-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, DFvag/VUmDNh/RSGkaHy3j8G2F0PVgE2MQuaMaQ3jwQjdDbDcAP8UPkOjgbJ4Q5Q 77Mv1OKYTSgal2QtPhAEug== 0001096385-02-000031.txt : 20020515 0001096385-02-000031.hdr.sgml : 20020515 20020515114914 ACCESSION NUMBER: 0001096385-02-000031 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20020331 FILED AS OF DATE: 20020515 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VECTREN UTILITY HOLDINGS INC CENTRAL INDEX KEY: 0001129542 STANDARD INDUSTRIAL CLASSIFICATION: WHOLESALE-PETROLEUM & PETROLEUM PRODUCTS (NO BULK STATIONS) [5172] IRS NUMBER: 352104850 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-16739 FILM NUMBER: 02649385 BUSINESS ADDRESS: STREET 1: 20 NW 4TH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 BUSINESS PHONE: 8124914000 10-Q 1 vuhi_10q-mar02.txt VECTREN UTILITY HOLDINGS 10Q FOR 1ST QTR 2002 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For quarterly period ended March 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------------- ----------------- Commission file number 1-16739 VECTREN UTILITY HOLDINGS, INC. ------------------------------- (Exact name of registrant as specified in its charter) INDIANA 35-2104850 ------------------------------- --------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 20 N.W. Fourth Street, Evansville, Indiana 47708 ---------------------------------------------------- (Address of principal executive offices and 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 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 10 May 1, 2002 - --------------------------------- ----------------- --------------------- Class Number of shares Date As of May 1, 2002, all shares outstanding of the Registrant's common stock were held by Vectren Corporation. Table of Contents Item Page Number Number PART I. FINANCIAL INFORMATION 1 Financial Statements (Unaudited) Vectren Utility Holdings, Inc. 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 5-12 2 Management's Discussion and Analysis of Results of Operations 13-22 and Financial Condition 3 Quantitative and Qualitative Disclosures About Market Risk 22-23 PART II. OTHER INFORMATION 1 Legal Proceedings 24 6 Exhibits and Reports on Form 8-K 24 Signatures 25 Definitions As discussed in this Form 10-Q, the abbreviations MMDth means millions of dekatherms, MMBTU means millions of British thermal units, and throughput means combined gas sales and gas transportation volumes. PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS (UNAUDITED) VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited - In millions) March 31, December 31, 2002 2001 ----------- ---------- ASSETS Utility Plant Original cost $ 2,927.6 $ 2,903.2 Less: Accumulated depreciation & amortization 1,326.3 1,308.2 -------- -------- Net utility plant 1,601.3 1,595.0 -------- -------- Current Assets Cash & cash equivalents 12.7 7.2 Accounts receivable-less reserves of $7.8 & $5.6, respectively 136.4 125.3 Receivables from other Vectren companies 42.7 58.2 Accrued unbilled revenues 72.6 78.3 Inventories 42.0 55.3 Recoverable fuel & natural gas costs 55.2 76.5 Prepayments & other current assets 41.6 95.8 -------- -------- Total current assets 403.2 496.6 -------- -------- Investments in unconsolidated affiliates 3.8 4.0 Other investments 12.5 12.2 Non-utility property-net 5.7 6.3 Goodwill-net 198.6 198.6 Regulatory assets 58.4 61.4 Other assets 17.8 17.3 -------- -------- TOTAL ASSETS $ 2,301.3 $ 2,391.4 ======== ======== The accompanying notes are an integral part of these consolidated condensed financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED CONDENSED BALANCE SHEETS (Unaudited - In millions) March 31, December 31, 2002 2001 -------- -------- LIABILITIES & SHAREHOLDER'S EQUITY Capitalization Common shareholder's equity Common stock (no par value) $ 385.7 $ 385.7 Retained earnings 351.7 329.0 Accumulated other comprehensive income (1.7) (1.7) -------- -------- Total common shareholder's equity 735.7 713.0 -------- -------- Cumulative Redeemable Preferred Stock of Subsidiary 0.3 0.5 Long-term debt- net of current maturities and debt subject to tender 899.8 900.9 -------- -------- Total capitalization 1,635.8 1,614.4 -------- -------- Commitments & Contingencies (Notes 6-8) Current Liabilities Accounts payable 50.6 79.0 Accounts payable to affiliated companies 46.9 36.5 Payables to other Vectren companies 7.2 11.5 Accrued liabilities 138.8 97.5 Short-term borrowings 140.8 274.2 Long-term debt subject to tender 11.5 11.5 Current maturities of long-term debt 1.3 1.3 -------- -------- Total current liabilities 397.1 511.5 -------- -------- Deferred Income Taxes & Other Liabilities Deferred income taxes 173.6 171.8 Deferred credits & other liabilities 94.8 93.7 -------- -------- Total deferred income taxes & other liabilities 268.4 265.5 -------- -------- TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $2,301.3 $2,391.4 ======== ======== The accompanying notes are an integral part of these consolidated condensed financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED CONDENSED STATEMENTS OF INCOME (Unaudited - In millions) Three Months Ended March 31, -------------------- 2002 2001 -------- -------- OPERATING REVENUES Gas revenues $ 357.1 $ 523.7 Electric revenues 126.8 88.2 ------ ------ Total operating revenues 483.9 611.9 ------ ------ COST OF OPERATING REVENUES Cost of gas sold 230.4 404.1 Fuel for electric generation 17.8 18.0 Purchased electric energy 59.8 13.2 ------ ------ Total cost of operating revenues 308.0 435.3 ------ ------ TOTAL OPERATING MARGIN 175.9 176.6 OPERATING EXPENSES Other operating 55.8 61.5 Merger & integration costs - 1.0 Depreciation & amortization 23.6 24.8 Income taxes 22.3 17.8 Taxes other than income taxes 17.9 19.1 ------ ------ Total operating expenses 119.6 124.2 ------ ------ OPERATING INCOME 56.3 52.4 Equity in earnings of unconsolidated affiliates (0.6) - Other income - net 1.8 (0.9) Interest expense 16.9 19.5 Preferred dividend requirement of subsidiary - 0.2 ------ ------ INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 40.6 31.8 ------ ------ Cumulative effect of change in accounting principle principle - net of tax - 3.9 ------ ------ NET INCOME $ 40.6 $ 35.7 ====== ====== The accompanying notes are an integral part of these consolidated condensed financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (Unaudited - In millions) Three Months Ended March 31, ------------------ 2002 2001 ------- ------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 40.6 $ 35.7 Adjustments to reconcile net income to cash from operating activities: Depreciation & amortization 23.6 24.8 Equity in losses of unconsolidated affiliates 0.6 - Deferred income taxes & investment tax credits 2.9 10.2 Net unrealized loss (gain) on derivative instruments, including cumulative effect of change in accounting principle 3.0 (11.8) Other non-cash charges- net 4.0 3.0 Changes in assets and liabilities: Accounts receivable, including to Vectren companies & accrued unbilled revenue 6.1 55.7 Inventories 13.3 63.7 Recoverable fuel & natural gas costs 21.3 (15.1) Prepayments & other current assets 60.9 30.2 Regulatory assets 2.6 (0.3) Accounts payable, including to Vectren companies & affiliated