-----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, JE7bg0M3tAnrfzWf8yhJMVkkJr0Ezt3T8xB2/MrYckRxghmD/zlYu//cRnjQEE0D Rbt+Qf9nR4YFvNWir3OHtQ== 0001096385-02-000073.txt : 20021113 0001096385-02-000073.hdr.sgml : 20021113 20021113123947 ACCESSION NUMBER: 0001096385-02-000073 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021113 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHERN INDIANA GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000092195 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 350672570 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03553 FILM NUMBER: 02819093 BUSINESS ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 BUSINESS PHONE: 8124914000 MAIL ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 10-Q 1 sig_10q-sept02.txt 3RD QUARTER 10Q FOR SIGECO 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 September 30, 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 1-3553 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY ----------------------------------------- (Exact name of registrant as specified in its charter) INDIANA 35-0672570 - ---------------------------------- ------------------- (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) have been subject to such filing requirements for the past 90 days: Yes [X] No [ ] Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of the latest practicable date. Common Stock-Without Par Value 15,754,826 November 1, 2002 - ------------------------------- ---------- ---------------- Class Number of Shares Date As of November 1, 2002, all shares outstanding of the Registrant's classes of common stock were held by Vectren Corporation through its wholly owned subsidiary, Vectren Utility Holdings, Inc. Table of Contents Item Page Number Number Part I. Financial Information 1 Financial Statements (Unaudited) Condensed Balance Sheets......................................... 1-2 Condensed Statements of Income................................... 3 Condensed Statements of Cash Flows............................... 4 Notes to Condensed Unaudited Financial Statements................ 5-11 2 Management's Discussion and Analysis of Results of Operations and Financial Condition................. 12-20 3 Qualitative and Quantitative Disclosures About Market Risk......... 21-22 4 Controls and Procedures............................................ 23 Part II. Other Information 1 Legal Proceedings.................................................. 24 6 Exhibits and Reports on Form 8-K................................... 24 Signatures......................................................... 25 Certifications..................................................... 26-28 Definitions As discussed in this Form 10-Q, the abbreviations AFUDC means allowance for funds used during construction APB means Accounting Principles Board EITF means Emerging Issues Task Force FASB means Financial Accounting Standards Board IDEM means Indiana Department of Environmental Management IURC means Indiana Utility Regulatory Commission MMDth means millions of dekatherms MMBTU means millions of British thermal units USEPA means United States Environmental Protection Agency Throughput means combined gas sales and gas transportation volumes PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS (UNAUDITED) SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEETS (Unaudited- In thousands) September 30, December 31, 2002 2001 ----------- ----------- ASSETS Utility Plant Original cost $1,501,560 $1,455,826 Less: Accumulated depreciation & amortization 720,662 690,344 ---------- ---------- Net utility plant 780,898 765,482 ---------- ---------- Current Assets Cash & cash equivalents 3,096 2,451 Accounts receivable-less reserves of $3,590 & $3,241, respectively 49,907 41,227 Receivables from other Vectren companies 709 10,065 Accrued unbilled revenues 20,152 17,013 Inventories 41,086 38,322 Recoverable fuel & natural gas costs 10,173 22,132 Prepayments & other current assets 14,972 14,053 ---------- ---------- Total current assets 140,095 145,263 ---------- ---------- Investments in unconsolidated affiliates 160 160 Other investments 9,873 9,254 Non-utility property-net 3,789 4,386 Goodwill-net 5,557 5,557 Regulatory assets 55,477 41,525 Other assets 3,804 1,595 ---------- ---------- TOTAL ASSETS $ 999,653 $ 973,222 ========== ========== The accompanying notes are an integral part of these condensed financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEETS (Unaudited - In thousands) September 30, December 31, 2002 2001 ------------ ----------- LIABILITIES & SHAREHOLDER'S EQUITY Capitalization Common shareholder's equity Common stock (no par value) $ 78,258 $ 78,258 Retained earnings 268,300 255,464 Accumulated other comprehensive income - 94 -------- -------- Total common shareholder's equity 346,558 333,816 -------- -------- Cumulative redeemable preferred stock of subsidiary 344 460 Long-term debt-net of current maturities 290,838 291,702 Long-term debt due to VUHI 49,460 49,460 -------- -------- Total capitalization 687,200 675,438 -------- -------- Commitments & Contingencies (Notes 4-6) Current Liabilities Accounts payable 21,860 27,135 Payables to other Vectren companies 3,398 3,390 Accrued liabilities 38,609 33,545 Short-term borrowings 3,174 874 Short-term borrowings due to VUHI 81,892 80,664 Current maturities of long-term debt 1,000 - -------- -------- Total current liabilities 149,933 145,608 -------- -------- Deferred Income Taxes & Other Liabilities Deferred income taxes 119,445 112,746 Deferred credits & other liabilities 43,075 39,430 -------- -------- Total deferred income taxes & other liabilities 162,520 152,176 -------- -------- TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $999,653 $973,222 ======== ======== The accompanying notes are an integral part of these condensed financial statements.
