10-Q 1 vvc10q_june03.txt VECTREN CORP 10Q FOR 2ND QTR 2003 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: 1-15467 VECTREN CORPORATION -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) INDIANA 35-2086905 -------------------------------- ------------------- (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 |X| No __ 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 68,119,966 August 1, 2003 -------------------------------- ----------- -------------- Class Number of Shares Date Table of Contents Item Page Number Number PART I. FINANCIAL INFORMATION 1 Financial Statements (Unaudited) Vectren Corporation and Subsidiary Companies Consolidated Condensed Balance Sheets 1-2 Consolidated Condensed Statements of Income 3 Consolidated Condensed Statements of Cash Flows 4 Notes to Unaudited Consolidated Condensed Financial Statements 5-19 2 Management's Discussion and Analysis of Results of Operations and Financial Condition 20-42 3 Quantitative and Qualitative Disclosures About Market Risk 42 4 Controls and Procedures 43 PART II. OTHER INFORMATION 1 Legal Proceedings 43 4 Submission of Matters to a Vote of Security Holders 44 6 Exhibits and Reports on Form 8-K 45 Signatures 46 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 PUCO: Public Utilities Commission of Environmental Management Ohio IURC: Indiana Utility Regulatory SFAS: Statement of Financial Commission Accounting Standards MCF / BCF: millions / billions of USEPA: United States Environmental cubic feet Protection Agency MDth / MMDth: thousands / millions of Throughput: combined gas sales and dekatherms gas transportation volumes PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited - In millions) June 30, December 31, 2003 2002 ----------------------------------------------- --------- ------------ ASSETS Current Assets Cash & cash equivalents $ 16.4 $ 25.1 Accounts receivable-less reserves of $3.4 & $5.5, respectively 110.5 154.4 Accrued unbilled revenues 40.6 116.1 Inventories 47.0 62.8 Recoverable fuel & natural gas costs 15.4 22.1 Prepayments & other current assets 84.9 93.0 ----------------------------------------------------------------------------- Total current assets 314.8 473.5 ----------------------------------------------------------------------------- Utility Plant Original cost 3,132.8 3,037.1 Less: accumulated depreciation & amortization 1,434.6 1,389.0 ----------------------------------------------------------------------------- Net utility plant 1,698.2 1,648.1 ----------------------------------------------------------------------------- Investments in Unconsolidated Affiliates 164.8 153.3 Other Investments 112.7 124.3 Non-Utility Property-Net 219.3 228.0 Goodwill-Net 202.2 202.2 Regulatory Assets 85.4 75.2 Other Assets 22.8 21.9 ----------------------------------------------------------------------------- TOTAL ASSETS $ 2,820.2 $ 2,926.5 ============================================================================= The accompanying notes are an integral part of these consolidated condensed financial statements. VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited - In millions)
June 30, December 31, 2003 2002 ------------------------------------------------------- --------- ------------ LIABILITIES & SHAREHOLDERS' EQUITY Current Liabilities Accounts payable $ 45.7 $ 101.7 Accounts payable to affiliated companies 61.4 86.4 Accrued liabilities 101.7 119.9 Short-term borrowings 390.6 399.5 Current maturities of long-term debt - 39.8 Long-term debt subject to tender - 26.6 ------------------------------------------------------------------------------------- Total current liabilities 599.4 773.9 ------------------------------------------------------------------------------------- Long-term Debt-Net of Current Maturities & Debt Subject to Tender 980.9 954.2 Deferred Income Taxes & Other Liabilities Deferred income taxes 203.4 195.5 Deferred credits & other liabilities 137.0 130.8 ------------------------------------------------------------------------------------- Total deferred credits & other liabilities 340.4 326.3 ------------------------------------------------------------------------------------- Minority Interest in Subsidiary 0.3 1.9 Commitments & Contingencies (Notes 8, 9 & 10) Cumulative, Redeemable Preferred Stock of a Subsidiary 0.2 0.3 Common Shareholders' Equity Common stock (no par value) - issued & outstanding 68.1 and 67.9, respectively 354.5 350.0 Retained earnings 552.9 530.4 Accumulated other comprehensive income (8.4) (10.5) ------------------------------------------------------------------------------------- Total common shareholders' equity 899.0 869.9 ------------------------------------------------------------------------------------- TOTAL LIABILITIES & SHAREHOLDERS' EQUITY $ 2,820.2 $ 2,926.5 =====================================================================================
The accompanying notes are an integral part of these consolidated condensed financial statements. VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited - In millions, except per share data)
Three Months Six Months Ended June 30, Ended June 30, ---------------- ----------------- 2003 2002 2003 2002 ---------------------------------------- ---------------- ----------------- As Restated, As Restated, See Note 3 See Note 3 ------------ ------------ OPERATING REVENUES Gas utility $ 165.1 $ 140.1 $ 674.6 $ 498.2 Electric utility 90.2 158.9 209.6 285.7 Energy services & other 28.1 81.1 61.7 226.6 -------------------------------------------------------------------------------- Total operating revenues 283.4 380.1 945.9 1,010.5 -------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 104.3 81.8 469.4 312.0 Fuel for electric generation 20.6 19.1 41.4 36.9 Purchased electric energy 18.8 86.8 59.2 146.5 Cost of energy services & other 19.1 72.0 44.6 206.8 Other operating 59.6 55.9 122.2 113.6 Depreciation & amortization 32.4 28.7 63.8 57.7 Taxes other than income taxes 11.1 10.2 33.1 28.5 -------------------------------------------------------------------------------- Total operating expenses 265.9 354.5 833.7 902.0 -------------------------------------------------------------------------------- OPERATING INCOME 17.5 25.6 112.2 108.5 OTHER INCOME (EXPENSE) Equity in earnings (losses) of unconsolidated affiliates (0.1) 3.7 8.7 6.8 Other - net (1.1) 3.1 (2.2) 5.3 -------------------------------------------------------------------------------- Total other income (expense) (1.2) 6.8 6.5 12.1 -------------------------------------------------------------------------------- Interest expense 18.2 19.5 37.1 39.3 -------------------------------------------------------------------------------- INCOME (LOSS) BEFORE INCOME TAXES (1.9) 12.9 81.6 81.3 -------------------------------------------------------------------------------- Income taxes (5.9) 0.4 21.8 23.4 Minority interest in & preferred dividend requirements of subsidiaries (0.1) - - (0.2) -------------------------------------------------------------------------------- NET INCOME $ 4.1 $ 12.5 $ 59.8 $ 58.1 ================================================================================ COMMON SHARES OUTSTANDING: BASIC 67.8 67.6 67.7 67.5 DILUTED 68.1 67.9 68.0 67.8 EARNINGS PER SHARE OF COMMON STOCK: BASIC $ 0.06 $ 0.18 $ 0.88 $ 0.86 DILUTED 0.06 0.18 0.88 0.86 DIVIDENDS DECLARED PER SHARE OF COMMON STOCK 0.28 0.27 0.55 0.53
The accompanying notes are an integral part of these consolidated condensed financial statements. VECTREN CORPORATION AND SUBSIDIARY COMPANIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited - In millions)
Six Months Ended June 30, ------------------------- 2003 2002 ------------------------------------------------------------------------------------------ As Restated, See Note 3 ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 59.8 $ 58.1 Adjustments to reconcile net income to cash from operating activities: Depreciation & amortization 63.8 57.7 Deferred income taxes & investment tax credits 4.3 (0.4) Equity in earnings of unconsolidated affiliates (8.7) (6.8) Net unrealized (gain) loss on derivative instruments (0.8) 2.9 Pension and postretirement expense 7.0 6.6 Other non-cash charges- net 7.6 1.8 Changes in working capital accounts: Accounts receivable & accrued unbilled revenue 112.2 98.4 Inventories 15.8 20.4 Recoverable fuel & natural gas costs 6.7 26.2 Prepayments & other current assets 0.3 34.4 Accounts payable, including to affiliated companies (81.0) (36.8) Accrued liabilities (15.5) (2.1) Changes in other noncurrent assets 0.6 (2.7) Changes in other noncurrent liabilities (1.6) (3.5) -------------------------------------------------------------------------------------------- Net cash flows from operating activities 170.5 254.2 -------------------------------------------------------------------------------------------- CASH FLOWS REQUIRED FOR FINANCING ACTIVITIES Proceeds from stock option exercises and other stock plans 3.6 1.4 Requirements for: Retirement of long-term debt, including premiums paid (40.9) (6.3) Dividends on common stock (37.3) (35.8) Redemption of preferred stock of subsidiary (0.1) (0.2) Net change in short-term borrowings (8.9) (116.3) -------------------------------------------------------------------------------------------- Net cash flows required for financing activities (83.6) (157.2) -------------------------------------------------------------------------------------------- CASH FLOWS REQUIRED FOR INVESTING ACTIVITIES Proceeds from: Notes receivable & other collections 9.4 3.7 Unconsolidated affiliate distributions 7.6 2.7 Requirements for: Capital expenditures, excluding AFUDC-equity (99.9) (93.3) Unconsolidated affiliate investments (8.6) (8.0) Notes receivable & other investments (4.1) (8.1) -------------------------------------------------------------------------------------------- Net cash flows required for investing activities (95.6) (103.0) -------------------------------------------------------------------------------------------- Net decrease in cash & cash equivalents (8.7) (6.0) Cash & cash equivalents at beginning of period 25.1 25.0 -------------------------------------------------------------------------------------------- Cash & cash equivalents at end of period $ 16.4 $ 19.0 ============================================================================================
The accompanying notes are an integral part of these consolidated condensed financial statements. VECTREN CORPORATION AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (UNAUDITED) 1. Organization and Nature of Operations Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company was organized on June 10, 1999 solely for the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with APB Opinion No. 16 "Business Combinations" (APB 16). The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI), serves as the intermediate holding company for its three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations. VUHI also has other assets that provide information technology and other services to the three utilities. Both Vectren and VUHI are exempt from registration pursuant to Section 3(a) (1) and 3(c) of the Public Utility Holding Company Act of 1935. Indiana Gas provides natural gas distribution and transportation services to a diversified customer base in 49 of Indiana's 92 counties. SIGECO provides electric generation, transmission, and distribution services to 8 counties in southwestern Indiana, including counties surrounding Evansville, and participates in the wholesale power market. SIGECO also provides natural gas distribution and transportation services to 10 counties in southwestern Indiana, including counties surrounding Evansville. The Ohio operations, owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc.(VEDO), a wholly owned subsidiary, (53 % ownership) and Indiana Gas (47 % ownership), provide natural gas distribution and transportation services to 17 counties in west central Ohio, including counties surrounding Dayton. The Company is also involved in nonregulated activities in four primary business areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure Services, and Broadband. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal to the Company's utility operations and to other parties and generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. Broadband invests in broadband communication services such as analog and digital cable television, high-speed Internet and data services, and advanced local and long distance phone services. In addition, the nonregulated group has other businesses that provide utility services, municipal broadband consulting, and retail products and services and that invest in energy-related opportunities, real estate, and leveraged leases. 2. Basis of Presentation The interim consolidated 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 consolidated condensed financial statements and related notes should be read in conjunction with the Company's audited annual consolidated 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 both the three and six months ended June 30, 2002 by $1.8 million after tax, or $0.03 on a basic earnings per share basis. 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 $2.3 million and $1.4 million, respectively, and increased previously reported pre-tax and after tax earnings for the six months ended June 30, 2002 by approximately $2.6 million and $1.4 million (including a $0.2 million tax adjustment), respectively. In addition, the Company reduced previously reported energy services and other revenues and cost of energy services and other by $7.1 million for the three months ended June 30, 2002 and $12.9 million for the six months ended June 30, 2002, reflecting the adoption of EITF Issue No. 99-19 "Reporting Revenue Gross as a Principal versus Net as an Agent." Following is a summary of the effects of the restatement on previously reported results of operations for the three months ended June 30, 2002.