companies (22.3) (147.2) Accrued liabilities 29.9 14.1 Other noncurrent assets & liabilities (1.0) (7.7) ------ ------ Total adjustments 144.9 19.6 ------ ------ Net cash flows from operating activities 185.5 55.3 ------ ------ CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES Proceeds from additional capital contribution - 129.4 Requirements for: Dividends on common stock (17.9) (16.5) Retirement of preferred stock of subsidiary (0.2) (0.2) Retirement of long-term debt (1.3) (6.8) Dividends on preferred stock of subsidiary - (0.2) Net change in short-term borrowings (133.4) (131.6) ------ ------ Net cash flows (required for) financing activities (152.8) (25.9) ------ ------ CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES Capital expenditures (26.8) (29.9) Unconsolidated affiliate investments (0.4) (3.0) Other investing proceeds - 4.8 ------ ------ Net cash flows (required for) investing activities (27.2) (28.1) ------ ------ Net increase in cash & cash equivalents 5.5 1.3 Cash & cash equivalents at beginning of period 7.2 2.2 ------ ------ Cash & cash equivalents at end of period $ 12.7 $ 3.5 ====== ====== The accompanying notes are an integral part of these consolidated condensed financial statements. VECTREN UTILITY HOLDINGS, INC. AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (UNAUDITED) 1. Organization and Nature of Operations Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation, was formed on March 31, 2000 to serve as the intermediate holding company for Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (SIGCORP), and the Ohio operations. Indiana Gas provides natural gas distribution and transportation services to a diversified customer base in 311 communities in 49 of Indiana's 92 counties. SIGECO provides electric generation, transmission, and distribution services to Evansville, Indiana, and 74 other communities in 8 counties in southwestern Indiana and participates in the wholesale power market. SIGECO also provides natural gas distribution and transportation services to Evansville, Indiana, and 64 communities in 10 counties in southwestern Indiana. The Ohio operations, owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc., a wholly owned subsidiary, (53 % ownership) and Indiana Gas (47 % ownership), provide natural gas distribution and transportation services to Dayton, Ohio, and 87 other communities in 17 counties in west central Ohio. The Ohio operations were acquired from the Dayton Power & Light Company on October 31, 2000. Vectren, an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company was organized on June 10, 1999 solely for the purpose of effecting the merger of Indiana Energy and SIGCORP. On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with Accounting Principles Board (APB) Opinion No. 16 "Business Combinations" (APB 16). Therefore, the reorganization of Indiana Gas and SIGECO into subsidiaries of VUHI has been accounted for as a combination of entities under common control. Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935. 2. Basis of Presentation The interim 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 footnote 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, 2001, filed on Form 10-K. 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. Certain reclassifications have been made to prior period financial statements to conform with the current year classification. These reclassifications have no impact on previously reported net income. 3. Impact of Recently Issued Accounting Guidance SFAS 142 In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company adopted the provisions of SFAS 142, as required on January 1, 2002. SFAS 142 changed the accounting for goodwill from an amortization approach to an impairment-only approach. Thus, amortization of goodwill that is not included as an allowable cost for rate-making purposes ceased upon adoption of the statement. This includes goodwill recorded in past business combinations, such as the Company's acquisition of the Ohio operations. Goodwill is to be tested for impairment at a reporting unit level at least annually. SFAS 142 also requires the initial impairment review of all goodwill within six months of the adoption date. The impairment review consists of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss would be recognized. Results of the initial impairment review are to be treated as a change in accounting principle in accordance with APB Opinion No. 20 "Accounting Changes." An impairment loss recognized as a result of an impairment test occurring after the initial impairment review is to be reported as a part of operations. SFAS 142 also changed certain aspects of accounting for intangible assets; however, the Company does not have any significant intangible assets. As required by SFAS 142, amortization of goodwill relating to the acquisition of the Ohio operations, which approximates $5.0 million per year, ceased on January 1, 2002. Initial impairment reviews to be performed within six months of adoption of SFAS 142 have not been completed, but no impairment is expected. SFAS 144 In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting model for all impaired long-lived assets and long-lived assets to be disposed of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business." This new accounting model retains the framework of SFAS 121 and requires that those impaired long-lived assets and long-lived assets to be disposed of be measured at the lower of carrying amount or fair value (less cost to sell for assets to be disposed of), whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations are no longer measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The adoption of SFAS 144 on January 1, 2002 did not materially impact operations. 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. SFAS 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently evaluating the impact that SFAS 143 will have on its operations. 4. Comprehensive Income Comprehensive income consists of the following: Three Months Ended March 31, ------------------- In millions 2002 2001 ------- ------- Net income $ 40.6 $ 35.7 Minimum pension liability adjustment and other- net of tax - (0.9) ----- ----- Total comprehensive income $ 40.6 $ 34.8 ===== ===== 5. Transactions with Other Vectren Companies Support Services & Purchases Vectren and certain subsidiaries of Vectren have provided corporate, general and administrative services to the Company including legal, finance, tax, risk management, and human resources. The costs have been allocated to the Company using various allocators, primarily number of employees, number of customers and/or revenues. Management believes that the allocation methodology is reasonable and approximates the costs that would have been incurred had the Company secured those services on a stand-alone basis. For the three months ended March 31, 2002 and 2001, amounts billed by other wholly owned subsidiaries of Vectren to the Company were $34.9 million and $22.7 million, respectively. Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases fuel used for electric generation. Amounts paid for such purchases for the three months ended March 31, 2002 and 2001 were $13.2 million and $10.4 million, respectively. Cash Management & Borrowing Arrangements The Company participates in a centralized cash management program with Vectren, other wholly owned subsidiaries, and banks which permits funding of checks as they are presented. Vectren's three operating utility companies, SIGECO, Indiana Gas, and VEDO are guarantors of VUHI's $350.0 million commercial paper program, of which $140.0 million is outstanding at March 31, 2002 and VUHI's $350.0 million unsecured senior notes outstanding at March 31, 2002. These guarantees are full and unconditional and joint and several. VUHI has no significant independent assets or operations other than the assets and operations of these operating utility companies. 6. Transactions with Vectren Affiliates ProLiance Energy, LLC (ProLiance), a nonregulated, energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), began providing natural gas and related services to Indiana Gas, Citizens Gas, and others in April 1996. ProLiance also provides services to the Ohio operations. Integration of SIGCORP Energy Services, LLC and ProLiance Energy, LLC In February 2002, Vectren announced its intention to integrate the operations of its wholly owned subsidiary SIGCORP Energy Services, LLC (SES) with ProLiance. SES provides natural gas and related services to SIGECO and others. In exchange for the contribution of SES' net assets and additional cash, Vectren's allocable share of ProLiance's prospective profits and losses is expected to increase from the Company's current 52.5% profit and loss share. However, governance, including voting rights, will remain at 50% for each member. As governance of ProLiance remains equal between the members, Vectren will continue to account for its investment in ProLiance using the equity method of accounting. The financial impact of the transaction, which is expected to be completed later in 2002, is not expected to be material. Regulatory Matters The sale of gas and provision of other services to Indiana Gas by ProLiance is subject to regulatory review through the quarterly gas cost adjustment (GCA) process administered by the IURC. On September 12, 1997, the IURC issued a decision finding the gas supply and portfolio administration agreements between ProLiance and Indiana Gas and ProLiance and Citizens Gas to be consistent with the public interest and that ProLiance is not subject to regulation by the IURC as a public utility. The IURC's decision reflected the significant gas cost savings to customers obtained through ProLiance's services and suggested that all material provisions of the agreements between ProLiance and the utilities are reasonable. Nevertheless, with respect to the pricing of gas commodity purchased from ProLiance, the price paid by ProLiance to the utilities for the prospect of using pipeline entitlements if and when they are not required to serve the utilities' firm customers, and the pricing of fees paid by the utilities to ProLiance for portfolio administration services, the IURC concluded that additional review in the GCA process would be appropriate and directed that these matters be considered further in the pending, consolidated GCA proceeding involving Indiana Gas and Citizens Gas. In 2001, the IURC commenced processing the GCA proceeding regarding the three pricing issues. The IURC indicated that it would consider the prospective relationship of ProLiance with the utilities in this proceeding. On April 23, 2002, Indiana Gas and Citizens Gas, together with the Office of Utility Consumer Counselor and other consumer parties entered into and filed with the IURC an agreement in principle setting forth the terms for resolution of all pending regulatory issues related to ProLiance. The parties intend to submit for IURC approval a final settlement no later than June 3, 2002. If approved by the IURC, the pending GCA proceeding will be concluded. Transactions with ProLiance Purchases from ProLiance for resale and for injections into storage for the three months ended March 31, 2002 and 2001 totaled $127.8 million and $268.5 million, respectively. Amounts owed to ProLiance at March 31, 2002 and December 31, 2001 for such purchases were $45.4 million and $36.1 million, respectively, and are included in accounts payable to affiliated companies. Amounts charged by ProLiance for capacity and storage services are market based. 7. Commitments & Contingencies The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 8 regarding environmental matters and Note 6 regarding ProLiance Energy, LLC. 8. Environmental Matters Clean Air Act NOx SIP Call Matter The Clean Air Act (the Act) requires each state to adopt a State Implementation Plan (SIP) to attain and maintain National Ambient Air Quality Standards (NAAQS) for a number of pollutants, including ozone. If the United States Environmental Protection Agency (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 1998 and 1999. 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 (Warrick), and A.B. Brown Generating Station Unit 2 (A.B. Brown). 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 issued an order that (1) approves the Company's proposed project to achieve environmental compliance by investing in clean coal technology, (2) approves the Company's cost estimate for the construction, subject to periodic review of the actual costs incurred, and (3) approves a mechanism whereby, prior to an electric base rate case, the Company may recover a return on its capital costs for the project, at its overall cost of capital, including a return on equity. Based on the level of system-wide emissions reductions required and the control technology utilized to achieve the reductions, the current estimated construction cost ranges from $175.0 million to $195.0 million and is expected to be expended during the 2001-2004 period. Through March 31, 2002, $30.1 million has been expended. After the equipment is installed and operational, related additional annual operation and maintenance expenses are estimated to be between $8.0 million and $10.0 million. The Company expects the Culley, Warrick and A.B. Brown SCR systems to be operational by the compliance date. Installation of SCR technology at these stations 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. The USEPA alleges that, beginning in 1992, SIGECO violated the Act by: (1) making modifications to its Culley Generating Station in Yankeetown, Indiana without obtaining required permits; (2) making major modifications to the Culley Generating Station without installing the best available emission control technology; and (3) failing to notify the USEPA of the modifications. In addition, the lawsuit alleges that the modifications to the Culley Generating Station required SIGECO to begin complying with federal new source performance standards at its Culley Unit 3. SIGECO believes it performed only maintenance, repair and replacement activities at the Culley Generating Station, as allowed under the Act. Because proper maintenance does not require permits, application of the best available control technology, notice to the USEPA, or compliance with new source performance standards, SIGECO believes that the lawsuit is without merit, and intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA has voluntarily dismissed nearly half of the claims brought in its original compliant. The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per violation. The lawsuit does not specify the number of days or violations the USEPA believes occurred. The lawsuit also seeks a court order requiring SIGECO to install the best available emissions technology at the Culley Generating Station. If the USEPA were successful in obtaining an order, SIGECO estimates that it would incur capital costs of approximately $40.0 million to $50.0 million to comply with the order. As a result of the NOx SIP call issue, the majority of the $40.0 million to $50.0 million for best available emissions technology at Culley Generating Station is included in the $175.0 million to $195.0 million cost range previously discussed. The USEPA has also issued an administrative notice of violation to SIGECO making the same allegations, but alleging that violations began in 1977. While it is possible that SIGECO could be subjected to criminal penalties if the Culley Generating Station continues to operate without complying with the permitting requirements of new source review and the allegations are determined by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA and the electric utility industry have a bonafide dispute over the proper interpretation of the Act. Accordingly, the Company has recorded no accrual and the plant continues to operate while the matter is being decided. Information Request On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested, and no further action has occurred. Manufactured Gas Plants In the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites. Indiana Gas has identified the existence, location and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the Indiana Department of Environmental Management (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 expert 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 accrued 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 its $20.4 million accrual. 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. 9. Energy Marketing Activities The Company enters into forward and option contracts in order to maximize short-term movement in electricity prices. These contracts are generally non-asset backed "buy-sell" transactions that are short-term in nature and expose the Company to limited market risk. The Company has designated these activities as "trading" activities. Commodity contracts designated as "trading" are generally settled net with the counter-party and are accounted for at market value. As of March 31, 2002, these "trading" contracts had a net liability value of $1.9 million. The Company also enters into transactions "other-than-trading" that are primarily asset-backed transactions. The net asset value of these "other-than-trading" contracts was $2.1 million at March 31, 2002. Contracts recorded at market value are recorded as current or noncurrent assets or liabilities in the consolidated condensed balance sheets depending on their value and on when the contracts are expected to be settled. Changes in market value are recorded in purchased electric energy in the consolidated condensed statements of income. Market value is determined using quoted market prices from independent sources or other valuation techniques. Forward sale contracts, premiums received for written options, and proceeds received from exercised options are recorded when settled as electric revenues in the consolidated condensed statements of income. Forward purchase contracts, premiums paid for purchased options, and proceeds paid for exercising options are recorded when settled in purchased electric energy in the consolidated condensed statements of income. Contracts with counter-parties subject to master netting arrangements are presented net in the consolidated condensed balance sheets. All "trading" and "other-than-trading" contracts at March 31, 2002 totaled $11.8 million of prepayments and other current assets and $11.6 million of accrued liabilities, compared to $5.1 million of prepayments and other current assets and $1.9 million of accrued liabilities at December 31, 2001. The change in the net value of "trading" and "other-than-trading" contracts to $0.2 million from $3.2 million resulted in an unrealized loss of $3.0 million for the three months ended March 31, 2002. 10. Segment Reporting There were two operating segments during 2001: (1) Gas Utility Services and (2) Electric Utility Services. The Gas Utility Services segment includes the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas distribution business and provides natural gas distribution and transportation services in nearly two-thirds of Indiana and west central Ohio. The Electric Utility Services segment includes the operations of SIGECO's power generating and marketing operations, and electric transmission and distribution services, which provides electricity to primarily southwestern Indiana. The following tables provide information about business segments. Three Months Ended March 31, ------------------------ In millions 2002 2001 - ----------- -------- -------- Operating Revenues Gas Utility Services $ 357.1 $ 523.7 Electric Utility Services 126.8 88.2 ------ ------ Total operating revenues $ 483.9 $ 611.9 ====== ====== Net Income Gas Utility Services $ 32.9 $ 18.8 Electric Utility Services 7.7 16.9 ----- ----- Net income $ 40.6 $ 35.7 ===== ===== March 31, December 31, In millions 2002 2001 - ----------- ---------- ---------- Identifiable Assets Gas Utility Services $ 1,485.2 $ 1,580.2 Electric Utility Services 816.1 811.2 -------- -------- Total identifiable assets $ 2,301.3 $ 2,391.4 ======== ======== ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Description of the Business Vectren Utility Holdings, Inc. (VUHI or the Company), an Indiana corporation, was formed on March 31, 2000 to serve as the intermediate holding company for Vectren Corporation's (Vectren) three operating public utilities, Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, Inc. (Indiana Energy), Southern Indiana Gas and Electric Company (SIGECO), formerly a wholly owned subsidiary of SIGCORP, Inc. (SIGCORP), and the Ohio operations. Indiana Gas provides natural gas distribution and transportation services to a diversified customer base in 311 communities in 49 of Indiana's 92 counties. SIGECO provides electric generation, transmission, and distribution services to Evansville, Indiana, and 74 other communities in 8 counties in southwestern Indiana and participates in the wholesale power market. SIGECO also provides natural gas distribution and transportation services to Evansville, Indiana, and 64 communities in 10 counties in southwestern Indiana. The Ohio operations, owned as a tenancy in common by Vectren Energy Delivery of Ohio, Inc., a wholly owned subsidiary, (53 % ownership) and Indiana Gas (47 % ownership), provide natural gas distribution and transportation services to Dayton, Ohio, and 87 other communities in 17 counties in west central Ohio. The Ohio operations were acquired from the Dayton Power & Light Company on October 31, 2000. Vectren, an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. The Company was organized on June 10, 1999 solely for the purpose of effecting the merger of Indiana Energy and SIGCORP. On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with Accounting Principles Board (APB) Opinion No. 16 "Business Combinations" (APB 16). Therefore, the reorganization of Indiana Gas and SIGECO into subsidiaries of VUHI has been accounted for as a combination of entities under common control. 