10-Q 1 sig10q_june03.txt 2ND QTR 10Q REPORT FOR SIGECO UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) |X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 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. 4th Street, Evansville, Indiana, 47708 ------------------------------------------------------- (Address of principal executive offices) (Zip Code) 812-491-4000 ------------------------------------------------------- (Registrant's telephone number, including area code) 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 whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes __ No |X| Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock - Without Par Value 20,785,007 August 1, 2003 -------------------------------- ---------- -------------- 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 (H)(1)(a) and (b) of Form 10-Q and is therefore filing with the reduced disclosure format contemplated thereby. Table of Contents Item Page Number Number PART I. FINANCIAL INFORMATION 1 Financial Statements (Unaudited) Southern Indiana Gas and Electric Company Condensed Balance Sheets 1-2 Condensed Statements of Income 3 Condensed Statements of Cash Flows 4 Notes to Unaudited Condensed Financial Statements 5-13 2 Management's Discussion and Analysis of Results of Operations and Financial Condition (A) 14-18 3 Quantitative and Qualitative Disclosures About Market Risk (A) 19 4 Controls and Procedures 19 PART II. OTHER INFORMATION 1 Legal Proceedings 20 6 Exhibits and Reports on Form 8-K 20 Signatures 21 (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 (H)(1)(a) and (b) of Form 10-Q 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 Definitions AFUDC: allowance for funds used during MMBTU: millions of British thermal construction units APB: Accounting Principles Board MW: megawatts EITF: Emerging Issues Task Force MWh / GWh: megawatt hours/millions of megawatt hours (gigawatt hours) FASB: Financial Accounting Standards NOx: nitrogen oxide Board FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility Commission Consumer Counselor IDEM: Indiana Department of SFAS: Statement of Financial Environmental Management Accounting Standards IURC: Indiana Utility Regulatory USEPA: United States Environmental Commission Protection Agency MCF / BCF: millions / billions of Throughput: combined gas sales and cubic feet gas transportation volumes MDth / MMDth: thousands / millions of dekatherms PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEETS (Unaudited - In thousands) June 30, December 31, 2003 2002 ------------------------------------------------- ----------- ------------ ASSETS Utility Plant Original cost $ 1,584,023 $ 1,526,094 Less: Accumulated depreciation & amortization 750,179 728,768 -------------------------------------------------------------------------------- Net utility plant 833,844 797,326 -------------------------------------------------------------------------------- Current Assets Cash & cash equivalents - 2,145 Accounts receivable-less reserves of $1,421 & $3,662, respectively 33,641 50,454 Receivables from other Vectren companies 140 18,015 Accrued unbilled revenues 18,124 33,027 Inventories 34,068 39,653 Recoverable fuel & natural gas costs 6,075 9,615 Prepayments & other current assets 8,253 5,926 -------------------------------------------------------------------------------- Total current assets 100,301 158,835 -------------------------------------------------------------------------------- Investments in Unconsolidated Affiliates 150 150 Other Investments 9,833 10,019 Non-Utility Property-Net 3,501 3,568 Goodwill-nNet 5,557 5,557 Regulatory Assets 53,162 49,859 Other Assets 490 344 -------------------------------------------------------------------------------- TOTAL ASSETS $ 1,006,838 $ 1,025,658 ================================================================================ The accompanying notes are an integral part of these condensed financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEETS (Unaudited - In thousands) June 30, December 31, 2003 2002 ------------------------------------------------- ---------- ------------ LIABILITIES & SHAREHOLDER'S EQUITY Capitalization Common shareholder's equity Common stock (no par value) $ 103,258 $ 103,258 Retained earnings 267,771 270,181 -------------------------------------------------------------------------------- Total common shareholder's equity 371,029 373,439 -------------------------------------------------------------------------------- Cumulative redeemable preferred stock 228 344 Long-term debt-net of current maturities & debt subject to tender 290,958 264,238 Long-term debt due to VUHI 86,574 86,574 -------------------------------------------------------------------------------- Total capitalization 748,789 724,595 -------------------------------------------------------------------------------- Commitments & Contingencies (Notes 4, 6, & 7) Current Liabilities Accounts payable 14,147 25,215 Accounts payable to affiliated companies 3,373 10,013 Payables to other Vectren companies 3,501 14,677 Accrued liabilities 33,228 31,247 Short-term borrowings 984 - Short-term borrowings due to VUHI 47,582 39,419 Long-term debt subject to tender - 26,640 Current maturities of long-term debt - 1,000 -------------------------------------------------------------------------------- Total