In millions -------------------------------------------------------------------------------------- OPERATING REVENUES As reported Adjustments As Restated ----------- ----------- ----------- Gas utility $ 139.8 $ 0.3 $ 140.1 Electric utility 158.9 - 158.9 Energy services & other 88.2 (7.1) 81.1 -------------------------------------------------------------------------------------- Total operating revenues 386.9 (6.8) 380.1 -------------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 81.9 (0.1) 81.8 Fuel for electric generation 19.0 0.1 19.1 Purchased electric energy 87.0 (0.2) 86.8 Cost of energy services & other 79.1 (7.1) 72.0 Other operating 57.4 (1.5) 55.9 Depreciation & amortization 28.7 - 28.7 Taxes other than income taxes 10.2 - 10.2 -------------------------------------------------------------------------------------- Total operating expenses 363.3 (8.8) 354.5 -------------------------------------------------------------------------------------- OPERATING INCOME 23.6 2.0 25.6 OTHER INCOME Equity in earnings of unconsolidated affiliates 3.8 (0.1) 3.7 Other - net 7.7 (4.6) 3.1 -------------------------------------------------------------------------------------- Total other income 11.5 (4.7) 6.8 -------------------------------------------------------------------------------------- Interest expense 19.3 0.2 19.5 -------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 15.8 (2.9) 12.9 -------------------------------------------------------------------------------------- Income taxes 1.5 (1.1) 0.4 Minority interest in and preferred dividends requirement of subsidiaries - - - -------------------------------------------------------------------------------------- NET INCOME $ 14.3 $ (1.8) $ 12.5 ======================================================================================
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 millions ------------------------------------------------------------------------------------- OPERATING REVENUES As reported Adjustments As Restated ----------- ----------- ----------- Gas utility $ 496.9 $ 1.3 $ 498.2 Electric utility 285.7 - 285.7 Energy services & other 239.5 (12.9) 226.6 ------------------------------------------------------------------------------------- Total operating revenues 1,022.1 (11.6) 1,010.5 ------------------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas sold 311.9 0.1 312.0 Fuel for electric generation 36.8 0.1 36.9 Purchased electric energy 146.8 (0.3) 146.5 Cost of energy services & other 218.5 (11.7) 206.8 Other operating 114.0 (0.4) 113.6 Depreciation & amortization 57.8 (0.1) 57.7 Taxes other than income taxes 28.5 - 28.5 ------------------------------------------------------------------------------------- Total operating expenses 914.3 (12.3) 902.0 ------------------------------------------------------------------------------------- OPERATING INCOME 107.8 0.7 108.5 OTHER INCOME Equity in earnings of unconsolidated affiliates 6.1 0.7 6.8 Other - net 9.1 (3.8) 5.3 ------------------------------------------------------------------------------------- Total other income 15.2 (3.1) 12.1 ------------------------------------------------------------------------------------- Interest expense 39.1 0.2 39.3 ------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 83.9 (2.6) 81.3 ------------------------------------------------------------------------------------- Income taxes 24.2 (0.8) 23.4 Minority interest in and preferred dividends requirement of subsidiaries (0.2) - (0.2) ------------------------------------------------------------------------------------- NET INCOME $ 59.9 $ (1.8) $ 58.1 =====================================================================================
4. Stock-Based Compensation The Company applies APB Opinion 25, "Accounting for Stock Issued to Employees" (APB25) and related interpretations when measuring compensation expense for its stock-based compensation plans. Stock Option Plans The exercise price of stock options awarded under the Company's stock option plans is equal to the fair market value of the underlying common stock on the date of grant. Accordingly, no compensation expense has been recognized for stock option plans. In January 2003, 384,500 options to purchase shares of common stock at an exercise price of $23.19 were issued to management. The grant vests over three years. Other Plans In addition to its stock option plans, the Company also maintains restricted stock and phantom stock plans for executives and non-employee directors. In January 2003, 93,000 restricted shares with a fair value per share of $23.19 were issued to management. Those shares vest in 2006. Compensation expense recognized in the consolidated financial statements associated with these restricted stock and phantom stock plans for the three months ended June 30, 2003 and 2002 was $0.7 million ($0.4 million after tax) and $1.3 million ($0.8 million after tax), respectively, and for the six months ended June 30, 2003 and 2002 was $1.4 million ($0.9 million after tax) and $1.9 million ($1.2 million after tax), respectively. The amount of expense is consistent with the amount of expense that would have been recognized if the Company used the fair value based method described in SFAS No. 123 "Accounting for Stock Based Compensation" (SFAS 123), as amended, to value these awards. Pro forma Information Following is the effect on net income and earnings per share as if the fair value based method described in SFAS 123 had been applied to the Company's stock-based compensation plans: Three Months Six Months Ended June 30, Ended June 30, --------------- --------------- In millions, except per share amounts 2003 2002 2003 2002 -------------------------------------- --------------- --------------- Net Income: As reported $ 4.1 $ 12.5 $ 59.8 $ 58.1 Add: Stock-based employee compensation included in reported net income- net of tax 0.4 0.8 0.9 1.2 Deduc: Total stock-based employee compensation expense determined under fair value based method for all awards- net of tax 0.9 1.0 1.6 1.6 ------------------------------------------------------------------------------ Pro forma $ 3.6 $ 12.3 $ 59.1 $ 57.7 ============================================================================== Basic Earnings Per Share: As reported $ 0.06 $ 0.18 $ 0.88 $ 0.86 Pro forma 0.05 0.17 0.86 0.84 Diluted Earnings Per Share: As reported $ 0.06 $ 0.18 $ 0.88 $ 0.86 Pro forma 0.05 0.17 0.86 0.84 5. Earnings Per Share Basic earnings per share is computed by dividing net income available to common shareholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share assumes the conversion of stock options into common shares and the lifting of restrictions on issued restricted shares using the treasury stock method to the extent the effect would be dilutive. The following tables illustrates the basic and dilutive earnings per share calculations for the three and six months ended June 30, 2003 and 2002: Three Months Ended June 30, -------------------------------------------------------- 2003 2002 -------------------------- -------------------------- Per Per In millions, except Share Share per share amounts Income Shares Amount Income Shares Amount --------------------- ------ ------ ------ ------ ------ ------ Basic EPS $ 4.1 67.8 $ 0.06 $12.5 67.6 $ 0.18 Effect of dilutive stock equivalents 0.3 0.3 ------------------------------------------------------------------------------- Diluted EPS $ 4.1 68.1 $ 0.06 $12.5 67.9 $ 0.18 =============================================================================== For the three months ended June 30, 2003 and 2002, options to purchase an additional 87,963 and 4,200 common shares of the Company's common stock were outstanding, but were not included in the computation of diluted earnings per share because their effect would be antidilutive. Exercise prices for options excluded from the computation ranged from $24.05 to $25.59 in 2003 and equaled $25.59 in 2002. Six Months Ended June 30, -------------------------------------------------------- 2003 2002 -------------------------- -------------------------- Per Per In millions, except Share Share per share amounts Income Shares Amount Income Shares Amount -------------------- ------ ------ ------ ------ ------ ------ Basic EPS $59.8 67.7 $ 0.88 $58.1 67.5 $ 0.86 Effect of dilutive stock equivalents 0.3 0.3 ------------------------------------------------------------------------------- Diluted EPS $59.8 68.0 $ 0.88 $58.1 67.8 $ 0.86 =============================================================================== For the six months ended June 30, 2003 and 2002, options to purchase an additional 530,663 and 22,274 common shares of the Company's common stock were outstanding, but were not included in the computation of diluted earnings per share because their effect would be antidilutive. Exercise prices for options excluded from the computation ranged from $23.19 to $25.59 in 2003 and from $24.90 to $25.59 in 2002. 6. Comprehensive Income Comprehensive income consists of the following: Three Months Six Months Ended June 30, Ended June 30, --------------- ----------------- In millions 2003 2002 2003 2002 --------------------------- ------ ------ ------ ------- Net income $ 4.1 $ 12.5 $ 59.8 $ 58.1 Other comprehensive income (loss) of unconsolidated affiliates- net of tax (5.2) 2.1 2.2 (0.2) ------------------------------------------------------------------------- Total comprehensive income (loss) $ (1.1) $ 14.6 $ 62.0 $ 57.9 ========================================================================= Other comprehensive income arising from unconsolidated affiliates is the Company's portion of ProLiance Energy, LLC's and Reliant Services, LLC's accumulated comprehensive income related to the use of cash flow hedges, including commodity contracts and interest rate swaps, and the Company's portion of Haddington Energy Partners, LP's accumulated comprehensive income related to unrealized gains and losses of "available for sale securities." 7. 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 and Citizens Gas and also began providing services to SIGECO and Vectren Retail, LLC (the Company's retail gas marketer) in 2002. ProLiance's primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. ProLiance's primary customers are utilities and other large end use customers. Vectren's ownership percentage of ProLiance is 61%. Governance and voting rights remain at 50% for each member. Since governance of ProLiance remains equal between the members, Vectren continues to account for its investment in ProLiance using the equity method of accounting. Purchases from ProLiance for resale and for injections into storage for the three months ended June 30, 2003 and 2002 totaled $169.2 million and $108.5 million, respectively, and for the six months ended June 30, 2003 and 2002 totaled $434.9 million and $236.3 million, respectively. Amounts owed to ProLiance at June 30, 2003 and December 31, 2002 for those purchases were $59.2 million and $84.6 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. 8. 