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. Results of Operations The Company's operations are comprised of its Gas Utility Services and Electric Utility Services segments. The Gas Utility Services segment includes the operations of Indiana Gas, the Ohio operations, and SIGECO's natural gas distribution business and provides natural gas distribution and transportation services to nearly two-thirds of Indiana and west central Ohio. The Electric Utility Services segment includes SIGECO's power supply operations, power marketing operations, and electric transmission and distribution services, which operate and maintain six coal-fired electric power plants and five gas-fired peaking units with a total of 1,271 megawatts of generating capacity to provide electricity to primarily southwestern Indiana. The results of operations for the three months ended March 31, 2002 and 2001 are as follows: In millions 2002 2001 - ----------- ------ ------ Net income, as reported $ 40.6 $ 35.7 Merger and integration costs-net of tax - 2.3 Cumulative effect of change in accounting principle - net of tax - (3.9) ----- ----- Net income before nonrecurring items $ 40.6 $ 34.1 ===== ===== Net Income Regulated utility operations contributed net income of $40.6 million for the three months ended March 31, 2002 compared to $35.7 million for the same period in 2001. The results for regulated operations were primarily driven by merger synergies, a return to lower gas prices and the related reduction in costs incurred in 2001, and the completion of merger activities and related costs. These increases were offset somewhat by fluctuations in fair value of certain power marketing contracts and the effects of weather. Merger & Integration Costs For the three months ended March 31, 2001, $1.0 million was expensed related to the 2000 merger forming Vectren. These costs were primarily for employee relocation, travel, and consulting fees. As a result of merger and integration activities, management retired certain information systems in 2001. Accordingly, the useful lives of these assets were shortened to reflect this decision. These information system assets are owned by a wholly owned subsidiary of Vectren, and the fees allocated by the subsidiary for the use of these systems by the Company are reflected in other operating expenses in the accompanying condensed financial statements. As a result of the shortened useful lives, additional fees were incurred by the Company resulting in additional other operating expense of $2.7 million for the three months ended March 31, 2001. In total, for the three months ended March 31, 2001, merger and integration costs totaled $3.7 million ($2.3 million after tax). Merger and integration activities resulting from the 2000 merger were completed in 2001. Impact of SFAS 133 on Power Marketing Operations For the three months ended March 31, 2002, net income has decreased $9.2 million when compared to the prior year due to the adoption and continued application of Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) which was adopted on January 1, 2001. The total impact of SFAS 133 for the three months ended March 31, 2002 is a loss of $3.0 million ($1.9 million after tax), which is included in purchased electric energy. This compares to a gain of $11.8 million ($7.3 million after tax) for the three months ended March 31, 2001. This total includes the cumulative effect of change in accounting principle of $6.6 million ($3.9 million after tax) and unrealized gains totaling $5.5 million ($3.4 million after tax) arising from the change in market value from the date of adoption through March 31, 2001, which is included in purchased electric energy. New Accounting Principles SFAS 142 In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). The Company adopted the provisions of SFAS 142, as required on January 1, 2002. SFAS 142 changed the accounting for goodwill from an amortization approach to an impairment-only approach. Thus, amortization of goodwill that is not included as an allowable cost for rate-making purposes ceased upon adoption of the statement. This includes goodwill recorded in past business combinations, such as the Company's acquisition of the Ohio operations. Goodwill is to be tested for impairment at a reporting unit level at least annually. SFAS 142 also requires the initial impairment review of all goodwill within six months of the adoption date. The impairment review consists of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss would be recognized. Results of the initial impairment review are to be treated as a change in accounting principle in accordance with APB Opinion No. 20 "Accounting Changes." An impairment loss recognized as a result of an impairment test occurring after the initial impairment review is to be reported as a part of operations. SFAS 142 also changed certain aspects of accounting for intangible assets; however, the Company does not have any significant intangible assets. As required by SFAS 142, amortization of goodwill relating to the acquisition of the Ohio operations, which approximates $5.0 million per year ($1.3 million per quarter), ceased on January 1, 2002. Initial impairment reviews to be performed within six months of adoption of SFAS 142 have not been completed, but no impairment is expected. SFAS 144 In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 develops one accounting model for all impaired long-lived assets and long-lived assets to be disposed of. SFAS 144 replaces the existing authoritative guidance in FASB Statement No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and certain aspects of APB Opinion No. 30, "Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business." This new accounting model retains the framework of SFAS 121 and requires that those impaired long-lived assets and long-lived assets to be disposed of be measured at the lower of carrying amount or fair value (less cost to sell for assets to be disposed of), whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations are no longer measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The adoption of SFAS 144 on January 1, 2002 did not materially impact operations. 