current liabilities 102,815 148,211 -------------------------------------------------------------------------------- Deferred Income Taxes & Other Liabilities Deferred income taxes 114,510 112,004 Deferred credits & other liabilities 40,724 40,848 -------------------------------------------------------------------------------- Total deferred income taxes & other liabilities 155,234 152,852 -------------------------------------------------------------------------------- TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $1,006,838 $1,025,658 ================================================================================ The accompanying notes are an integral part of these condensed financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited - In thousands)

The accompanying notes are an integral part of these condensed financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited - In thousands) Six Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------ ------------------------- As Restated, See Note 3 ----------------------------------------------------------------------------- NET CASH FLOWS FROM OPERATING ACTIVITIES $ 70,023 $ 59,142 ----------------------------------------------------------------------------- CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES Requirements for: Dividends on common stock (21,854) (21,910) Retirement of long-term debt (1,000) - Redemption of preferred stock (116) (116) Dividends on preferred stock (14) (10) Net change in short-term borrowings, including due to VUHI 9,147 2,463 ----------------------------------------------------------------------------- Net cash flows (required for) financing activities (13,837) (19,573) ----------------------------------------------------------------------------- CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES Proceeds from sale of assets - 1,400 Capital expenditures (58,331) (42,437) ----------------------------------------------------------------------------- Net cash flows (required for) investing activities (58,331) (41,037) ----------------------------------------------------------------------------- Net decrease in cash & cash equivalents (2,145) (1,468) Cash & cash equivalents at beginning of period 2,145 1,556 ----------------------------------------------------------------------------- Cash & cash equivalents at end of period $ - $ 88 ============================================================================= The accompanying notes are an integral part of these condensed financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) 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. The Company 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). 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." 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, 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. 2. Basis of Presentation The interim condensed financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations. The Company believes that the information in this report reflects all adjustments necessary to fairly state the results of the interim periods reported. These condensed financial statements and related notes should be read in conjunction with the Company's audited annual financial statements for the year ended December 31, 2002, filed on Form 10-K/A. Because of the seasonal nature of the Company's utility operations, the results shown on a quarterly basis are not necessarily indicative of annual results. 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 statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. 3. Restatement of Previously Reported Information Subsequent to the issuance of the Company's 2002 quarterly financial statements, the Company's management determined that previously issued financial statements should be restated. The restatement had the effect of decreasing net income for the three and six months ended June 30, 2002 by $2.9 million after tax and $2.6 million after tax, respectively. In the second quarter of 2002, the Company recorded $5.2 million ($3.2 million after tax) of carrying costs for demand side management (DSM) programs pursuant to existing IURC orders and based on an improved regulatory environment. During the 2002 annual audit, management determined that the accrual of such carrying costs was more appropriate in periods prior to 2000 when DSM program expenditures were made. Therefore, such carrying costs originally reflected in 2002 quarterly results were reversed and reflected in common shareholders' equity as of January 1, 2000. The Company also identified other adjustments for various reconciliation errors and other errors related primarily to the recording of estimates. These adjustments were not significant, either individually or in the aggregate and increased previously reported pre-tax and after tax earnings for the three months ended June 30, 2002 by approximately $0.4 million and $0.3 million, respectively, and increased previously reported pre-tax and after tax earnings for the six months ended June 30, 2002 by approximately $0.9 million and $0.6 million, respectively. Following is a summary of the effects of the restatement on previously reported results of operations for the three months ended June 30, 2002.