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited - In thousands) Three Months Ended Nine Months Ended September 30, September 30, ------------------- --------------------- 2002 2001 2002 2001 -------- -------- -------- -------- OPERATING REVENUES Electric revenues $189,935 $104,335 $475,659 $287,564 Gas revenues 7,388 11,032 54,619 74,333 -------- -------- -------- -------- Total operating revenues 197,323 115,367 530,278 361,897 -------- -------- -------- -------- COST OF OPERATING REVENUES Fuel for electric generation 22,872 21,011 59,731 56,852 Purchased electric energy 92,436 22,565 239,272 69,380 Cost of gas sold 2,474 5,926 31,412 51,913 -------- -------- -------- -------- Total cost of operating revenues 117,782 49,502 330,415 178,145 -------- -------- -------- -------- TOTAL OPERATING MARGIN 79,541 65,865 199,863 183,752 OPERATING EXPENSES Other operating 24,205 23,659 76,003 72,550 Merger & integration costs - 286 - 588 Restructuring costs - 433 - 4,777 Depreciation & amortization 11,370 11,053 33,411 33,190 Income taxes 12,681 8,336 26,014 18,043 Taxes other than income taxes 3,657 3,125 9,975 9,978 -------- -------- -------- -------- Total operating expenses 51,913 46,892 145,403 139,126 -------- -------- -------- -------- OPERATING INCOME 27,628 18,973 54,460 44,626 Other income - net 926 766 9,109 2,553 Interest expense 5,713 5,047 17,198 15,420 -------- -------- -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 22,841 14,692 46,371 31,759 -------- -------- -------- -------- Cumulative effect of change in accounting principle-net of tax - - - 3,938 -------- -------- -------- -------- NET INCOME 22,841 14,692 46,371 35,697 -------- -------- -------- -------- Preferred stock dividends 15 268 25 748 Loss on extinguishment of preferred stock - 1,176 - 1,170 -------- -------- -------- -------- NET INCOME APPLICABLE TO COMMON SHAREHOLDER $ 22,826 $ 13,248 $ 46,346 $ 33,779 ======== ======== ======== ========
The accompanying notes are an integral part of these condensed financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited - In thousands) Nine Months Ended September 30, -------------------- 2002 2001 -------- -------- NET CASH FLOWS FROM OPERATING ACTIVITIES $ 92,185 $ 61,528 -------- -------- CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES Requirements for: Dividends on common stock (33,510) (24,006) Redemption of preferred stock (116) (17,676) Dividends on preferred stock (25) (748) Net change in short-term borrowings, including due to VUHI 3,528 25,912 -------- -------- Net cash flows (required for) financing activities (30,123) (16,518) -------- -------- CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES Proceeds from sale of investments and assets 1,400 1,119 Requirements for: Capital expenditures (61,191) (44,747) Other investments (1,626) - -------- -------- Net cash flows (required for) investing activities (61,417) (43,628) -------- -------- Net increase in cash & cash equivalents 645 1,382 Cash & cash equivalents at beginning of period 2,451 1,613 -------- -------- Cash & cash equivalents at end of period $ 3,096 $ 2,995 ======== ======== The accompanying notes are an integral part of these condensed financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY NOTES TO THE CONDENSED FINANCIAL STATEMENTS (UNAUDITED) 1. Organization and Nature of Operations Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana corporation, provides electric generation, transmission, and distribution services to 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. SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). Vectren, an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. Vectren was organized on June 10, 1999 solely for the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with APB Opinion No. 16 "Business Combinations." Vectren's wholly owned subsidiary, VUHI, serves as the intermediate holding company for its three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, SIGECO, formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations, a utility jointly owned by Indiana Gas and Vectren Energy Delivery of Ohio, Inc. (VEDO). Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935. 2. Basis of Presentation The interim condensed financial statements included in this report have been prepared by the Company, without audit, as provided in the rules and regulations of the Securities and Exchange Commission. Certain information and 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 condensed financial statements and related notes should be read in conjunction with the Company's audited annual financial statements for the year ended December 31, 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 EITF 02-03 In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-03) that gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) should be shown net in the income statement, whether or not settled physically, if the derivative instruments are held for "trading purposes." The consensus rescinded EITF 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10) as well as other decisions reached on energy trading contracts at the EITF's June 2002 meeting. The Company's power marketing operations enter into contracts that are derivatives as defined by SFAS 133, but these operations do not met the definition of energy trading activities based upon the provisions in EITF 98-10. Currently, the Company uses a gross presentation to report the results of these operations. The Company will re-evaluate its portfolio of derivative contracts to determine if any will be required to be reported net in accordance with the provisions of the new consensus. The consensus relating to the presentation of gains and losses on derivative instruments held for "trading purposes" is effective for financial statements issued for periods beginning after December 15, 2002 and requires the reclassification of all periods presented. For the Company, the consensus is effective beginning January 1, 2003. See Note 7 for additional information on the Company's power marketing operations 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. Goodwill is to be tested for impairment at a reporting unit level at least annually. SFAS 142 also required the initial impairment review of all goodwill within six months of the adoption date. The impairment review consisted 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 were 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 other intangible assets; however, the Company does not have any significant other intangible assets. The Company has goodwill included in its Gas Utility Services operating segment. The amortization of this goodwill which approximated $0.2 million per year ceased on January 1, 2002. Initial impairment reviews to be performed within six months of adoption of SFAS 142 were completed and resulted in no impairment. 