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 the 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. SFAS 143 is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently evaluating the impact that SFAS 143 will have on its operations. Significant Fluctuations Utility Margin (Operating Revenues Less Cost of Gas Sold, Fuel for Electric Generation, & Purchased Electric Energy) - --------------------------------------------------------------------------- Gas Utility Margin Gas Utility margin for the three months ended March 31, 2002 of $126.7 million increased $7.1 million, or 6%, compared to 2001. The increase is primarily due to the return of volumes lost in the prior year due to the effects of the higher gas costs and the decreased cost of unaccounted for gas. Gas Utility margin was also favorably impacted by rate recovery of excise taxes in Ohio effective July 1, 2001 and an increase in the Ohio Percentage of Income Payment Plan (PIPP) rider, as well as customer growth. These favorable impacts were offset somewhat by weather 10% warmer than the prior year and 12% warmer than normal. The increased volumes attributed to lower gas costs and the effects of warmer weather resulted in an overall 6% decrease in total throughput from 82.7 MMDth to 77.9 MMDth. Total cost of gas sold was $230.4 million for the three months ended March 31, 2002 and $404.1 million in 2001. Total cost of gas sold decreased $173.7 million, or 43%, during 2002 compared to 2001, primarily due to a return to lower gas prices. The total average cost per dekatherm of gas purchased for the three months ended March 31, 2002 was $4.47 compared to $7.87 for the same period in 2001. Electric Utility Margin Electric Utility margin for the three months ended March 31, 2002 of $49.2 million decreased $7.8 million, or 14%, from 2001 primarily due to reductions in margin to reflect wholesale power marketing purchase and sale contracts at current market values. The decrease in margin from quarter to quarter was $8.5 million. This decrease was offset by increased margins from retail sales. Margin from retail sales increased $3.3 million, or 8%, over the previous year. The increase in retail margin is attributable to a 2% increase in megawatt hours sold, consistent costs for fuel and purchased power used for generation, and a cash return on NOx compliance expenditures. The Company enters into forward and option contracts in order to maximize short-term movement in electricity prices. These contracts are generally non-asset backed "buy-sell" transactions that are short-term in nature and expose the Company to limited market risk. The Company has designated these activities as "trading" activities. The Company also enters into asset-backed transactions that are generally longer term in nature. As a result of increased "trading" and "other-than-trading" activity, purchased electric energy has increased $46.6 million during the three months ended March 31, 2002 compared to 2001. These activities increased wholesale revenues from $30.0 million to $64.9 million and megawatt hours sold into the wholesale market from 0.9 million to 2.6 million. Operating Expenses (excluding Cost of Gas Sold, Fuel for Electric Generation, & Purchased Electric Energy) - ------------------------------------------------------------------------------- Other Operating Other operating expenses decreased $5.7 million for the three months ended March 31, 2002 compared to the prior year. The decrease results from lower charges for the use of corporate assets related to those assets which had useful lives shortened as a result of the merger and merger synergies. Depreciation & Amortization Depreciation and amortization decreased $1.2 million for the three months ended March 31, 2002 resulting from the discontinuance of goodwill amortization as required under SFAS 142, offset somewhat by depreciation of plant additions. Income Tax Expense Federal and state income taxes related to utility operations increased $4.5 million for the three months ended March 31, 2002 compared to the prior year due primarily to higher pre-tax earnings offset somewhat by a small decrease in the effective tax rate. Taxes Other Than Income Taxes Taxes other than income taxes decreased $1.2 million for the three months ended March 31, 2002 compared to the prior year due to a decrease in gross receipts and excises taxes as a result of lower sales volumes and gas prices. Other Income, Net Utility other income, net increased $2.7 million for the three months ended March 31, 2002 compared to the prior year. In 2001, contributions were made to low income heating assistance programs to assist customers with their increased utility bills reflecting higher gas costs. Interest Expense Interest expense decreased $2.6 million for the three months ended March 31, 2002, when compared to the prior year. The decrease results from lower interest rates on variable rate debt and lower outstanding balances. The reduced debt outstanding is due primarily to decreased working capital requirements resulting from a return to lower gas prices. 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 United States Environmental Protection Agency (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 1998 and 1999. 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 (Warrick), and A.B. Brown Generating Station Unit 2 (A.B. Brown). 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 issued an order that (1) approves the Company's proposed project to achieve environmental compliance by investing in clean coal technology, (2) approves the Company's cost estimate for the construction, subject to periodic review of the actual costs incurred, and (3) approves a mechanism whereby, prior to an electric base rate case, the Company may recover a return on its capital costs for the project, at its overall cost of capital, including a return on equity. Based on the level of system-wide emissions reductions required and the control technology utilized to achieve the reductions, the current estimated construction cost ranges from $175.0 million to $195.0 million and is expected to be expended during the 2001-2004 period. Through March 31, 2002, $30.1 million has been expended. After the equipment is installed and operational, related additional annual operation and maintenance expenses are estimated to be between $8.0 million and $10.0 million. The Company expects the Culley, Warrick and A.B. Brown SCR systems to be operational by the compliance date. Installation of SCR technology at these stations 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. The USEPA alleges that, beginning in 1992, SIGECO violated the Act by: (1) making modifications to its Culley Generating Station in Yankeetown, Indiana without obtaining required permits; (2) making major modifications to the Culley Generating Station without installing the best available emission control technology; and (3) failing to notify the USEPA of the modifications. In addition, the lawsuit alleges that the modifications to the Culley Generating Station required SIGECO to begin complying with federal new source performance standards at its Culley Unit 3. SIGECO believes it performed only maintenance, repair and replacement activities at the Culley Generating Station, as allowed under the Act. Because proper maintenance does not require permits, application of the best available control technology, notice to the USEPA, or compliance with new source performance standards, SIGECO believes that the lawsuit is without merit, and intends to vigorously defend itself. Since the filing of this lawsuit, the USEPA has voluntarily dismissed nearly half of the claims brought in its original compliant. The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per violation. The lawsuit does not specify the number of days or violations the USEPA believes occurred. The lawsuit also seeks a court order requiring SIGECO to