Following is a summary of the effects of the restatement on previously reported results of operations for the six months ended June 30, 2002. In thousands -------------------------------------------------------------------------------- As Reported Adjustments As Restated ----------- ----------- ----------- OPERATING REVENUES Electric revenues $ 285,724 $ - $ 285,724 Gas revenues 47,231 - 47,231 -------------------------------------------------------------------------------- Total operating revenues 332,955 - 332,955 -------------------------------------------------------------------------------- COST OF OPERATING REVENUES Fuel for electric generation 36,859 - 36,859 Purchased electric energy 146,836 (291) 146,545 Cost of gas sold 28,938 116 29,054 -------------------------------------------------------------------------------- Total cost of operating revenues 212,633 (175) 212,458 -------------------------------------------------------------------------------- TOTAL OPERATING MARGIN 120,322 175 120,497 OPERATING EXPENSES Other operating 51,797 (339) 51,458 Depreciation & amortization 22,041 - 22,041 Income taxes 13,333 (1,618) 11,715 Taxes other than income taxes 6,318 - 6,318 -------------------------------------------------------------------------------- Total operating expenses 93,489 (1,957) 91,532 -------------------------------------------------------------------------------- OPERATING INCOME 26,833 2,132 28,965 Other income - net 8,183 (4,779) 3,404 Interest expense 11,485 - 11,485 -------------------------------------------------------------------------------- NET INCOME 23,531 (2,647) 20,884 Preferred stock dividends 10 - 10 -------------------------------------------------------------------------------- NET INCOME APPLICABLE TO COMMON SHAREHOLDER $ 23,521 $ (2,647) $ 20,874 ================================================================================ 4. 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 $10.4 million and $11.7 million, respectively, for the three months ended June 30, 2003 and 2002,and $21.6 million and $24.3 million, respectively, for the six months ended June 30, 2003 and 2002. 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 three months ended June 30, 2003 and 2002, totaled $19.1 million and $15.0 million, respectively, and $38.3 million and $28.2, respectively, for the six months ended June 30, 2003 and 2002. Guarantees of Parent Company Debt Vectren's three operating utility companies, VEDO, Indiana Gas, and SIGECO are guarantors of VUHI's $366.0 million in short-term credit facilities, of which approximately $318.6 million is outstanding at June 30, 2003 and VUHI's $350.0 million unsecured senior notes outstanding at June 30, 2003. The guarantees are full and unconditional and joint and several, and VUHI has no subsidiaries other than the subsidiary guarantors. Stock-Based Incentive Plans SIGECO does not have stock-based compensation plans separate from Vectren. An insignificant number of SIGECO's employees participate in Vectren's stock-based compensation plans. 5. Transactions with ProLiance Energy, LLC ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to Indiana Gas, the Ohio operations, Citizens Gas and others. ProLiance also began providing service to SIGECO and Vectren Retail, LLC (Vectren's retail gas marketer) in 2002. ProLiance's primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2003 and 2002 totaled $8.8 million and zero, respectively, and for the six months ended June 30, 2003 and 2002 totaled $38.6 million and zero, respectively. Amounts owed to ProLiance at June 30, 2003 and December 31, 2002 for those purchases were $3.4 million and $10.0 million, respectively, and are included in accounts payable to affiliated companies. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility. 6. Commitments & Contingencies 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 7 regarding environmental matters. United States Securities and Exchange Commission (SEC) Informal Inquiry As more fully described in Note 3 to these condensed financial statements and in Note 3 to the 2002 financial statements filed on Form 10-K/A, the Company restated its financial statements for 2000, 2001, and quarterly results issued in 2002. The Company is cooperating with the SEC in an informal inquiry with respect to this previously announced restatement, has met with the staff of the SEC, and is providing information in response to their requests. 7. Environmental Matters Clean Air Act NOx SIP Call Matter The Clean Air Act (the Act) requires each state to adopt a State Implementation Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS) for a number of pollutants, including ozone. If the USEPA finds a state's SIP inadequate to achieve the NAAQS, the USEPA can call upon the state to revise its SIP (a SIP Call). In October 1998, the USEPA issued a final rule "Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone," (63 Fed. Reg. 57355). This ruling found that the SIP's of certain states, including Indiana, were substantially inadequate since they allowed for nitrogen oxide (NOx) emissions in amounts that contributed to non-attainment with the ozone NAAQS in downwind states. The USEPA required each state to revise its SIP to provide for further NOx emission reductions. The NOx emissions budget, as stipulated in the USEPA's final ruling, requires a 31% reduction in total NOx emissions from Indiana. In June 2001, the Indiana Air Pollution Control Board adopted final rules to achieve the NOx emission reductions required by the NOx SIP Call. Indiana's SIP requires the Company to