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 will no longer be 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 have a material impact on 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. 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 September 30, 2002 and 2001, amounts billed by other wholly owned subsidiaries of Vectren to the Company were $10.9 million and $9.1 million, respectively. For the nine months ended September 30, 2002 and 2001, amounts billed by other wholly owned subsidiaries of Vectren to the Company were $35.2 million and $30.6 million, respectively. Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which the Company purchases fuel used for electric generation. Amounts paid for such purchases for the three months ended September 30, 2002 and 2001 were $17.3 million and $7.3 million, respectively. Amounts paid for such purchases for the nine months ended September 30, 2002 and 2001 were $45.6 million and $28.2 million, respectively. Cash Management and 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. Guarantees of Parent Company Debt Vectren's three operating utility companies, SIGECO, VEDO, and Indiana Gas are guarantors of VUHI's $325 million commercial paper program, of which $168.5 million is outstanding at September 30, 2002 and VUHI's $350.0 million unsecured senior notes outstanding at September 30, 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. 5. Commitments & Contingencies The Company is party to various legal and regulatory 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 6 regarding environmental matters. 6. 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, 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. On August 28, 2001, the IURC issued an order that (1) approved the Company's proposed project to achieve environmental compliance by investing in clean coal technology, (2) approved the Company's initial cost estimate of $198 million for the construction, subject to periodic review of the actual costs incurred, and (3) approved a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months a return on its capital costs for the project, at its overall cost of capital, including a return on equity. The first rider adjustment for ongoing cost recovery was approved by the IURC on February 6, 2002. On June 5, 2002, the Company filed a new proceeding to update the NOx project cost and to obtain approval of a second rider authorizing ongoing recovery of depreciation and operating costs related to the clean coal technology. 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 ranges from $240 million to $250 million and is expected to be expended during the 2001-2006 period. Through September 30, 2002, $53.5 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 would commence in 2004 when the technology becomes operational. On October 22, 2002, the Company filed a settlement agreement with the IURC that has been entered into with the Indiana Office of Utility Consumer Counselor and an industrial intervenor group relating to the ongoing NOx project. The agreement, if approved by the IURC, will authorize additional capital cost investment and recovery on those capital costs, as well as the recovery of future operating costs, including depreciation and purchased emission allowances, through a rider mechanism. A hearing is scheduled for November 15, 2002 to consider the agreement. The settlement establishes a fixed return of 8 percent on the capital investment. The Company expects to achieve timely compliance as a result of the project. Construction of the first SCR at Culley is nearing completion on schedule, and 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. 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 a majority of the claims brought in its original compliant. In its original complaint, USEPA alleged significant emissions increases of three pollutants for each of four maintenance projects. Currently, USEPA is alleging only significant emission increases of a single pollutant at three of the four maintenance projects cited in the original complaint. The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per violation. However, on July 29, 2002, the Court ruled that USEPA could not seek civil penalties for two of the three remaining projects at issue in the litigation, significantly reducing potential civil penalty exposure. 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 in response it could incur capital costs of approximately $20 million to $40 million to comply with the order. Trial is currently set to begin March 31, 2003. 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 June of 2002, the Company received a request from the IDEM concerning information on any manufactured gas plant sites which the Company has not enrolled in IDEM's Voluntary Remediation Program, specifically five sites which were owned and/or operated by SIGECO. Preliminary site investigations conducted by SIGECO in the mid-1990's confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. 