install the best available emissions technology at the Culley Generating Station. If the USEPA were successful in obtaining an order, SIGECO estimates that it would incur capital costs of approximately $40.0 million to $50.0 million to comply with the order. As a result of the NOx SIP call issue, the majority of the $40.0 million to $50.0 million for best available emissions technology at Culley Generating Station is included in the $175.0 million to $195.0 million cost range previously discussed. The USEPA has also issued an administrative notice of violation to SIGECO making the same allegations, but alleging that violations began in 1977. While it is possible that SIGECO could be subjected to criminal penalties if the Culley Generating Station continues to operate without complying with the permitting requirements of new source review and the allegations are determined by a court to be valid, SIGECO believes such penalties are unlikely as the USEPA and the electric utility industry have a bonafide dispute over the proper interpretation of the Act. Accordingly, the Company has recorded no accrual and the plant continues to operate while the matter is being decided. Information Request On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested, and no further action has occurred. Manufactured Gas Plants In the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites. Indiana Gas has identified the existence, location and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the Indiana Department of Environmental Management (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 expert 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 accrued 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 its $20.4 million accrual. 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. Regulatory Matters ProLiance Energy, LLC (ProLiance), a nonregulated, energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), began providing natural gas and related services to Indiana Gas, Citizens Gas, and others in April 1996. ProLiance also provides services to the Ohio operations. The sale of gas and provision of other services to Indiana Gas by ProLiance is subject to regulatory review through the quarterly gas cost adjustment (GCA) process administered by the IURC. On September 12, 1997, the IURC issued a decision finding the gas supply and portfolio administration agreements between ProLiance and Indiana Gas and ProLiance and Citizens Gas to be consistent with the public interest and that ProLiance is not subject to regulation by the IURC as a public utility. The IURC's decision reflected the significant gas cost savings to customers obtained through ProLiance's services and suggested that all material provisions of the agreements between ProLiance and the utilities are reasonable. Nevertheless, with respect to the pricing of gas commodity purchased from ProLiance, the price paid by ProLiance to the utilities for the prospect of using pipeline entitlements if and when they are not required to serve the utilities' firm customers, and the pricing of fees paid by the utilities to ProLiance for portfolio administration services, the IURC concluded that additional review in the GCA process would be appropriate and directed that these matters be considered further in the pending, consolidated GCA proceeding involving Indiana Gas and Citizens Gas. In 2001, the IURC commenced processing the GCA proceeding regarding the three pricing issues. The IURC indicated that it would consider the prospective relationship of ProLiance with the utilities in this proceeding. On April 23, 2002, Indiana Gas and Citizens Gas, together with the Office of Utility Consumer Counselor and other consumer parties entered into and filed with the IURC an agreement in principle setting forth the terms for resolution of all pending regulatory issues related to ProLiance. The parties intend to submit for IURC approval a final settlement no later than June 3, 2002. If approved by the IURC, the pending GCA proceeding will be concluded. Financial Condition The Company's equity capitalization objective is 40-55% of total capitalization. This objective may have varied, and will vary, depending on particular business opportunities and seasonal factors that affect the Company's operation. The Company's equity component was 45% and 44% of total capitalization, including current maturities of long-term debt and long-term debt subject to tender, at March 31, 2002 and December 31, 2001, respectively. Short-term cash working capital is required primarily to finance customer accounts receivable, unbilled utility revenues resulting from cycle billing, gas in underground storage, prepaid gas delivery services, capital expenditures, and investments until permanently financed. Short-term borrowings tend to be greatest during the summer when accounts receivable and unbilled utility revenues related to electricity are highest and gas storage facilities are being refilled. The Company expects the majority of its capital expenditures and debt security redemptions to be provided by internally generated funds; however, additional financing may be required due to the possible early redemption of debt at Indiana Gas and significant capital expenditures for NOx compliance equipment at SIGECO. VUHI's and Indiana Gas' credit ratings on outstanding senior unsecured debt at March 31, 2002 are A-/A2 as rated by Standard and Poor's and Moody's, respectively. SIGECO's credit ratings on outstanding secured debt at March 31, 2002 are A-/A1. VUHI's commercial paper has a credit rating of A-2/P-1. Cash Flow From Operations The Company's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled approximately $185.5 million and $55.3 million for the three months ended March 31, 2002 and 2001, respectively. Cash flow from operations increased during the three months ended March 31, 2002 compared to 2001 by $130.2 million due primarily to favorable changes in working capital accounts due to a return to lower gas prices and increased earnings before non-cash charges. Financing Activities Sources & Uses of Liquidity At March 31, 2002, the Company has $360.0 million of short-term borrowing capacity, of which $219.2 million is available. During the three months ended March 31, 2002, $1.3 million of long-term debt was paid as scheduled, and in June and July of 2002, put provisions on $5.0 million and $6.5 million, respectively, of long-term debt become exercisable. At March 31, 2002, $140.0 million of commercial paper was supported by the VUHI facility whereby VUHI must maintain a rating of better than BB+/Ba1. Financing Cash Flow Cash flow required for financing activities of $152.8 million for the three months ended March 31, 2002 includes $134.7 million of reductions in net borrowings and $17.9 million in common stock dividends. In the prior year, $129.4 million of common stock was issued and used to repay short-term borrowings. Other Financing Transactions In January 2002, the Company redeemed 1,160 shares of SIGECO's 8.5% preferred stock per its stated terms of $100 per share, plus accrued and unpaid dividends. Prior to the redemption, there were 4,597 shares outstanding. Capital Expenditures & Other Investment Activities Cash required for investing activities of $27.2 million for the three months ended March 31, 2002 includes $26.8 million of requirements for capital expenditures. Investing activities for the three months ended March 31, 2001 were comparable at $28.1 million. Planned Capital Expenditures New construction, normal system maintenance and improvements, and information technology investments needed to provide service to a growing customer base will continue to require substantial expenditures. Capital expenditures investments for the remainder of 2002 are estimated at $123.4 million. 