lower its system-wide NOx emissions to .14 lbs./MMBTU by May 31, 2004 (the compliance date). This is a 65% reduction from emission levels existing in 1999 and 1998. The Company has initiated steps toward compliance with the revised regulations. These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to be the most effective method of reducing NOx emissions where high removal efficiencies are required. The IURC has issued orders that approve: o the Company's proposed project to achieve environmental compliance by investing in clean coal technology; o a total capital cost investment for this project up to $244 million (excluding AFUDC), subject to periodic review of the actual costs incurred; o a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months an 8 percent return on its 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 in 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 June 30, 2003, $102.8 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. Such expenses are expected to commence later in 2003 when the Culley SCR is 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 completed on schedule, 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 a proposed 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. SIGECO anticipates that the Court will enter the consent decree. Under the terms of the proposed 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 proposed agreement, SIGECO did not admit to any allegations alleged 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 proposed agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation. Under the proposed 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 oxides, or cease operation of the unit by December of 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 of 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 proposed 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 proposed 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, and no further action has occurred. 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 Voluntary Remediation Program. In response SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990's. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have recently been initiated by the Company to confirm that the sites continue to pose no such risk. 8. 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. In accordance with regulatory treatment, the Company collects an estimated net cost of removal of its utility plant in rates through normal depreciation. As of June 30, 2003 and December 31, 2002 such removal costs approximated $125 million of accumulated depreciation as presented in the condensed balance sheets based upon the Company's latest depreciation studies. 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. Although management is still evaluating the impact of SFAS 149 on its financial position and results of operations, the adoption is not expected to have a material effect. 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 is effective immediately for all financial instruments entered into or modified after May 31, 2003. For all other instruments, SFAS 150 applies to the Company's third quarter of 2003. The Company has approximately $200,000 of outstanding preferred stock that is redeemable on terms outside the Company's control. However, the preferred stock is not redeemable on a specified or determinable date or upon an event that is certain to occur. Therefore, SFAS 150's adoption will not affect the Company's results of operations or financial condition. FASB Interpretation (FIN) 45 In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a guarantor's accounting for and disclosure of certain guarantees issued and outstanding and that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligations it has undertaken. The initial recognition and measurement provisions are 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 In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 addresses consolidation by business enterprises of variable interest entities and significantly changes the consolidation requirements for those entities. FIN 46 is intended to achieve more consistent application of consolidation policies to variable interest entities and, thus improves comparability between enterprises engaged in similar activities when those activities are conducted through variable interest entities. FIN 46 applies to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date. FIN 46 applies to the Company's third quarter of 2003 for variable interest entities in which the Company holds a variable interest acquired before February 1, 2003. Although management is still evaluating the impact of FIN 46 on its financial position and results of operations, the adoption is not expected to have a material effect. 9. Segment Reporting The Company has two operating segments: (1) Gas Utility Services and (2) Electric Utility Services. The Gas Utility Services segment includes the operations of the Company's natural gas distribution business and provides natural gas distribution and transportation services in southwest Indiana. The Electric Utility Services segment includes the operations of the Company's power generating and marketing operations, and electric transmission and distribution services, which provides electricity to primarily southwestern Indiana. Following is detailed information about the Company's operating segments. The Company uses pre-tax operating income as the measure of profitability for its segments. Following is information regarding the Company's segments' operating data.