7. Energy Marketing Activities When generation capacity is not needed to serve utility customers, the Company markets available power from its owned generation assets to optimize the return on these key assets. The contracts entered into are primarily short-term purchase and sale transactions that expose the Company to limited market risk. During 2002, the Company has increased its activity in the wholesale market. With the exception of those contracts subject to the normal purchase and sale exclusion, commodity contracts are accounted for at market value. As of September 30, 2002, contracts had a no net asset value compared to a net asset value of $3.2 million at December 31, 2001. The Company has determined these power marketing contracts are derivatives within the scope of SFAS No. 133. Contracts recorded at market value are recorded as current or noncurrent assets or liabilities in the Condensed Balance Sheets depending on their value and on when the contracts are expected to be settled. Changes in market value, which is a function of the normal decline in fair value as earnings are realized and the fluctuation in fair value resulting from price volatility, are recorded in purchased electric energy in the Condensed Statements of Income. Market value is determined using quoted market prices from independent sources. Forward sale contracts, premiums received for written options, and proceeds received from exercised options are recorded when settled as electric utility revenues in the 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 Condensed Statements of Income. Contracts with counter-parties subject to master netting arrangements are presented net in the Condensed Balance Sheets. Power marketing contracts at September 30, 2002 totaled $7.7 million of prepayments and other current assets and $7.7 million of accrued liabilities, compared to $5.2 million of prepayments and other current assets and $2.0 million of accrued liabilities at December 31, 2001. For the three months ended September 30, 2002 and 2001, the change in the net value of these contracts includes an unrealized gain of $0.2 million and an unrealized loss of $0.9 million, respectively. For the nine months ended September 30, 2002 and 2001, the change in the net value of these contracts includes unrealized losses of $3.0 million and $3.3 million, respectively. Including these unrealized changes in fair value, overall margin (revenue net of purchased power) from power marketing operations for the three months ended September 30, 2002 and 2001 was $4.6 million and $4.1million, respectively, and for the nine months ended September 30, 2002 and 2001 was $8.0 million and $10.9 million, respectively. 8. Segment Reporting The Company had two operating segments during the three and nine months ended September 30, 2002: (1) Gas Utility Services and (2) Electric Utility Services. The Gas Utility Services segment provides natural gas distribution and transportation services in southwestern Indiana. The Electric Utility Services segment includes the operations of SIGECO's electric transmission and distribution services, which provides electricity to primarily southwestern Indiana, and SIGECO's power generating and power marketing operations. The following tables provide information about business segments. The Company makes decisions on finance and dividends at the corporate level.
Three Months Ended Nine Months Ended September 30, September 30, ---------------------- --------------------- In thousands 2002 2001 2002 2001 --------- --------- --------- --------- Operating Revenues Electric Utility Services $ 189,935 $ 104,335 $ 475,659 $ 287,564 Gas Utility Services 7,388 11,032 54,619 74,333 --------- --------- --------- --------- Total operating revenues $ 197,323 $ 115,367 $ 530,278 $ 361,897 ========= ========= ========= ========= Net Income Applicable to Common Shareholder Electric Utility Services $ 23,268 $ 11,380 $ 43,170 $ 31,526 Gas Utility Services (442) 1,868 3,176 2,253 --------- --------- --------- --------- Net income applicable to common shareholder $ 22,826 $ 13,248 $ 46,346 $ 33,779 ========= ========= ========= ========= September 30, December 31, In thousands 2002 2001 ----------- ----------- Identifiable Assets Electric Utility Services $ 842,629 $ 811,248 Gas Utility Services 157,024 161,974 --------- --------- Total identifiable assets $ 999,653 $ 973,222 ========= =========
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Description of the Business Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana corporation, provides electric generation, transmission, and distribution services to 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. SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). Vectren, an Indiana corporation, is an energy and applied technology holding company headquartered in Evansville, Indiana. Vectren was organized on June 10, 1999 solely for the purpose of effecting the merger of Indiana Energy, Inc. (Indiana Energy) and SIGCORP, Inc. (SIGCORP). On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares and has been accounted for as a pooling-of-interests in accordance with APB Opinion No. 16 "Business Combinations." Vectren's wholly owned subsidiary, VUHI, serves as the intermediate holding company for its three operating public utilities: Indiana Gas Company, Inc. (Indiana Gas), formerly a wholly owned subsidiary of Indiana Energy, SIGECO, formerly a wholly owned subsidiary of SIGCORP, and the Ohio operations, a utility jointly owned by Indiana Gas and Vectren Energy Delivery of Ohio, Inc. (VEDO). Both Vectren and VUHI are exempt from registration pursuant to Section 3(a)(1) and 3(c) of the Public Utility Holding Company Act of 1935. Results of Operations