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 9 regarding environmental matters. United States Securities and Exchange Commission (SEC) Informal Inquiry As more fully described in Note 3 to these consolidated condensed financial statements and in Note 3 to the 2002 consolidated financial statements filed on Form 10-K/A, the Company restated its consolidated 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. IRS Section 29 Investment Tax Credit Recent Developments Vectren's Coal Mining operations are comprised of Vectren Fuels, Inc. (Fuels), which includes its coal mines and related operations and Vectren Synfuels, Inc. (Synfuels). Synfuels holds one limited partnership unit (an 8.3% interest) in Pace Carbon Synfuels Investors, LP (Pace Carbon), a Delaware limited partnership formed to develop, own, and operate four projects to produce and sell coal-based synthetic fuel utilizing Covol technology. Under Section 29 of the Internal Revenue Code, manufacturers such as Pace Carbon, receive a tax credit for every ton of synthetic fuel sold. To qualify for the credits, the synthetic fuel must meet three primary conditions: 1) there must be a significant chemical change in the coal feedstock, 2) the product must be sold to an unrelated person, and 3) the production facility must have been placed in service before July 1, 1998. In past rulings, the Internal Revenue Service (IRS) has concluded that the synthetic fuel produced at the Pace Carbon facilities should qualify for Section 29 tax credits. The IRS issued a private letter ruling with respect to the four projects on November 11, 1997, and subsequently issued an updated private letter ruling on September 23, 2002. As a partner in Pace Carbon, Vectren has reflected total tax credits under Section 29 in its consolidated results through June 30, 2003 of approximately $30 million. Vectren has been in a position to fully utilize the credits generated and continues to project full utilization. In addition, Fuels receives synfuel-related fees from synfuel producers unrelated to Pace Carbon for a portion of its coal production. On June 27, 2003, the IRS, in an industry-wide announcement, stated that it has reason to question the scientific validity of certain test procedures and results that have been presented to it by certain taxpayers with an interest in synfuel operations. Accordingly, the IRS has suspended the issuance of new private letter rulings. In addition, the IRS indicated that it may revoke existing private letter rulings that relied on the procedures and results under review if it determines that those test procedures and results do not demonstrate that a significant chemical change has occurred. During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year and later expanded the audit to include tax years 1999 and 2000. The IRS has requested numerous extensions to the statute of limitations for the years under audit. It is expected that the issue of the existence of chemical change will be formally raised in the Pace Carbon audit. At this time, Vectren cannot predict the outcome of the IRS' review of the industry-wide issues, when that review will be completed or the ultimate impact, if any, of the audit of Pace Carbon relative to Vectren's investments in Pace Carbon. Vectren believes that it is justified in its reliance on the private letter rulings for the Pace Carbon facilities, that the test results that Pace Carbon presented to the IRS in connection with its private letter rulings are scientifically valid, and that Pace Carbon has operated its facilities in compliance with its private letter rulings and Section 29 of the Internal Revenue Code. Guarantees and Product Warranties Vectren Corporation issues guarantees to third parties on behalf of its unconsolidated affiliates. Such guarantees allow those affiliates to execute transactions on more favorable terms than the affiliate could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and performance guarantees. As of June 30, 2003, guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $2 million. The Company has also issued a guarantee approximating $4 million related to the residual value of an operating lease that expires in 2006. Vectren Corporation has accrued no liabilities for these guarantees as they relate to guarantees issued among related parties or were executed prior to the adoption of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). As more fully described in Note 10, FIN 45 was adopted prospectively and specifically excludes from its recognition and measurement provisions guarantees issued among related parties. Through June 30, 2003, the Company has not been called upon to satisfy any obligations pursuant to its guarantees. Liabilities accrued for, and activity related to, product warranties are not significant. 9. 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 the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites. Indiana Gas has identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program and is currently conducting some level of remedial activities including groundwater monitoring at certain sites where deemed appropriate and will continue remedial activities at the sites as appropriate and necessary. In conjunction with data compiled by environmental consultants, Indiana Gas has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million. The estimated accrued costs are limited to Indiana Gas' proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas' share of response costs at these 19 sites to between 20% and 50%. With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million. Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen. In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled in the IDEM's Voluntary Remediation Program. In response SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990's. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have recently been initiated by the Company to confirm that the sites continue to pose no such risk. 10. Rate and Regulatory Matters The following is an update on two regulatory matters in Ohio. Each of the discussed matters is currently pending before the PUCO. The first matter relates to an application made to the PUCO by VEDO, together with other regulated Ohio gas utilities, for authority to establish a tariff mechanism to recover expenses related to uncollectible accounts pursuant to an automatic adjustment procedure. The application is pending before the PUCO and, if granted, will enable VEDO to better match revenues with costs associated with fulfilling its obligation to serve customers who are unable to pay their bills. Presently, the amount provided for in VEDO's base rates is not adequate to cover the total expenses relating to uncollectible accounts. The actual positive impact of the tariff mechanism will vary with the as-billed price of natural gas and the number of customers who are unable to pay their bills. While the Company believes there is a sound basis for the PUCO to grant the application to recover actual expenses relating to uncollectible accounts, no assurance can be provided with respect to the ultimate outcome of this proceeding. The second matter concerns the requirement in Ohio that gas utilities, including VEDO, undergo a biannual audit of their gas acquisition practices in connection with the gas cost recovery (GCR) mechanism. In the case of VEDO, on or about August 15, 2003, a third-party consulting firm engaged by the Staff of the PUCO, is scheduled to conclude an audit report to be filed with the PUCO. The audit report will provide the results of that firm's review of VEDO's gas acquisition practices for the biannual period commencing November 1, 2000 (the first day of operations by VEDO) through October 31, 2002. The audit will provide the initial opportunity, in the context of a PUCO GCR proceeding, for a review of the portfolio administration arrangement between VEDO and ProLiance Energy, LLC. Similar arrangements for the Company's other utility subsidiaries, Indiana Gas and SIGECO, were previously reviewed and approved by the IURC. VEDO's prior gas acquisition practices may be challenged in the audit report, including VEDO's relationship with ProLiance, and, as a result, a gas cost disallowance may be recommended. Should such a challenge be made, then, by the first of September 2003, VEDO would file its response. If a hearing is necessary, the earliest it could occur would be mid-September 2003. After that hearing, the PUCO would consider all of the evidence on the matter and make a determination on the merits. Throughout this process VEDO could, and likely would, endeavor to engage in efforts with the participants in the proceeding to resolve disputed issues outside of administrative litigation. The Company believes that VEDO's gas acquisition practices that are the subject of the audit were reasonable. If a challenge is made with respect to VEDO's gas acquisition practices during the audit period and that challenge was adopted by the PUCO, the Company believes that it would not be reasonably likely to have a material effect on the Company's results or financial condition. However, the Company can provide no assurance as to the ultimate outcome of this proceeding. 11. 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 $385 million of accumulated depreciation as presented in the condensed consolidated 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 of a subsidiary 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. 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 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. The incremental disclosure requirements are included in these financial statements in Note 8. 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. 12. Segment Reporting The Company has four operating segments: 1) Gas Utility Services, (2) Electric Utility Services, (3) Nonregulated Operations, and (4) Corporate and Other. The Gas Utility Services segment provides natural gas distribution and transportation services in nearly two-thirds of Indiana and west central Ohio. The Electric Utility Services segment includes the operations of SIGECO's electric transmission and distribution services, which provides electricity primarily to southwestern Indiana, and SIGECO's power generating and power marketing operations. The Company collectively refers to its gas and electric utility services segments as its Regulated Operations. Segments within the Regulated Operations use operating income as a measure of profitability. The Nonregulated Operations segment is comprised of various subsidiaries and affiliates offering and investing in energy marketing and services, coal mining, utility infrastructure services, and broadband communications among other energy-related opportunities. The Corporate and Other segment, among other activities, provides general and administrative support and assets, including computer hardware and software, to the Company's other operating segments. The Nonregulated Operations and Corporate and Other segments use net income as a measure of profitability. The Company makes decisions on finance and dividends at the corporate level. Following is information regarding the Company's segments' operating data.