Following is information regarding the Company's segments' total assets. June 30, December 31, In thousands 2003 2002 ---------------------------------------------------------------- Total Assets Electric Utility Services $ 871,698 $ 856,516 Gas Utility Services 135,140 169,142 ---------------------------------------------------------------- Total Assets $1,006,838 $1,025,658 ================================================================ 10. Subsequent Event In August 2003, the Company initiated steps to call two first mortgage bonds. The first bond has a principal amount of $45.0 million, an interest rate of 7.60%, was originally due in 2023, and may be redeemed at 103.745% of its stated principal amount. The second SIGECO bond has a principal amount of $20.0 million, an interest rate of 7.625%, was originally due in 2025, and may be redeemed at 103.763% of the stated principal amount. These transactions are expected to take place in September 2003. Pursuant to regulatory authority, the premium paid to retire the net carrying value of these notes will be deferred as a regulatory asset. The proceeds to fund the early redemption will be received from VUHI in the form of new long-term debt and additional equity. SIGECO also intends to repay a portion of its intercompany short-term borrowings due to VUHI with the equity contribution and long-term debt proceeds. To generate the initial proceeds to fund these transactions, in August 2003, VUHI completed a public offering of long-term debt netting proceeds of approximately $203 million, and Vectren completed a public offering of common stock netting proceeds of approximately $143 million. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Pursuant to General Instructions H(2)(a) of Form 10-Q, 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. Results of Operations The following discussion and analysis should be read in conjunction with the unaudited financial statements and notes thereto. Subsequent to the issuance of the Company's 2002 quarterly financial statements, the Company's management determined that previously issued financial statements should be restated. The restatement had the effect of decreasing net income for the three and six months ended June 30, 2002 by $2.9 million after tax and $2.6 million after tax, respectively. Note 3 to the condensed financial statements includes a summary of the effects of the restatement. The Company's results of operations give effect to the restatement. Net Income Applicable to Common Shareholder For the three months ended June 30, 2003, net income applicable to common shareholder was $6.1 million compared to $9.4 million, for the same period last year. For the six months ended June 30, 2003, net income applicable to common shareholder was $19.4 million compared to $20.9 million for the same period in 2002. The 2003 second quarter results declined $3.3 million compared to the same period in 2002. An estimated $2.5 million of the decrease is due to milder weather affecting both heating and cooling sales. Heating weather experienced in the second quarter 2003 was 9% warmer than the same period last year and cooling sales were reduced by weather 51% milder than the same period in 2002. Year to date 2003 earnings declined $1.5 million compared to the same period in 2002. The decrease was primarily driven by weather that on the year was unfavorably impacted by an estimated $1.3 million after tax and increased operating expenses compared to last year, offset by increased wholesale and other margins. Margin Electric Utility Margin Electric utility margin by customer type and non-firm wholesale margin separated between realized margin and mark-to-market gains and losses follows: Three Months Six Months Ended June 30, Ended June 30, ------------------ ------------------- In millions 2003 2002 2003 2002 ----------------------------- ------------------ ------------------- Retail & firm wholesale $ 46.9 $ 51.0 $ 96.9 $ 99.2 Non-firm wholesale 3.9 2.0 12.1 3.1 ----------------------------------------------------------------------------- Total electric margin $ 50.8 $ 53.0 $109.0 $102.3 ============================================================================= Non-firm wholesale margin: Realized margin $ 4.0 $ 2.0 $ 11.3 $ 6.0 Mark-to-market gains (losses) (0.1) - 0.8 (2.9) Electric margins were $50.8 million, a decrease of $2.2 million compared to the second quarter of 2002. The decrease in electric margin was due primarily to the effect of milder cooling weather which was 43% cooler than normal and 51% cooler than last year, offset by increased margins from wholesale power activities. The estimated quarter over quarter decrease as a result of the milder weather on electric utility margins was approximately $3.9 million. As a result of the mild weather, volumes sold to retail and firm wholesale customers decreased 7% from 1.49 GWh in 2002 to 1.39 GWh in 2003. Non-firm wholesale electric utility margins increased $1.9 million to $3.9 million in 2003 compared to 2002. Electric margins were $109.0 million, an increase of $6.7 million over the first six months of 2002 primarily due to increased non-firm wholesale power activity resulting from price volatility, offset by lower retail sales due to milder cooling weather. As a result of the mild