any other occurrence. No single or partial exercise by Lender of any right or remedy shall preclude other or further exercises thereof or of any other right or remedy. This Note inures to the benefit of Lender and binds Borrower and Lender's and Borrower's respective successors and assigns, and the terms "Lender" and Borrower" whenever occurring herein shall be deemed and construed to include such respective successors and assigns. This Note shall be construed according to, and governed by, the laws of the State of Indiana. This Note is one of the promissory notes referred to in the Financial Services Agreement, dated January 5th, 2001, and subsequently amended on January 22, 2003, between Lender, Borrower and certain other public utility subsidiaries of Lender to which reference is made for a statement of additional rights and obligations of the parties hereto. IN WITNESS WHEREOF, the Borrower has caused this Note to be executed as of the date and the year first hereinabove written. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY By:/s/Robert L. Goocher ----------------------------- Robert L. Goocher Vice President and Treasurer Principal Amount Underwriter of Initial Underwritten Securities - ----------- ----------------------------------------- Principal Amount of Principal Amount of 5.25% Senior Notes 5.75% Senior Notes ------------------- ------------------- ABN AMRO Incorporated............... $ 34,000,000 $ 34,000,000 Banc One Capital Markets, Inc....... 34,000,000 34,000,000 Wachovia Capital Markets, LLC....... 12,000,000 12,000,000 BNY Capital Markets, Inc............ 5,000,000 5,000,000 Fifth Third Securities, Inc......... 5,000,000 5,000,000 NatCity Investments, Inc............ 5,000,000 5,000,000 U.S. Bancorp Piper Jaffray Inc...... 5,000,000 5,000,000 ----------- ----------- Total $100,000,000 $100,000,000 The Underwritten Securities shall have the following terms: Title: 5.25% Senior Notes due 2013 5.75% Senior Notes due 2018 Rank: Unsecured senior indebtedness Guarantees: Guaranteed by Indiana Gas Company, Inc., Southern Indiana Gas and Electric Company and Vectren Energy Delivery of Ohio, Inc. Ratings: "Baa1" by Moody's Investors Service, Inc. "A-" by Standard & Poor's Ratings Services Aggregate principal amount: 5.25% Senior Notes: $100,000,000 5.75% Senior Notes: $100,000,000 Denominations: $1,000 and integral multiples thereof Currency of payment: United States dollars Interest rate or formula: 5.25% Senior Notes: 5.25% per annum 5.75% Senior Notes: 5.75% per annum Interest payment dates: February 1 and August 1 of each year, commencing February 1, 2004 Regular record dates: The 15th calendar day of the month immediately preceding the month in which each Interest Payment Date falls Stated maturity date: 5.25% Senior Notes: August 1, 2013 5.75% Senior Notes: August 1, 2018 Redemption provisions: The Notes are redeemable at any time at the option of the Company in whole or in part, upon not less than 30 calendar days and not more than 60 calendar days prior written notice at a price equal to the greater of 100% of the principal amount to be redeemed, and the sum of the present values of the remaining scheduled payments of principal and interest on the Notes, discounted to the redemption date on a semi-annual basis at the Treasury Rate plus 20 basis points, in the case of the 5.25% Senior Notes, and 25 basis points, in the case of the 5.75% Senior Notes, plus in each case unpaid interest accrued to the redemption date. Sinking fund requirements: The Notes will not have the benefit of, or be subject to, any sinking fund. Defeasance provisions: The Notes are subject to defeasance and covenant defeasance as provided in Article 8 of the Indenture. Fixed or Variable Price Offering: 5.25% Senior Notes: 99.746% of the principal amount, plus accrued interest, if any, from July 29, 2003. 5.75% Senior Notes: 99.177% of the principal amount, plus accrued interest, if any, from July 29, 2003. Purchase price: 5.25% Senior Notes: 99.096% of the principal amount. 5.75% Senior Notes: 98.477% of the principal amount. Over-allotment option: None Form: Book-entry Listing: None Lock-Up Agreements: During the period of 90 days from July 29, 2003 the Company will not sell, offer to sell, grant any option for the sale of, or otherwise dispose of any additional Notes, any security convertible into or exchangeable into or exercisable for Notes or any debt securities substantially similar to the Notes or any security convertible into, exchangeable into or exercisable for any such debt securities, withou the prior written consent of the Underwriters. Other terms and conditions: None Closing date and location: July 29, 2003 at Sidley Austin Brown & Wood, LLP, 787 Seventh Avenue, New York, New York 10019. All of the provisions contained in the document attached as Annex I hereto entitled "Vectren Utility Holdings, Inc.--Debt Securities--Underwriting Agreement" are hereby incorporated by reference in their entirety herein and shall be deemed to be a part of this Terms Agreement to the same extent as if such provisions had been set forth in full herein. Terms defined in such document are used herein as therein defined. EX-31.1 CERTIFICATIO 4 sig10k_ex31-1.txt SARBANES-OXLEY CERTIFICATION Exhibit 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 Southern Indiana Gas and Electric Company; 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 25, 2004 /s/ Niel C. Ellerbrook ------------------------------------- Niel C. Ellerbrook Chairman & Chief Executive Officer EX-31.2 CERTIFICATIO 5 sig10k_ex31-2.txt SARBANES-OXLEY 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 Southern Indiana Gas and Electric Company; 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 25, 2004 /s/ Jerome A. Benkert, Jr. --------------------------------- Jerome A. Benkert, Jr. Executive Vice President & Chief Financial Officer EX-32.1 CERTIFICATIO 6 sig10k_ex32-1.txt SARBANES-OXLEY 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 Southern Indiana Gas and Electric Company. Signed this 25th day of February, 2004. /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-----