Three Months Six Months Ended June 30, Ended June 30, ---------------------- --------------------- In millions 2003 2002 2003 2002 --------------------------------------- --------- --------- ------- --------- Operating Revenues Gas Utility Services $ 165.1 $ 140.1 $ 674.6 $ 498.2 Electric Utility Services 90.2 158.9 209.6 285.7 ----------------------------------------------------------------------------------------- Total Regulated 255.3 299.0 884.2 783.9 ----------------------------------------------------------------------------------------- Nonregulated Operations 47.7 97.0 100.9 256.5 Corporate & Other 6.8 5.6 13.7 11.4 Intersegment Eliminations (26.4) (21.5) (52.9) (41.3) ----------------------------------------------------------------------------------------- Total operating revenues $ 283.4 $ 380.1 $ 945.9 $ 1,010.5 ========================================================================================= Measure of Profitability Operating Income Gas Utility Services $ 0.2 $ 4.7 $ 69.5 $ 66.8 Electric Utility Services 15.3 18.4 39.2 34.8 ----------------------------------------------------------------------------------------- Total Regulated operating income 15.5 23.1 108.7 101.6 ----------------------------------------------------------------------------------------- Regulated other income (expense)-net 0.1 2.2 (1.0) 4.2 Regulated interest expense (15.4) (15.7) (30.9) (31.6) Regulated income taxes (1.4) (2.5) (30.9) (25.9) ----------------------------------------------------------------------------------------- Regulated net income (loss) (1.2) 7.1 45.9 48.3 ----------------------------------------------------------------------------------------- Nonregulated net income 3.4 4.4 11.9 8.8 Corporate & other net income 1.9 1.0 2.0 1.0 ----------------------------------------------------------------------------------------- Net income $ 4.1 $ 12.5 $ 59.8 $ 58.1 =========================================================================================
Following is the Company's segments' identifiable assets. June 30, December 31, In millions 2003 2002 ----------------------------------------------------- ---------- Identifiable Assets Gas Utility Services $ 1,413.8 $ 1,570.1 Electric Utility Services 871.7 869.2 ------------------------------------------------------------------ Total Regulated 2,285.5 2,439.3 ------------------------------------------------------------------ Nonregulated Operations 404.4 419.6 Corporate & Other 373.0 393.3 Intersegment Eliminations (242.7) (325.7) ------------------------------------------------------------------ Total identifiable assets $ 2,820.2 $ 2,926.5 ================================================================== 13. Subsequent Events Equity Issuance In August 2003, the Company completed a public offering of 6.5 million shares of its common stock, which was priced at $22.81 per share to yield total gross proceeds $148.3 million. The Company also has granted the underwriters a 30-day option to purchase up to an additional 975,000 shares of the Company's common stock at the public offering price to cover over-allotments, if any. The public offering of the shares closed on August 13, 2003 with net proceeds of approximately $143 million (excluding any proceeds from an over-allotment option). VUHI Debt Issuance In July 2003, VUHI issued senior unsecured notes with an aggregate principal amount of $200 million in two $100 million tranches. The first tranche are 10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746% to yield 5.28% to maturity (2013 Notes). The second tranche are 15-year notes due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity (2018 Notes). The notes are jointly and severally guaranteed by the Company's three public utilities. In addition, they have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by the Company, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2013 Notes and 25 basis points for the 2018 Notes. Shortly before these issues, the Company entered into several treasury locks with a total notional amount of $150.0 million. Upon issuance of the debt, the treasury locks were settled resulting in the Company receiving $5.7 million. The value received will be amortized as a reduction of interest expense over the life of the issues. The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $203 million. SIGECO and Indiana Gas Debt Call In August 2003, the Company initiated steps to call two first mortgage bonds outstanding at SIGECO and a senior unsecured note outstanding at Indiana Gas. The first SIGECO 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. The Indiana Gas note has a principal amount of $13.5 million, an interest rate of 6.75%, was originally due in 2028, and may be redeemed at the 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. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Description of the Business Vectren Corporation (the Company or Vectren), an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company was organized on June 10, 1999 solely for the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with APB Opinion No. 16 "Business Combinations" (APB 16). The Company's wholly owned subsidiary, Vectren Utility Holdings, Inc. (VUHI), serves as the intermediate holding company for its three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations. VUHI also has other assets that provide information technology and other services to the three utilities. Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935. Indiana Gas provides natural gas distribution and transportation services to a diversified customer base in 49 of Indiana's 92 counties. SIGECO provides electric generation, transmission, and distribution services to 8 counties in southwestern Indiana, including counties surrounding Evansville, and participates in the wholesale power market. SIGECO also provides natural gas distribution and transportation services to 10 counties in southwestern Indiana, including counties surrounding Evansville. The Ohio operations, owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc.(VEDO), a wholly owned subsidiary, (53 % ownership) and Indiana Gas (47 % ownership), provide natural gas distribution and transportation services to 17 counties in west central Ohio, including counties surrounding Dayton. The Company is also involved in nonregulated activities in four primary business areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure Services, and Broadband. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal to the Company's utility operations and to other parties and generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. Broadband invests in broadband communication services such as analog and digital cable television, high-speed Internet and data services, and advanced local and long distance phone services. In addition, the nonregulated group has other businesses that provide utility services, municipal broadband consulting, and retail products and services and that invest in energy-related opportunities, real estate, and leveraged leases. Consolidated Results of Operations The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated 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 both the three and six months ended June 30, 2002 by $1.8 million after tax. Note 3 to the consolidated condensed financial statements includes a summary of the effects of the restatement. The Company's results of operations give effect to the restatement. Three Months Six Months Ended June 30, Ended June 30, ---------------------- --------------------- In millions, except per share amounts 2003 2002 2003 2002 -------------------------------- ---------------------- --------------------- As Restated As Restated ----------- ----------- Net income $ 4.1 $ 12.5 $ 59.8 $ 58.1 Attributed to: Utility Group $ 1.4 $ 8.7 $ 48.7 $ 50.7 Nonregulated Group 3.4 4.4 11.9 8.8 Corporate & Other Group (0.7) (0.6) (0.8) (1.4) ---------------------------------------------------------------------------- Basic earnings per share $ 0.06 $ 0.18 $ 0.88 $ 0.86 Attributed to: Utility Group $ 0.02 $ 0.13 $ 0.72 $ 0.75 Nonregulated Group 0.05 0.06 0.18 0.13 Corporate & Other Group (0.01) (0.01) (0.02) (0.02) Net Income For the three months ended June 30, 2003, net income was $4.1 million, or $0.06 per share, compared to net income of $12.5 million, or $0.18 per share, for the same period last year. For the six months ended June 30, 2003, reported earnings were $59.8 million, or $0.88 per share, compared to $58.1 million, or $0.86 per share, for the same period in 2002. The 2003 second quarter results declined $0.10 per share as compared to the same period in 2002 due to milder weather affecting both heating and cooling sales and the write-off of two investments. 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. The estimated quarter over quarter impact of milder weather was $4.3 million after tax, or $0.06 per share. The 2003 results include the write-off of the Company's investment in BABB International, Inc. (BABB), an entity that processes fly ash into building materials. Charges of $1.9 million, pre-tax and $2.0 million, pre-tax were recorded in the second and first quarters, respectively, of 2003. The second quarter 2003 also includes the write-off of $2.0 million pre-tax of the investment in First Mile Technologies (First Mile), a small broadband entity located in Indianapolis, Indiana. The write-off of both investments reduced net income for the second quarter by $2.3 million, or $0.04 per share, and the first six months by $3.5 million, or nearly $0.06 per share. Dividends Dividends declared for the three months ended June 30, 2003 were $0.275 per share compared to $0.265 per share for the same period in 2002. Dividends declared for the six months ended June 30, 2003 were $0.550 per share compared to $0.530 per share for the same period in 2002. Detailed Discussion of Results of Operations Following is a more detailed discussion of the results of operations of the Company's Utility Group and Nonregulated Group. The detailed results of operations for the Utility Group and Nonregulated Group are presented and analyzed before the reclassification and elimination of certain intersegment transactions necessary to consolidate those results into the Company's Consolidated Condensed Statements of Income. The operations of the Corporate and Other Group are not significant. Results of Operations of the Utility Group The Utility Group is comprised of Vectren Utility Holdings, Inc.'s operations, which consist of the Company's regulated operations (the Gas Utility Services and Electric Utility Services operating segments), and components of the Corporate and Other operating segment. Gas Utility Services provides natural gas distribution and transportation services in nearly two-thirds of Indiana and west central Ohio. Electric Utility Services provides electricity primarily to southwestern Indiana, and includes the Company's power generating and marketing operations. Corporate and Other Operations provides information technology and other support services to those utility operations. The results of operations of the Utility Group before certain intersegment eliminations and reclassifications for the three and six months ended June 30, 2003 and 2002 follow. Three Months Six Months Ended June 30, Ended June 30, ----------------- ----------------- In millions, except per share amounts 2003 2002 2003 2002 ------------------------------------ ------- ------- ------- ------- OPERATING REVENUES Gas revenues $ 165.1 $ 140.1 $ 674.6 $ 498.2 Electric revenues 90.2 158.9 209.6 285.7 Other revenues 0.2 0.1 0.4 0.2 ----------------------------------------------------------------------------- Total operating revenues 255.5 299.1 884.6 784.1 ----------------------------------------------------------------------------- OPERATING EXPENSES Cost of gas 104.3 82.1 469.4 312.6 Fuel for electric generation 20.6 19.1 41.4 36.9 Purchased electric energy 18.8 86.8 59.2 146.5 Other operating 53.9 48.8 110.5 100.1 Depreciation & amortization 29.6 26.3 58.4 53.1 Taxes other than income taxes 10.9 10.0 32.6 28.1 ----------------------------------------------------------------------------- Total operating expenses 238.1 273.1 771.5 677.3 ----------------------------------------------------------------------------- OPERATING INCOME 17.4 26.0 113.1 106.8 OTHER INCOME (EXPENSE) - NET Equity in losses of unconsolidated affiliates 0.1 (0.4) (0.4) (0.5) Other - net 0.2 3.7 (1.3) 5.8 ----------------------------------------------------------------------------- Total other income (expense) - net 0.3 3.3 (1.7) 5.3 ----------------------------------------------------------------------------- Interest expense 15.9 17.3 32.4 34.9 ----------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 1.8 12.0 79.0 77.2 ----------------------------------------------------------------------------- Income taxes 0.4 3.3 30.3 26.5 ----------------------------------------------------------------------------- NET INCOME $ 1.4 $ 8.7 $ 48.7 $ 50.7 ============================================================================= BASIC EARNINGS PER SHARE $ 0.02 $ 0.13 $ 0.72 $ 0.75 ============================================================================= Utility Group earnings for the second quarter 2003 were $1.4 million as compared to $8.7 million for the same quarter last year. As noted previously, the primary contributors to the decline are electric cooling weather that was significantly below normal in the 2003 quarter and the write-off of the BABB investment. Utility Group earnings for the six months ended June 30, 2003 were $48.7 million as compared to $50.7 million for the same period in 2002. Earnings in 2003 were primarily driven by weather that on the year was favorably impacted by an estimated $5.4 million after tax compared to last year and increased wholesale and other margins, offset by the BABB investment write-off of $2.3 million after tax and increased other operating costs. Significant Fluctuations Utility Margin Gas Utility Margin Gas utility margin by customer type and separated between volumes sold and transported follows: Three Months Six Months Ended June 30, Ended June 30, ---------------- ----------------- In millions 2003 2002 2003 2002 ------------------------ ---------------- ----------------- Residential $ 38.7 $ 34.9 $ 132.5 $ 119.8 Commercial 10.0 13.7 42.5 40.6 Contract 8.8 8.6 24.4 23.6 Other 3.3 0.8 5.8 1.6 ------------------------------------------------------------ Total gas margin $ 60.8 $ 58.0 $ 205.2 $ 185.6 ============================================================ Volumes in MMDth Sold 14.6 15.9 78.5 67.6 Transported 17.6 19.3 45.8 46.2 ------------------------------------------------------------ Total throughput 32.2 35.2 124.3 113.8 ============================================================ Gas margins were $60.8 million, an increase of $2.8 million over the same quarter in 2002. The increase is primarily due to increased late payment charges, an increase in Ohio's percent of income payment plan (PIPP) rate recovery rider, recovery of Ohio customer choice implementation costs, recovery of gross receipts and excise taxes on higher gas costs, and other items. The increase was partially offset by 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 $3.3 million. Weather and an overall decline in customer usage were the primary factors resulting in the 8% decrease in throughput. Gas margins were $205.2 million, an increase of $19.6 million over the first six months of 2002. It is estimated that weather, 17% colder than the prior year and 7% colder than normal, contributed $12.0 million to the increased margin. The remaining $7.6 million increase is primarily attributable to gross receipts and excise taxes, increased late payment fees, and recovery of Ohio customer choice implementation costs. The colder weather is the primary reason for the 9% 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 $6.48 and $6.51, respectively, compared to $4.46 for both periods in 2002. 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. Utility Group Operating Expenses Other Operating For the three and six months ended June 30, 2003, other operating expenses increased $5.1 million and $10.4 million, respectively, compared to the same periods in the prior year. The increased expenses were principally due to higher uncollectible accounts expenses, the timing of electric plant maintenance expenditures, and other costs such as PIPP and Ohio customer choice costs that are recovered through margins. Year-to-date uncollectible accounts expense has increased $2.7 million compared to the prior year. Depreciation & Amortization For the three and six months ended June 30, 2003, depreciation and amortization increased $3.3 million and $5.3 million, respectively, due to additions to utility plant. Since June 30, 2002, the Company has placed into service over $100 million in utility plant including a new gas-fired peaker unit, expenditures for implementing a choice program for Ohio gas customers, and other upgrades to existing transmission and distribution facilities. Taxes Other Than Income Taxes For the three and six months ended June 30, 2003, taxes other than income taxes increased $0.9 million and $4.5 million, respectively, compared to the prior year. The increase results from higher utility receipts and excise taxes as a result of higher gas prices and for the year to date period more volumes sold. Utility Group Other Income (Expense)-Net For the three and six months ended June 30, 2003, other income (expense)-net decreased $3.0 million and $7.0 million, respectively, compared to the prior year. The decreases are primarily the result of the write-off of the BABB investment ($1.9 million for the quarter and $3.9 million for the year to date). The remaining decreases result principally from sales of emission allowances and other assets in the second quarter of 2002 totaling $1.8 million. Year to date results are also affected by contributions of $1.2 million made in 2003 to low income customer assistance programs resulting from the ProLiance settlement previously approved by the IURC. Utility Group Interest Expense For the three and six months ended June 30, 2003, interest expense decreased $1.4 million and $2.5 million, respectively, when compared to the same periods last year. The decreases result primarily from lower interest rates. This was partially offset by higher outstanding balances due primarily to funding of capital expenditures and increased working capital requirements resulting from the higher gas prices experienced during late 2002 and 2003. Utility Group Income Tax For the three months ended June 30, 2003, federal and state income taxes decreased $2.9 million and for the six months ended June 30, 2003 increased $3.8 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 34.3% in 2002 to 38.4% 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. 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 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 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 SCRs 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 the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites. Indiana Gas has identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program and is currently conducting some level of remedial activities including groundwater monitoring at certain sites where deemed appropriate and will continue remedial activities at the sites as appropriate and necessary. In conjunction with data compiled by environmental consultants, Indiana Gas has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million. The estimated accrued costs are limited to Indiana Gas' proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas' share of response costs at these 19 sites to between 20% and 50%. With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million. Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen. In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled in the IDEM's Voluntary Remediation Program. In response SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990's. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow-up reviews have recently been initiated by the Company to confirm that the sites continue to pose no such risk. Rate and Regulatory Matters The following is an update on two regulatory matters in Ohio. Each of the discussed matters is currently pending before the PUCO. The first matter relates to an application made to the PUCO by VEDO, together with other regulated Ohio gas utilities, for authority to establish a tariff mechanism to recover expenses related to uncollectible accounts pursuant to an automatic adjustment procedure. The application is pending before the PUCO and, if granted, will enable VEDO to better match revenues with costs associated with fulfilling its obligation to serve customers who are unable to pay their bills. Presently, the amount provided for in VEDO's base rates is not adequate to cover the total expenses relating to uncollectible accounts. The actual positive impact of the tariff mechanism will vary with the as-billed price of natural gas and the number of customers who are unable to pay their bills. While the Company believes there is a sound basis for the PUCO to grant the application to recover actual expenses relating to uncollectible accounts, no assurance can be provided with respect to the ultimate outcome of this proceeding. The second matter concerns the requirement in Ohio that gas utilities, including VEDO, undergo a biannual audit of their gas acquisition practices in connection with the gas cost recovery (GCR) mechanism. In the case of VEDO, on or about August 15, 2003, a third-party consulting firm engaged by the Staff of the PUCO, is scheduled to conclude an audit report to be filed with the PUCO. The audit report will provide the results of that firm's review of VEDO's gas acquisition practices for the biannual period commencing November 1, 2000 (the first day of operations by VEDO) through October 31, 2002. The audit will provide the initial opportunity, in the context of a PUCO GCR proceeding, for a review of the portfolio administration arrangement between VEDO and ProLiance Energy, LLC. Similar arrangements for the Company's other utility subsidiaries, Indiana Gas and SIGECO, were previously reviewed and approved by the IURC. VEDO's prior gas acquisition practices may be challenged in the audit report, including VEDO's relationship with ProLiance, and, as a result, a gas cost disallowance may be recommended. Should such a challenge be made, then, by the first of September 2003, VEDO would file its response. If a hearing is necessary, the earliest it could occur would be mid-September 2003. After that hearing, the PUCO would consider all of the evidence on the matter and make a determination on the merits. Throughout this process VEDO could, and likely would, endeavor to engage in efforts with the participants in the proceeding to resolve disputed issues outside of administrative litigation. The Company believes that VEDO's gas acquisition practices that are the subject of the audit were reasonable. If a challenge is made with respect to VEDO's gas acquisition practices during the audit period and that challenge was adopted by the PUCO, the Company believes that it would not be reasonably likely to have a material effect on the Company's results or financial condition. However, the Company can provide no assurance as to the ultimate outcome of this proceeding. Results of Operations of the Nonregulated Group The Nonregulated Group is comprised of four primary business areas: Energy Marketing and Services, Coal Mining, Utility Infrastructure Services, and Broadband. Energy Marketing and Services markets natural gas and provides energy management services, including energy performance contracting services. Coal Mining mines and sells coal to the Company's utility operations and to other parties and generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels. Utility Infrastructure Services provides underground construction and repair, facilities locating, and meter reading services. Broadband invests in broadband communication services such as analog and digital cable