weather which was 44% cooler than normal and 51% cooler than last year, volumes sold to retail and firm wholesale customers decreased 3% from 2.89 GWh in 2002 to 2.81 GWh in 2003 with an estimated margin decrease of $2.9 million. Non-firm wholesale margins were $12.1 million, an increase of $9.0 million over 2002. Periodically, generation capacity is in excess of that needed to serve retail and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. The contracts entered into are primarily short-term purchase and sale transactions that expose the Company to limited market risk. For the three months ended June 30, 2003, volumes sold into the wholesale market were 0.58 GWh compared to 3.17 GWh in 2002 while volumes purchased from the wholesale market were 1.23 GWh in 2003 compared to 3.16 GWh in 2002. For the six months ended June 30, 2003 volumes sold into the wholesale market were 2.02 GWh compared to 5.63 GWh in 2002 while volumes purchased from the wholesale market were 2.48 GWh in 2003 compared to 5.49 GWh in 2002. A portion of volumes purchased in the wholesale market is used to serve retail and firm wholesale customers. In 2003, greater amounts of purchased power have been required for native load due to scheduled outages and installation of NOx equipment. While volumes both sold and purchased in the wholesale market have decreased during 2003, which has resulted in decreased electric revenues and purchased power, margins increased as noted above primarily from price volatility. Gas Utility Margin Gas utility margins were $5.8 million, a decrease of $0.4 million over the same quarter in 2002. The decrease is primarily due to heating weather which was normal and 9% warmer than the prior year period. The estimated quarter over quarter impact of the warmer weather on gas utility margins was a decrease of approximately $0.3 million. Weather and an overall decline in customer usage were the primary factors resulting in the 6% decrease in throughput. Gas utility margins were $15.9 million, a decrease of $2.3 million over the first six months of 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 $3.0 million. Management estimates that weather 16% colder than the prior year and 7% colder than normal increased margin by approximately $0.7 million period over period. The colder weather is the primary reason for the 8% increase in throughput. Higher gas costs and a slowly recovering economy have impacted customer usage. The total average cost per dekatherm of gas purchased for the three and six months ended June 30, 2003, was $5.32 and $5.90, respectively, compared to $4.00 and $4.26, respectively, for the same periods in 2002. Operating Expenses Other Operating For the six months ended June 30, 2003, other operating expenses increased $1.3 million, compared to the prior year. The increased expenses were principally due to the timing of electric plant maintenance expenditures. Depreciation & Amortization For the three and six months ended June 30, 2003, depreciation and amortization increased $0.6 million and $1.2 million, respectively, due to additions to utility plant. Since June 30, 2002, the Company has placed into service a new gas-fired peaker unit and other upgrades to existing transmission and distribution facilities. Income Tax For the three months ended June 30, 2003, federal and state income taxes decreased $2.4 million and for the six months ended June 30, 2003 increased $0.7 million when compared to 2002. The changes are primarily due to fluctuations in pre-tax income. Year to date, the effective tax rate increased from 35.9% in 2002 to 38.9% in 2003 principally due to an increase in the Indiana state income tax rate from 4.5 % to 8.5% that was effective January 1, 2003. Other - Net For the three and six months ended June 30, 2003, other income (expense) -net decreased $2.4 million and $2.2 million, respectively, compared to the prior year. The decreases are primarily the result of the current year penalty associated with the Culley settlement of $0.6 million and sales emission allowances in the second quarter of 2002 totaling $0.6 million. In addition both the quarter and year to date 2003 periods have experienced less AFUDC. Interest Expense For the three and six months ended June 30, 2003, interest expense increased $0.5 million and $0.9 million, respectively, when compared to the same periods last year. The increase results from increased debt outstanding which is due primarily to increased working capital requirements resulting from the higher gas prices and NOx expenditures. 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. 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. Although management is still evaluating the impact of SFAS 149 on its financial position and results of operations, the adoption is not expected to have a material effect. 