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, including, but not limited to Vectren's realization of net merger savings, are forward-looking statements. Such statements are based on management's beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words "believe," "anticipate," "endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal," and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause the Company's actual results to differ materially from those contemplated in any forward-looking statements included, among others, the following: |X| 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. |X| Increased competition in the energy environment including effects of industry restructuring and unbundling. |X| 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. |X| 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 natural gas transmission, gathering and processing, and similar entities with regulatory oversight. |X| Economic conditions including the effects of an economic downturn, inflation rates, and monetary fluctuations. |X| 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. |X| Availability or cost of capital, resulting from changes in the Company, including its security ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries. |X| Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages. |X| Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures. |X| 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. |X| 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 market 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. Commodity Price Risk The Company's regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electric energy for its retail customers due to current Indiana and Ohio regulations, which subject to compliance with applicable state regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. The Company does engage in limited, wholesale power marketing activities that may expose it to commodity price risk associated with fluctuating electric power prices. The Company's wholesale power marketing activities manage the utilization of its available electric generating capacity as well as other trading activities that maximize short-term movement in electricity prices. These operations enter into forward and option contracts that commit the Company to purchase and sell commodities in the future. Commodity price risk results from forward sale and option contracts that commit the Company to deliver commodities on specified future dates. Power marketing uses planned unutilized generation capability and forward purchase contracts to protect certain sales transactions from unanticipated fluctuations in the price of electric power, and periodically, will use derivative financial instruments to protect its interests from unplanned outages and shifts in demand. Open positions in terms of price, volume and specified delivery points may occur to a limited extent and are managed using methods described above and frequent management reporting. The Company enters into forward and option contracts in order to maximize short-term movement in electricity prices. These contracts are generally non-asset backed "buy-sell" transactions that are short-term in nature and expose the Company to limited market risk. The Company has designated these activities as "trading" activities. All "trading" and "other-than-trading" contracts at March 31, 2002 totaled $11.8 million of prepayments and other current assets and $11.6 million of accrued liabilities, compared to $5.1 million of prepayments and other current assets and $1.9 million of accrued liabilities at December 31, 2001. The change in the net value of "trading" and "other-than-trading" contracts to $0.2 million from $3.2 million resulted in an unrealized loss of $3.0 million for the three months ended March 31, 2002. Market risk is measured by management as the potential impact on pre-tax earnings resulting from a 10% adverse change in the forward price of commodity prices on market sensitive financial instruments (all contracts not expected to be settled by physical receipt or delivery). For the three months ended March 31, 2002 and 2001, a 10% adverse change in the forward prices of electricity and natural gas on market sensitive financial instruments would have decreased pre-tax earnings by approximately $1.6 million and $0.1 million, respectively. Interest Rate Risk Interest rate risk is not significantly different from the information as set forth in Item 7A. Quantitative and Qualitative Disclosures About Market Risk included in the Company's 2001 Form 10-K and is therefore not presented herein. Other Risks Counter-party credit and market risks are not significantly different from the information as set forth in Item 7A. Quantitative and Qualitative Disclosures About Market Risk included in the Company's 2001 Form 10-K and is therefore not presented herein. 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 8 regarding environmental matters and Note 6 regarding ProLiance Energy, LLC. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits None. (b) Reports On Form 8-K During The Last Calendar Quarter On January 24, 2002, the Company filed a Current Report on Form 8-K with respect to the release of financial information to the investment community regarding Vectren's results of operations, financial position and cash flows for the three and twelve month periods ended December 31, 2001. The financial information was released to the public through this filing. Item 5. Other Events Item 7. Exhibits 99.1 - Press Release - Fourth Quarter 2001 Vectren Corporation Earnings 99.2 - Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 On March 26, 2002, the Company filed a Current Report on Form 8-K with respect to its decision to replace Arthur Andersen LLP as the Company's independent auditors, effective upon completion of a transition period which is expected to extend through the conclusion of their review of the financial results of the Company and its subsidiaries for the first quarter of 2002. Item 4. Changes in Registrant's Certifying Accountant. Item 7. Exhibits 16 - Letter from Arthur Andersen LLP to the Securities and Exchange Commission, dated March 26, 2002. 99 - Letter to Vectren Corporation Shareholders dated March 22, 2002 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 UTILITY HOLDINGS, INC. Registrant May 14, 2002 /s/Jerome A. Benkert, Jr. ------------------------- Jerome A. Benkert, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) /s/M. Susan Hardwick ---------------------------- M. Susan Hardwick Vice President and Controller (Principal Accounting Officer) -----END PRIVACY-ENHANCED MESSAGE-----