television, high-speed Internet and data services, and advanced local and long distance phone services. In addition, the Nonregulated Group has other businesses that provide utility services, municipal broadband consulting, and retail products and services and that invest in energy-related opportunities, real estate, and leveraged leases. The results of operations of the Nonregulated Group before certain intersegment eliminations and reclassifications for the three and six months ended June 30, 2003 and 2002 follow: Three Months Six Months Ended June 30, Ended June 30, ---------------- ----------------- In millions, except per share amounts 2003 2002 2003 2002 -------------------------------------- ------ ------ ------- ------- Energy services & other revenues $ 47.7 $ 97.0 $ 100.9 $ 256.5 Operating expenses: Cost of energy services & other revenues 38.2 87.1 82.9 235.1 Operating expenses 9.3 9.3 18.4 18.4 ---------------------------------------------------------------------------- Total expenses 47.5 96.4 101.3 253.5 ---------------------------------------------------------------------------- OPERATING INCOME (LOSS) 0.2 0.6 (0.4) 3.0 Other income (expense): Equity in earnings of unconsolidated affiliates (0.2) 4.1 9.1 7.3 Other - net (1.1) (0.5) - 0.5 ---------------------------------------------------------------------------- Total other income (expense) (1.3) 3.6 9.1 7.8 ---------------------------------------------------------------------------- Interest expense 2.4 2.2 4.8 4.5 ---------------------------------------------------------------------------- INCOME BEFORE TAXES (3.5) 2.0 3.9 6.3 Income tax (6.9) (2.4) (8.1) (2.3) Minority interest in consolidated subsidiaries - - 0.1 (0.2) ---------------------------------------------------------------------------- NET INCOME $ 3.4 $ 4.4 $ 11.9 $ 8.8 ============================================================================ BASIC EARNINGS PER SHARE $ 0.05 $ 0.06 $ 0.18 $ 0.13 ============================================================================ NET INCOME ATTRIBUTED TO: Energy Marketing & Services $ 2.1 $ 3.6 $ 10.5 $ 8.2 Coal Mining 4.7 2.9 7.2 4.9 Utility Infrastructure (0.2) - (1.2) (0.5) Broadband (1.2) 0.1 (1.1) 0.2 Other Businesses (2.0) (2.2) (3.5) (4.0) Nonregulated earnings for the second quarter 2003 decreased to $3.4 million as compared to $4.4 million for the same period last year due to the impact of the write-off of First Mile, a small broadband investment. Nonregulated earnings for the six months ended June 30, 2003 were $11.9 million in 2003 as compared to $8.8 million for the same period in 2002. The $3.1 million increase results primarily from increased earnings generated by the Company's investments in ProLiance Energy, LLC (ProLiance) and Pace Carbon Synfuels, LP (Pace Carbon), offset somewhat by the current quarter write-off of the First Mile investment. ProLiance is a component of the Energy Marketing and Services Group and Pace Carbon is a component of the Coal Mining Group. Energy Marketing & Services Energy Marketing and Services includes the Company's gas marketing operations. These gas marketing operations are performed through the Company's investment in ProLiance, a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas). ProLiance provides natural gas and related services to Indiana Gas, the Ohio operations, and Citizens Gas and also began providing services to SIGECO and Vectren Retail, LLC (the Company's retail gas marketer) in 2002. ProLiance's primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. ProLiance's primary customers are utilities and other large end use customers. In June 2002, the integration of Vectren's wholly owned gas marketing subsidiary, SIGCORP Energy Services, LLC (SES), with ProLiance was completed. SES provided natural gas and related services to SIGECO and others prior to the integration. In exchange for the contribution of SES' net assets, Vectren's allocable share of ProLiance's profits and losses increased from 52.5% to 61%, consistent with Vectren's new ownership percentage. Governance and voting rights remain at 50% for each member. Since governance of ProLiance remains equal between the members, Vectren continues to account for its investment in ProLiance using the equity method of accounting. Prior to June 1, 2002, SES' operating results were consolidated. Subsequent to June 1, 2002, SES' operating results, now part of ProLiance, are reflected in equity in earnings of unconsolidated affiliates. SES' revenues and expenses were the primary component of nonregulated revenues and cost of revenues. Therefore, the integration significantly decreased revenues, cost of revenues, and operating expenses. For the three months ended June 30, 2003, revenues, cost of revenues, and operating expenses decreased $61.0 million, $58.6 million, and $1.8 million, respectively, compared to 2002. And, for the six months ended June 30, 2003, revenues, cost of revenues, and operating expenses decreased $186.3 million, $178.7 million, and $4.1 million, respectively, compared to 2002. The transfer of net assets was accounted for at book value consistent with joint venture accounting and did not result in any gain or loss. For the Company's portion of ProLiance's operations, $2.7 million and $5.4 million, respectively, is included in equity in earnings of unconsolidated affiliates for the three months ended June 30, 2003 and 2002. For the six months ended June 30, 2003 and 2002, such amounts included in equity in earnings of unconsolidated affiliates are $17.0 million and $10.8 million, respectively. For the quarter, gas marketing's contribution was down $2.2 million period over period primarily due to the timing of costs and optimization benefits related to pipeline contracts. For the year to date period, gas marketing's contribution increased $1.2 million period over period due to continued realization of benefits from the integration of its two gas marketing companies in 2002 and from opportunities provided by gas price volatility in the first quarter. In addition to gas marketing, Energy Marketing and Services includes the operations of Energy Systems Group, LLC (ESG), which provides energy performance contracting and facility upgrades through its design and installation of energy-efficient equipment. Prior to April 2003, ESG was a consolidated venture between the Company and Citizens Gas with the Company owning two-thirds. In April 2003, the Company purchased the remaining interest in ESG for approximately $4 million. For the three and six months ended June 30, 2003 earnings from ESG were $0.6 million compared to a loss for the quarter of $0.1 million and $0.3 million for the year to date period in 2002. The $0.7 million increase for the quarter and $0.9 million increase year to date are due primarily to success in obtaining higher margins and working from a higher construction backlog at the end of 2002. ESG's results also reflect 100% Vectren ownership during the quarter versus 67% Vectren ownership in 2002. For the quarter, ESG produced operating income of approximately $1.1 million on sales of $12.3 million compared to an operating loss of $0.2 million on sales of $7.8 million in the prior year. And for the six months ended June 30, 2003, ESG produced operating income of approximately $1.1 million on sales of $21.2 million compared to an operating loss of $0.5 million on sales of $13.4 million in the prior year. Coal Mining Coal Mining generates IRS Code Section 29 investment tax credits relating to the production of coal-based synthetic fuels through its 8.3% ownership interest in Pace Carbon. Pace Carbon is a Delaware limited partnership formed to develop, own, and operate four projects to produce and sell coal-based synthetic fuel (synfuel) utilizing Covol technology. Vectren accounts for is investment in Pace Carbon using the equity method. The group also mines and sells coal to the Company's utility operations and to other third parties through its wholly owned subsidiary Vectren Fuels, Inc. (Fuels). In addition, Fuels receives synfuel-related fees from synfuel producers unrelated to Pace Carbon for a portion of its coal production. For the three months ended June 30, 2003 and 2002, the investment in Pace Carbon resulted in losses reflected in equity in earnings of unconsolidated affiliates of $2.9 million and $2.4 million, respectively. For the six months ended June 30, 2003 and 2002, the investment in Pace Carbon resulted in losses reflected in equity in earnings of unconsolidated affiliates of $6.4 million and $3.3 million, respectively. Losses have increased as a result of increased production of synthetic fuels and higher production costs. The production of synfuel generates IRS Code Section 29 investment tax credits that are reflected in income taxes. These credits have also increased consistent with increased synfuel production. Net income, including the losses, tax benefits, and tax credits, generated from the investment in Pace Carbon totaled $3.2 million and $1.3 million for the three months ended June 30, 2003 and 2002, respectively, and totaled $4.8 million and $2.1 million for the six months ended June 30, 2003 and 2002, respectively. For the three months ended June 30, 2003, earnings from Fuels were $1.5 million, compared to earnings of $1.6 million in 2002. For the six months ended June 30, 2003, earnings from Fuels were $2.4 million, compared to earnings of $2.8 million in 2002. During both the quarter and year to date period, net income and operating income decreased as a result of lower market prices on third party coal sales, a lower yield per ton mined, and increased depreciation of mine development costs, offset by increased synfuel-related fees. For the quarter, Fuels produced operating income of approximately $2.5 million on sales of $29.6 million compared to operating income of $3.3 million on sales of $26.2 million in the prior year. And for the six months ended June 30, 2003, Fuels produced operating income of approximately $4.0 million on sales of $56.8 million compared to operating income of $5.1 million on sales of $51.4 million in the prior year. For the three months ended June 30, 2003 and 2002, total synfuel-related results, which reflect earnings from the investment in Pace Carbon and Fuel's synfuel-related fees, were $4.3 million and $2.0 million, respectively. For the six months ended June 30, 2003 and 2002, synfuel-related results were $6.6 million and $3.5 million, respectively. IRS Section 29 Investment Tax Credit Recent Developments Under Section 29 of the Internal Revenue Code, manufacturers such as Pace Carbon, receive a tax credit for every ton of synthetic fuel sold. To qualify for the credits, the synthetic fuel must meet three primary conditions: 1) there must be a significant chemical change in the coal feedstock, 2) the product must be sold to an unrelated person, and 3) the production facility must have been placed in service before July 1, 1998. In past rulings, the Internal Revenue Service (IRS) has concluded that the synthetic fuel produced at the Pace Carbon facilities should qualify for Section 29 tax credits. The IRS issued a private letter ruling with respect to the four projects on November 11, 1997, and subsequently issued an updated private letter ruling on September 23, 2002. As a partner in Pace Carbon, Vectren has reflected total tax credits under Section 29 in its consolidated results through June 30, 2003 of approximately $30 million. Vectren has been in a position to fully utilize the credits generated and continues to project full utilization. On June 27, 2003, the IRS, in an industry-wide announcement, stated that it has reason to question the scientific validity of certain test procedures and results that have been presented to it by certain taxpayers with an interest in synfuel operations. Accordingly, the IRS has suspended the issuance of new private letter rulings. In addition, the IRS indicated that it may revoke existing private letter rulings that relied on the procedures and results under review if it determines that those test procedures and results do not demonstrate that a significant chemical change