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 is effective immediately for all financial instruments entered into or modified after May 31, 2003. For all other instruments, SFAS 150 applies to the Company's third quarter of 2003. The Company has approximately $200,000 of outstanding preferred stock that is redeemable on terms outside the Company's control. However, the preferred stock is not redeemable on a specified or determinable date or upon an event that is certain to occur. Therefore, SFAS 150's adoption will not effect the Company's results of operations or financial condition. FASB Interpretation (FIN) 45 In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 clarifies the requirements for a guarantor's accounting for and disclosure of certain guarantees issued and outstanding and that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligations it has undertaken. The initial recognition and measurement provisions are 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 In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 addresses consolidation by business enterprises of variable interest entities and significantly changes the consolidation requirements for those entities. FIN 46 is intended to achieve more consistent application of consolidation policies to variable interest entities and, thus improves comparability between enterprises engaged in similar activities when those activities are conducted through variable interest entities. FIN 46 applies to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date. FIN 46 applies to the Company's third quarter of 2003 for variable interest entities in which the Company holds a variable interest acquired before February 1, 2003. Although management is still evaluating the impact of FIN 46 on its financial position and results of operations, the adoption is not expected to have a material effect. 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 credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries. o Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages. o Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures. o Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters, including, but not limited to, those described in Management's Discussion and Analysis of Results of Operations and Financial Condition. o Changes in federal, state or local legislature requirements, such as changes in tax laws or rates, environmental laws and regulations. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions, or other factors affecting such statements. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Pursuant to General Instructions H(2)(c) of Form 10-Q, the following is intentionally omitted. ITEM 4. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures As of June 30, 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 provide 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 June 30, 2003, there have been no significant changes to the Company's internal control over financial reporting that has materially affected, or is 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 II. OTHER INFORMATION ITEM 1. 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 7 of its unaudited condensed financial statements included in Part 1 Item 1 Financial Statements regarding the Clean Air Act and related legal proceedings. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K Certifications 31.1 Certification Pursuant To Section 302 Of The Sarbanes-Oxley Act Of 2002- Chief Executive Officer 31.2 Certification Pursuant To Section 302 Of The Sarbanes-Oxley Act Of 2002- Chief Financial Officer 32 Certification Pursuant To Section 906 Of The Sarbanes-Oxley Act Of 2002 Other Exhibits None (b) Reports On Form 8-K During The Last Calendar Quarter On April 25, 2003, SIGECO filed a Current Report on Form 8-K with respect to the release of Vectren Corporation's financial information to the investment community regarding its results of operations, for the three and twelve month periods ended March 31, 2003. The financial information was released to the public through this filing. Item 12. Results of Operations and Financial Condition Item 7. Exhibits 99.1 - Press Release - Vectren Corporation Reports 1st Quarter 2003 Increase 99.2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 On June 9, 2003, SIGECO filed a Current Report on Form 8-K with respect a proposed agreement with the U.S. Department of Justice, and the U.S. Environmental Protection Agency that would lead to further improvements in air quality and resolve the government's pending Clean Air Act claims against SIGECO. Item 9. Regulation FD Disclosure Item 7. Exhibits 99.1 - Press Release - Vectren subsidiary reaches agreement with Department of Justice, EPA 99.2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 On June 30, 2003, SIGECO filed a Current Report on Form 8-K to announce 1) on June 26, 2003, VUHI's revolving credit facility was renewed and 2) on June 27, 2003, a registration statement filed by Vectren and VUHI, originally filed on March 31, 2003, was declared effective. Item 9. Regulation FD Disclosure Item 7. Exhibits 99.1 - Press Release - Vectren Renews Credit Facility and Announces Effectiveness of Registration Statement 99.2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 SIGNATURES Pursuant to the requirements 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 -------------------------------------------- Registrant August 14, 2003 /s/Jerome A. Benkert, Jr. ---------------------------- Jerome A. Benkert, Jr. Executive Vice President & Chief Financial Officer (Principal Financial Officer) /s/M. Susan Hardwick --------------------------- M. Susan Hardwick Vice President & Controller (Principal Accounting Officer)

SOUTHERN INDIANA GAS & ELECTRIC CO 10-Q