Three Months Ended Nine Months Ended September 30, September 30, ------------------- ------------------- In thousands 2002 2001 2002 2001 -------- -------- -------- -------- Net income applicable to common shareholder, as reported $ 22,826 $ 13,248 $ 46,346 $ 33,779 Merger, integration, & other costs-net of tax - 178 - 365 Restructuring costs-net of tax - 268 - 2,965 Cumulative effect of change in accounting principle-net of tax - - - (3,938) Loss on extinguishment of preferred stock - 1,176 - 1,170 -------- -------- -------- -------- Net income applicable to common shareholder before nonrecurring items $ 22,826 $ 14,870 $ 46,346 $ 34,341 ======== ======== ======== ========
Net Income Applicable to Common Shareholder For the nine months ended September 30, 2002, net income applicable to common shareholder was $46.3 million compared to $33.8 million for the same period in 2001. In addition to completion of merger and restructuring activities and related costs and the extinguishment of preferred stock, the nine-month period increase of $12.6 million was primarily the result of favorable cooling weather during the second and third quarters, a return to lower gas prices and the related reduction in costs incurred in 2001, and merger synergies. The accrual of carrying costs on the Company's demand side management programs consistent with an existing IURC rate order also contributed. These favorable impacts were offset somewhat by the effects of warm weather during the heating season. For the three months ended September 30, 2002, net income applicable to common shareholder was $22.8 million compared to $13.2 million for the same period in 2001. Net income applicable to common shareholder increased primarily due to increased margins, partly reflecting favorable cooling weather. New Accounting Principles EITF 02-03 In October 2002, the EITF reached a final consensus in EITF Issue 02-03 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-03) that gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) should be shown net in the income statement, whether or not settled physically, if the derivative instruments are held for "trading purposes." The consensus rescinded EITF 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10) as well as other decisions reached on energy trading contracts at the EITF's June 2002 meeting. The Company's power marketing operations enter into contracts that are derivatives as defined by SFAS 133, but these operations do not met the definition of energy trading activities based upon the provisions in EITF 98-10. Currently, the Company uses a gross presentation to report the results of these operations. The Company will re-evaluate its portfolio of derivative contracts to determine if any will be required to be reported net in accordance with the provisions of the new consensus. The consensus relating to the presentation of gains and losses on derivative instruments held for "trading purposes" is effective for financial statements issued for periods beginning after December 15, 2002 and requires the reclassification of all periods presented. For the Company, the consensus is effective beginning January 1, 2003. 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 this statement. This includes goodwill recorded in past business combinations. Goodwill is to be tested for impairment at a reporting unit level at least annually. SFAS 142 also required the initial impairment review of all goodwill within six months of the adoption date. The impairment review consisted 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 were 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 other intangible assets; however, the Company does not have any significant other intangible assets. The Company has goodwill included in its Gas Utility Services operating segment. The amortization of this goodwill which approximated $0.2 million per year ceased on January 1, 2002. Initial impairment reviews to be performed within six months of adoption of SFAS 142 were completed and resulted in no impairment. 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. Significant Fluctuations Utility Margin (Operating Revenues Less Cost of Gas Sold, Fuel for Electric Generation, & Purchased Electric Energy) Electric Utility Margin Electric Utility margin for the three and nine months ended September 30, 2002 and 2001 increased $14.0 million, or 23%, and $15.3 million, or 9%, respectively. The increases result primarily from the effect on retail sales of cooling weather considerably warmer than the prior year. Weather in 2002 was 31% warmer for the quarter and 23% warmer for the nine-month period when compared to 2001. For the nine-month period, weather was 22% warmer than normal. In addition to weather, both the quarter and the nine-month period were positively affected by a cash return on NOx compliance expenditures pursuant to a rate recovery rider approved by the IURC in August 2001. The year-to-date period, however, was negatively affected by decreased margin from power marketing activities. When generation capacity is not needed to serve utility customers, the Company markets available power from its owned generation assets to optimize the return on these key assets. The contracts entered into are primarily short-term purchase and sale transactions that expose the Company to limited market risk. While volumes both sold and purchased in the wholesale market have increased during 2002, margins have softened this year as a result of reduced price volatility. As a result of increased activity offset by reduced price volatility, margin from power marketing activities decreased $2.9 million for the year-to-date period. For the quarter, power marketing activities increased margin by $0.5 million. Gas Utility Margin Gas Utility margin for the three months ended September 30, 2002 of $4.9 million decreased $0.2 million, or 4%, compared to 2001. The decrease is primarily due to warmer weather. Gas Utility margin for the nine months ended September 30, 2002 of $23.2 million increased $0.8 million, or 4%, compared to 2001. The increase is primarily due to favorable changes in unaccounted for gas, customer growth, and