has occurred. During June 2001, the IRS began a tax audit of Pace Carbon for the 1998 tax year and later expanded the audit to include tax years 1999 and 2000. The IRS has requested numerous extensions to the statute of limitations for the years under audit. It is expected that the issue of the existence of chemical change will be formally raised in the Pace Carbon audit. At this time, Vectren cannot predict the outcome of the IRS' review of the industry-wide issues, when that review will be completed or the ultimate impact, if any, of the audit of Pace Carbon relative to Vectren's investments in Pace Carbon. Vectren believes that it is justified in its reliance on the private letter rulings for the Pace Carbon facilities, that the test results that Pace Carbon presented to the IRS in connection with its private letter rulings are scientifically valid, and that Pace Carbon has operated its facilities in compliance with its private letter rulings and Section 29 of the Internal Revenue Code. Utility Infrastructure Services Utility Infrastructure Services provides underground construction and repair of utility infrastructure services to the Company and to other gas, water, electric, and telecommunications companies as well as facilities locating and meter reading services through its investment in Reliant Services, LLC (Reliant). Reliant is a 50% owned strategic alliance with an affiliate of Cinergy Corp. and is accounted for using the equity method of accounting. Reliant's losses have increased in 2003 primarily due to continued cutbacks of underground construction and repair projects from gas distribution utility customers, which began in the later part of 2002. Broadband Broadband invests in broadband communication services such as cable television, high-speed Internet, and advanced local and long distance phone services. The Company has an approximate 1% equity interest and a convertible subordinated debt investment in Utilicom Networks, LLC (Utilicom) that if converted bring the Company's ownership interest up to 12%. Utilicom is a provider of bundled communication services focusing on last mile delivery to residential and commercial customers. The Company also has an 18.9% equity interest in SIGECOM Holdings, Inc. (Holdings), which was formed by Utilicom to hold interests in SIGECOM, LLC (SIGECOM). SIGECOM provides broadband services to the greater Evansville, Indiana, area. The equity investments in Utilicom and Holdings are accounted for using the cost method of accounting. As a result, for the three and six months ended June 30, 2003 and 2002, these investments had no significant impact on the Company's operating results. Utilicom also plans to provide broadband services to the greater Indianapolis, Indiana, and Dayton, Ohio, markets. However, the funding of these projects has been delayed due to the continued difficult environment within the telecommunication capital markets, which has prevented Utilicom from obtaining debt financing on terms it considers acceptable. While the existing investors remain interested in the Indianapolis and Dayton projects, the Company is not required to make further investments and does not intend to proceed unless commitments are obtained to fully fund these projects. Franchising agreements have been extended in both locations. In addition to its Utilicom-related investment, the Company also had an investment in First Mile, a small broadband entity located in Indianapolis, Indiana. During the three months ended June 30, 2003, the Company disposed of its First Mile investment at a loss recorded in other-net totaling $2.0 million ($1.2 after tax). Other Businesses The Other Businesses Group includes a variety of wholly owned operations and investments. The significant activities that affected the nonregulated results of operations during the three and six months ended June 30, 2003 compared to 2002 are the wholly owned operations of Vectren Retail, LLC (Vectren Retail), Vectren Communication Services, Inc. (VCS), and Southern Indiana Properties, Inc. (SIPI), and the Haddington Partnerships investments. Vectren Retail provides natural gas and other related products and services primarily in Ohio, serving customers opting for choice among energy providers. Vectren Retail began operations in 2001 and continues to incur startup costs. During the three and six months ended June 30, 2003, these start up costs have increased operating expenses approximately $0.7 million and $1.8 million, respectively, compared to the same periods in 2002. For the three months ended June 30, 2003, Vectren Retail incurred an operating loss of approximately $1.4 million on sales of $4.7 million compared to an operating loss of $1.0 million on sales of $0.6 million in the prior year. And for the six months ended June 30, 2003, Vectren Retail incurred an operating loss of approximately $1.5 million on sales of $20.6 million compared to an operating loss of $1.8 million on sales of $2.2 million in the prior year. The net loss incurred by Vectren Retail for the quarter was $0.9 million in 2003 and $0.6 million in 2002. Year to date, the net loss incurred was $1.0 million in 2003 and $1.1 million in 2002. VCS is a wholly owned broadband consulting company. For the three and six months ended June 30, 2003, operating income contributed by VCS increased $0.8 million and $0.7 million, respectively, when compared to the prior year. The increase is primarily due to charges incurred in 2002 related to the settlement of construction contracts and the reorganization of its operations, allowing it to focus on consulting services. For the three months ended June 30, 2003 and 2002, net losses incurred by VCS were $0.5 million and $1.0 million, respectively. For the six months ended June 30, 2003 and 2002, net losses incurred by VCS were $1.0 million and $1.7 million, respectively. SIPI is a wholly owned company with various investments in leveraged leases, notes receivable, and unconsolidated affiliates. For both the three and six months ended June 30, 2003, the net loss incurred by SIPI decreased $0.7 million. The decrease is primarily due to charges to income tax expense incurred in 2002 related to a change in Indiana corporate income tax laws. The tax law change, which effectively increased Vectren's state income tax rate from 4.5% to 8.5%, required the recalculation of SIPI's deferred tax obligations and earnings from leveraged lease investments at the date of enactment of the law. The Haddington Partnerships are equity method investments that invest in energy-related opportunities. The 2002 results include earnings of $1.3 million ($0.8 million after tax). The earnings resulted from allocating proceeds generated from the sale of investments. Such earnings are included in equity in earnings of unconsolidated affiliates, and have not recurred in 2003. Other Nonregulated Transactions In early August, 2003, the Company disposed of its interest in two nonregulated businesses. These actions were in furtherance of the Company's objective to narrow the scope of its nonregulated businesses. Proceeds realized from these dispositions will be used to reduce outstanding debt at the Company's nonregulated business. The first disposition was closed as of August 1, 2003, when the Company consummated the sale of its investment in Genscape, Inc., a supplier of real-time power plant output and transmission information, to GFI Energy Ventures, LLC. The after-tax gain realized by the Company was approximately $2.6 million. The second disposition was closed on August 4, 2003, and involved CIGMA, LLC (CIGMA), a joint venture between the Company and a subsidiary of Citizens Gas. In that transaction, substantially all of CIGMA's assets were sold to McJunkin Corporation. CIGMA had been engaged in utility materials management for the Company's utility subsidiaries, Citizens Gas & Coke Utility, and others. As a result of the transaction, the Company realized a small after-tax gain, and received a cash dividend from CIGMA of $4 million. United States Securities and Exchange Commission (SEC) Informal Inquiry As more fully described in Note 3 to these consolidated condensed financial statements and in Note 3 to the 2002 consolidated financial statements filed on Form 10-K/A, the Company restated its consolidated 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. 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 of a subsidiary 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. The incremental disclosure requirements are included in these financial statements in Note 8. 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. Financial Condition Within Vectren's consolidated group, VUHI funds short-term and long-term financing needs of the utility group operations, and Vectren Capital Corp (Vectren Capital) funds short-term and long-term financing needs of the nonregulated and corporate operations. Vectren Corporation guarantees Vectren Capital's debt, but does not guarantee VUHI's debt. Vectren Capital's long-term and short-term obligations outstanding at June 30, 2003 totaled $113.0 million and $68.6 million, respectively. VUHI's outstanding long-term and short-term borrowing arrangements are jointly and severally guaranteed by Indiana Gas, SIGECO, and VEDO. VUHI's long-term and short-term obligations outstanding at June 30, 2003 totaled $350.0 million and $318.6 million, respectively. Additionally, prior to VUHI's formation, Indiana Gas and SIGECO funded their operations separately, and therefore, have long-term debt outstanding funded solely by their operations. Utility operations have historically funded the Company's common stock dividends. Nonregulated operations have demonstrated sustained profitability, and the ability to generate cash flows. These cash flows are ordinarily reinvested in other nonregulated ventures or used for corporate expenses. VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at June 30, 2003 are A-/Baa1 as rated by Standard and Poor's Ratings Services (Standard and Poor's) and Moody's Investors Service (Moody's), respectively. SIGECO's credit ratings on outstanding senior unsecured debt at June 30, 2003 are BBB+/Baa1. SIGECO's credit ratings on outstanding secured debt at June 30, 2003 are A-/A3. VUHI's commercial paper has a credit rating of A-2/P-2. Vectren Capital's senior unsecured debt is rated BBB+/Baa2. Moody's current outlook is stable while Standard and Poor's current outlook is negative. The ratings of Moody's and Standard and Poor's are categorized as investment grade and are unchanged from December 31, 2002. In July 2003, Standard and Poor's reaffirmed its ratings, and Moody's reaffirmed its ratings on VUHI's senior unsecured debt. A security rating is not a recommendation to buy, sell, or hold securities. The rating is subject to revision or withdrawal at any time, and each rating should be evaluated independently of any other rating. Standard and Poor's and Moody's lowest level investment grade rating is BBB- and Baa3, respectively. The Company's consolidated equity capitalization objective is 45-55% of total capitalization. This objective may have varied, and will vary, depending on particular business opportunities, capital spending requirements, and seasonal factors that affect the Company's operation. The Company's equity component was 48% and 46% of total capitalization, including current maturities of long-term debt and long-term debt subject to tender, at June 30, 2003 and December 31, 2002, respectively. The Company expects the majority of its capital expenditures, investments, and debt security redemptions to be provided by internally generated funds. However, additional permanent financing will be required due to significant capital expenditures for NOx compliance equipment at SIGECO and plans to further strengthen the Company's capital structure and the capital structures of VUHI and its utility subsidiaries. These plans include the issuance of new equity and debt and the calling of certain long-term debt at SIGECO and Indiana Gas. In April 2003, the Company filed with the United States Securities and Exchange Commission a registration statement, as