other adjustments. These increases were offset by weather warmer than the prior year during the heating season and customer conservation. These offsets resulted in an overall 6% decrease in total throughput from 23.7 MMDth in 2001 to 22.3 MMDth in 2002. Operating Expenses (excluding Cost of Gas Sold, Fuel for Electric Generation, & Purchased Electric Energy) Other Operating Other operating expenses for the three months ended September 30, 2002 increased $0.5 million, or 2%, and $3.5 million, or 5% for the nine months ended September 30, 2002 compared to 2001. The 2002 increase results primarily from charges for the use of corporate assets offset by merger synergies and the timing of maintenance expenditures. Income Tax Expense Federal and state income taxes increased $4.3 million and $8.0 million for the three and nine months ended September 30, 2002, respectively. The increase results principally from higher pretax earnings. Taxes Other Than Income Taxes Taxes other than income taxes increased $0.5 million for the three months ended September 30, 2002 when compared to the prior year period and were comparable for the nine month periods. The increase during the quarter is attributable to greater electric revenues that are subject to gross receipts tax than in the prior period. For the nine-month period, the increase experienced during the quarter was offset by a decrease in gross receipts and excise taxes as a result of lower gas revenues due to lower gas prices. Other income-net Other income-net increased $0.2 million and $6.6 million for the three and nine months ended September 30, 2002 as compared to the prior year periods. The increases are attributable to the accrual of $5.2 million in carrying costs for demand side management programs not currently in rates pursuant to an existing IURC rate order and $0.6 million from the sale of excess emission allowances in the second quarter of 2002. The remainder is principally increased AFUDC throughout 2002 due to increased construction in progress balances for the NOx compliance project. Interest Expense Interest expense increased $0.7 million and $1.8 million for the three and nine months ended September 30, 2002. The increase was due primarily to increased borrowings from VUHI resulting from NOx compliance capital expenditures. 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, 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. On August 28, 2001, the IURC issued an order that (1) approved the Company's proposed project to achieve environmental compliance by investing in clean coal technology, (2) approved the Company's initial cost estimate of $198 million for the construction, subject to periodic review of the actual costs incurred, and (3) approved a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months a return on its capital costs for the project, at its overall cost of capital, including a return on equity. The first rider adjustment for ongoing cost recovery was approved by the IURC on February 6, 2002. On June 5, 2002, the Company filed a new proceeding to update the NOx project cost and to obtain approval of a second rider authorizing ongoing recovery of depreciation and operating costs related to the clean coal technology. 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 ranges from $240 million to $250 million and is expected to be expended during the 2001-2006 period. Through September 30, 2002, $53.5 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 would commence in 2004 when the technology becomes operational. On October 22, 2002, the Company filed a settlement agreement with the IURC that has been entered into with the Indiana Office of Utility Consumer Counselor and an industrial intervenor group relating to the ongoing NOx project. The agreement, if approved by the IURC, will authorize additional capital cost investment and recovery on those capital costs, as well as the recovery of future operating costs, including depreciation and purchased emission allowances, through a rider mechanism. A hearing is scheduled for November 15, 2002 to consider the agreement. The settlement establishes a fixed return of 8 percent on the capital investment. The Company expects to achieve timely compliance as a result of the project. Construction of the first SCR at Culley is nearing completion on schedule, and 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. 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 a majority of the claims brought in its original compliant. In its original complaint, USEPA alleged significant emissions increases of three pollutants for each of four maintenance projects. Currently, USEPA is alleging only significant emission increases of a single pollutant at three of the four maintenance projects cited in the original complaint. The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per violation. However, on July 29, 2002, the Court ruled that USEPA could not seek civil penalties for two of the three remaining projects at issue in the litigation, significantly reducing potential civil penalty exposure. 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 in response it could incur capital costs of approximately $20 million to $40 million to comply with the order. Trial is currently set to begin March 31, 2003. 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 June of 2002, the Company received a request from the IDEM concerning information on any manufactured gas plant sites which the Company has not enrolled in IDEM's Voluntary Remediation Program, specifically five sites which were owned and/or operated by SIGECO. Preliminary site investigations conducted by SIGECO in the mid-1990's confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. 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 50% and 49% of total capitalization, including current maturities of long-term debt, at September 30, 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, and capital expenditures. 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 in future years due to significant capital expenditures for NOx compliance equipment. SIGECO's credit ratings on outstanding secured debt at September 30, 2002 are A-/A1 as rated by Standard and Poor's and Moody's, respectively. On August 27, 2002, Moody's Investor Services issued a press release indicating its rating is under review for a possible downgrade. Moody's raised several concerns including the regulatory treatment of the significant NOx environmental expenditures. The Company continues to work with Moody's to address these and other items involving Vectren and other Vectren subsidiaries including the favorable NOx settlement. 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 $92.2 million and $61.5 million, for the nine months ended September 30, 2002 and 2001, respectively. Cash flow from operations increased during the nine months ended September 30, 2002 compared to 2001 by $30.7 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 SIGECO mainly relies on the short-term borrowing arrangements of VUHI for its short-term working capital needs. The intercompany credit line totals $150 million, but is limited to VUHI's available capacity ($156.5 million at September 30, 2002) and is subject to the same terms and conditions as VUHI's commercial paper program. Borrowings outstanding at September 30, 2002 were $81.9 million. At September 30, 2002, the Company had approximately $5 million of short-term borrowing capacity with third parties to supplement its intercompany borrowing arrangements of which $1.8 million was available. Vectren's three operating utility companies, SIGECO, VEDO, and Indiana Gas are guarantors of VUHI's $325 million commercial paper program, of which $168.5 million is outstanding at September 30, 2002 and VUHI's $350.0 million unsecured senior notes outstanding at September 30, 2002. VUHI has no significant independent assets or operations other than the assets and operations of these operating utility companies. These guarantees are full and unconditional and joint and several. Ratings triggers on VUHI's commercial paper backup facility existing at December 31, 2001, were removed as the facility was renewed during 2002. Financing Cash Flow Cash flow required for financing activities of $30.1 million for the nine months ended September 30, 2002 includes $33.5 million in common stock dividends and $0.1 million paid for the redemption of preferred stock offset by $3.5 million of increases in borrowings. In the prior year, the company retired $17.7 million of preferred stock. 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 $61.4 million for the nine months ended September 30, 2002 includes $61.2 million for capital expenditures. Investing activities for the nine months ended September 30, 2001 were $43.6 million. The increase is attributable to NOx compliance expenditures. 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 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. QUALITATIVE AND QUANTITATIVE 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 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 operations that may expose it to commodity price risk associated with fluctuating electric power prices. The Company's wholesale power marketing operations manage the utilization of its available electric generating capacity. These operations enter into forward and option contracts that commit the Company to purchase and sell electric power 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. When generation capacity is not needed to serve utility customers, the Company markets available power from its owned generation assets to optimize the return on these key assets. The contracts entered into are primarily short-term purchase and sale contracts that expose the Company to limited market risk. During 2002, the Company has increased its activity in the wholesale market. With the exception of those contracts subject to the normal purchase and sale exclusion, commodity contracts are accounted for at market value. As of September 30, 2002, contracts had no net asset value compared to a net asset value of $3.2 million at December 31, 2001. The Company has determined these power marketing contracts are derivatives within the scope of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." Power marketing contracts at September 30, 2002 totaled $7.7 million of prepayments and other current assets and $7.7 million of accrued liabilities, compared to $5.2 million of prepayments and other current assets and $2.0 million of accrued liabilities at December 31, 2001. The change in the net value of these contracts includes an unrealized gain of $0.2 million and an unrealized loss of $3.0 million, respectively, for the three and nine months ended September 30, 2002. For the three months ended September 30, 2002 and 2001, the change in the net value of these contracts includes an unrealized gain of $0.2 million and an unrealized loss of $0.9 million, respectively. For the nine months ended September 30, 2002 and 2001, the change in the net value of these contracts includes unrealized losses of $3.0 million and $3.3 million, respectively. Including these unrealized changes in fair value, overall margin (revenue net of purchased power) from power marketing operations for the three months ended September 30, 2002 and 2001 was $4.6 million and $4.1 million, respectively, and for the nine months ended September 30, 2002 and 2001 was $8.0 million and $10.9 million, respectively. 