amended, to issue a maximum of $180 million of new equity securities and to issue $200 million in debt securities at VUHI. The registration statement was declared effective on June 27, 2003. Subsequent to June 30, 2003, the Company initiated these transactions as more fully described below. Sources & Uses of Liquidity Operating Cash Flow The Company's primary and historical source of liquidity to fund working capital requirements has been cash generated from operations, which for the six months ended June 30, 2003 and 2002 was $170.5 million and $254.2 million, respectively. The decrease of $83.7 million is primarily the result of more favorable changes in working capital accounts occurring in 2002 due to a return to lower gas prices in that year, offset by increased earnings before non-cash charges in 2003. Financing Cash Flow Although working capital requirements are generally funded by cash flow from operations, the Company uses short-term borrowings to supplement working capital needs when accounts receivable balances are at their highest and gas storage is refilled. Additionally short-term borrowings are required for capital projects and investments until they are permanently financed. Cash flow required for financing activities of $83.6 million for the six months ended June 30, 2003 includes $49.8 million in payments to decrease borrowings outstanding and increased common stock dividends compared to 2002. In 2002, higher operating cash flow was used to repay $122.6 million in borrowings. Financing Transactions In January, 2003, the Company called the remaining $23.8 million of Indiana Gas' 9.375% private placement notes originally due in 2021. The total amount paid on redemption was $24.9 million. Pursuant to regulatory authority the premium paid was deferred as a regulatory asset. Also in January, 2003, other debt of Indiana Gas totaling $15.0 million and of SIGECO totaling $1.0 million was paid as scheduled. 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 the second quarter, the Company re-marketed those bonds on a long-term basis and has therefore reclassified them as long-term debt at June 30, 2003. Financing Activity Subsequent to June 30, 2003 With respect to the permanent financing strategy discussed above, the Company initiated the following transactions subsequent to June 30, 2003. Equity Issuance In August 2003, the Company completed a public offering of 6.5 million shares of its common stock, which was priced at $22.81 per share to yield total gross proceeds $148.3 million. The Company also has granted the underwriters a 30-day option to purchase up to an additional 975,000 shares of the Company's common stock at the public offering price to cover over-allotments, if any. The public offering of the shares closed on August 13, 2003 with net proceeds of approximately $143 million (excluding any proceeds from an over-allotment option). VUHI Debt Issuance Subsequent to June 30 2003, VUHI issued senior unsecured notes with an aggregate principal amount of $200 million in two $100 million tranches. The first tranche are 10-year notes due August 2013, with an interest rate of 5.25% priced at 99.746% to yield 5.28% to maturity (2013 Notes). The second tranche are 15-year notes due August 2018 with an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity (2018 Notes). The notes are jointly and severally guaranteed by the Company's three public utilities. In addition, they have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by the Company, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining scheduled payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in the indenture, plus 20 basis points for the 2013 Notes and 25 basis points for the 2018 Notes. Shortly before these issues, the Company entered into several treasury locks with a total notional amount of $150.0 million. Upon issuance of the debt, the treasury locks were settled resulting in the Company receiving $5.7 million. The value received will be amortized as a reduction of interest expense over the life of the issues. The net proceeds from the sale of the senior notes and settlement of related hedging arrangements approximated $203 million. SIGECO and Indiana Gas Debt Call In August 2003, the Company initiated steps to call two first mortgage bonds outstanding at SIGECO and a senior unsecured note outstanding at Indiana Gas. The first SIGECO 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. The Indiana Gas note has a principal amount of $13.5 million, an interest rate of 6.75%, was originally due in 2028, and may be redeemed at the 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. Investing Cash Flow Cash required for investing activities of $95.6 million for the six months ended June 30, 2003 includes $99.9 million of requirements for capital expenditures. Investing activities for 2002 were $103.0 million. The decrease occurring in 2003 principally results from collections of notes receivable and distributions by unconsolidated affiliates offset by additional capital expenditures, principally for the NOx project. Available Sources of Liquidity At June 30, 2003, the Company has $551 million of short-term borrowing capacity, including $371 million for the Utility Group and $180 million for the wholly owned Nonregulated Group and corporate operations, of which approximately $51 million is available for the Utility Group operations and approximately $109 million is available for the wholly owned Nonregulated Group and corporate operations. The availability of short-term borrowing is reduced by outstanding letters of credit totaling $2.5 million, collateralizing nonregulated activities. Effective January 1, 2003, the Company transferred assets which primarily supported the Utility Group's operations to VUHI which made available approximately $90 million of additional nonregulated and corporate capacity. Beginning in 2003, the Company began issuing new shares to satisfy dividend reinvestment plan requirements. During the six months ended June 30, 2003, new issues from stock plans added additional liquidity of approximately of $2.2 million, compared to 2002. Potential Uses of Liquidity Planned Capital Expenditures & Investments Investments in nonregulated unconsolidated affiliates and total company capital expenditures for the remainder of 2003 are estimated to be approximately $160 million. Ratings Triggers At June 30, 2003, $113.0 million of Vectren Capital's senior unsecured notes were subject to cross-default and ratings trigger provisions that would provide that the full balance outstanding is subject to prepayment if the ratings of Indiana Gas' or SIGECO's most senior securities declined to BBB/Baa2. In addition, accrued interest and a make whole amount based on the discounted value of the remaining payments due on the notes would also become payable. The credit rating of Indiana Gas' senior unsecured debt and SIGECO's secured debt remain one level and two levels, respectively, above the ratings trigger. Other Guarantees and Letters of Credit In the normal course of business, Vectren Corporation issues guarantees to third parties on behalf of its consolidated subsidiaries and unconsolidated affiliates. Such guarantees allow those subsidiaries and affiliates to execute transactions on more favorable terms than the subsidiary or affiliate could obtain without such a guarantee. Guarantees may include posted letters of credit, leasing guarantees, and performance guarantees. As of June 30, 2003, guarantees issued and outstanding on behalf of unconsolidated affiliates approximated $2 million. In addition, the Company has also issued a guarantee approximating $4 million related to the residual value of an operating lease that expires in 2006. Through June 30, 2003, the Company has not been called upon to satisfy any obligations pursuant to its guarantees. 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 The performance of projects undertaken by the Company's nonregulated businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the realization of Section 29 income tax credits and the Company's coal mining, gas marketing, and broadband strategies. o Direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit rating, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries. o Employee 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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to various business risks associated with commodity prices, interest rates, and counter-party credit. These financial exposures are monitored and managed by the Company as an integral part of its overall risk management program. The Company's risk management program includes, among other things, the use of derivatives to mitigate risk. The Company also executes derivative contracts in the normal course of operations while buying and selling commodities and other fungible goods to be used in operations and while optimizing generation assets. The Company does not execute derivative contracts it designates as trading. These risks are not significantly different from the information set forth in Item 7A Quantitative and Qualitative Disclosures About Market Risk included in the Vectren 2002 Form 10-K/A and is therefore not presented herein. 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 9 of its unaudited consolidated condensed financial statements included in Part 1 Item 1 Financial Statements regarding the Clean Air Act and related legal proceedings. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Vectren's Annual Meeting of Stockholders was held on May 14, 2003. At said Annual Meeting, the stockholders voted on the following four proposals: 1. The election of four directors of the company, each to serve for up to a three-year term or until their successors are duly qualified and elected: Director Votes For Abstentions ----------------------------- --------------------- --------------- John M. Dunn 59,872,414 1,109,441 Niel C. Ellerbrook 59,774,469 1,207,386 Anton H. George 59,878,818 1,103,037 Robert L. Koch II 59,984,444 997,411 The terms of office of John D. Engelbrecht, Lawrence A. Ferger, William G. Mays, J. Timothy McGinley, Richard P. Rechter, Ronald G. Reherman, Richard W. Shymanski, and Jean L. Wojtowicz will expire in 2004 or 2005. 2. The reappointment of Deloitte & Touche LLP (Deloitte) as the independent accountants for the Company and its subsidiaries for 2003: The stockholders approved Deloitte as the independent accountants by the following votes: Votes For Votes Against Abstentions Broker Non-Votes ----------------- ----------------- --------------- ------------------ 59,005,709 1,645,489 313,808 16,849 3. A proposal to expense stock options: The stockholders defeated the proposal by the following votes: Votes For Votes Against Abstentions Broker Non-Votes ----------------- ----------------- --------------- ------------------ 20,763,652 26,140,895 1,921,462 12,155,846 4. A proposal to use index-based options: The stockholders defeated the proposal by the following votes: Votes For Votes Against Abstentions Broker Non-Votes ----------------- ----------------- --------------- ------------------ 9,158,878 38,088,736 1,578,395 12,155,846 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 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, Vectren Corporation filed a Current Report on Form 8-K with respect to the release of financial information to the investment community regarding the Company's results of operations, 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, Vectren Corporation filed a Current Report on Form 8-K with respect a proposed agreement between Southern Indiana Gas and Electric Company, a wholly-owned subsidiary of Vectren Corporation, 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, Vectren Corporation filed a Current Report on Form 8-K to announce 1) on June 26, 2003, Vectren Utility Holdings, Inc.'s (VUHI) revolving credit facility was renewed and 2) on June 27, 2003, a registration statement, 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. VECTREN CORPORATION ------------------- 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)