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 and nine months ended September 30, 2002, a 10% adverse change in the forward prices of electricity on market sensitive financial instruments would have decreased pre-tax earnings by approximately $0.0 million and $1.4 million, respectively. For the three and nine months ended September 30, 2001, a 10% adverse change in the forward prices of electricity on market sensitive financial instruments would have decreased pre-tax earnings by approximately $0.6 million and $2.0 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 By using forward purchase contracts and derivative financial instruments to manage risk, the Company exposes itself to counter-party credit risk and market risk. The Company manages this exposure to counter-party credit risk by entering into contracts with companies that can be reasonably expected to fully perform under the terms of the contract. Counter-party credit risk is monitored regularly and positions are adjusted appropriately to manage risk. Further, tools such as netting arrangements and requests for collateral are also used to manage credit risk. The Company attempts to manage exposure to market risk associated with commodity contracts and interest rates by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Company's customer receivables from gas and electric sales and gas transportation services are primarily derived from a diversified base of residential, commercial, and industrial customers located in Indiana and west central Ohio. The Company manages credit risk associated with its receivables by continually reviewing creditworthiness and requests cash deposits based on that review. Credit risk associated with certain investments is also managed by a review of creditworthiness and receipt of collateral. ITEM 4. CONTROLS AND PROCEDURES Evaluation of disclosure controls and procedures Within 90 days prior to the filing of the report, 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 or the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective in bringing to their attention on timely basis material information relating to the Company required to be disclosed by the Company in its Exchange Act reports. Disclosure controls and procedures, as defined by the Securities Exchange Act of 1934 in Rules 13a-14(c) and 15d-14(c), 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 Securities and Exchange Act of 1934 (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 Since the evaluation of disclosure controls and procedures, there have been no significant changes to the Company's internal control structure or significant changes in other factors that could significantly affect the Company's internal control environment. No material weaknesses or other significant deficiencies in the design of internal control were noted by the Company during the most recent disclosure control and procedure evaluation and through the filing of this Form 10-Q. Internal control, as defined in American Institute of Certified Public Accountants Codification of Statements on Auditing Standards (AU ss.319), is a process, effected by an entity's board of directors, management, and other personnel, designed to provide reasonable assurance regarding the achievement of objectives in the following categories: (a) reliability of financial reporting, (b) effectiveness and efficiency of operations and (c) compliance with applicable laws and regulations. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The Company is party to various legal and regulatory 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 6 regarding environmental matters. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits None (b) Reports On Form 8-K During The Last Calendar Quarter On July 23, 2002, SIGECO 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 for the three, six, and twelve month periods ended June 30, 2002. The financial information was released to the public through this filing. Item 5. Other Events Item 7. Exhibits 99.1 - Press Release - Second Quarter 2002 Vectren Corporation Earnings 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 Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY ----------------------------------------- Registrant November 13, 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) CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 CHIEF EXECUTIVE OFFICER CERTIFICATION I, Niel C. Ellerbrook, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Southern Indiana Gas and Electric Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 13, 2002 /s/ Niel C. Ellerbrook --------------------------------- Niel C. Ellerbrook Chairman and Chief Executive Officer CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 CHIEF FINANCIAL OFFICER CERTIFICATION I, Jerome A. Benkert, Jr., certify that: 1. I have reviewed this quarterly report on Form 10-Q of Southern Indiana Gas and Electric Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a. designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b. evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c. presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 13, 2002 /s/ Jerome A. Benkert, Jr. ------------------------------------ Jerome A. Benkert, Jr. Executive Vice President and Chief Executive Officer CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 CERTIFICATION By signing below, each of the undersigned officers hereby certifies pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his or her knowledge, (i) this report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in this report fairly presents, in all material respects, the financial condition and results of operations of Southern Indiana Gas and Electric Company. Signed this 13th day of November 2002. /s/ Jerome A. Benkert, Jr. /s/ Niel C. Ellerbrook - --------------------------------- ------------------------------------- (Signature of Authorized Officer) (Signature of Authorized Officer) Jerome A. Benkert, Jr. Niel C. Ellerbrook - --------------------------------- ------------------------------------- (Typed Name) (Typed Name) Executive Vice President and Chief Financial Officer Chairman and Chief Executive Officer - --------------------------------- ------------------------------------- (Title) (Title) -----END PRIVACY-ENHANCED MESSAGE-----