-----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, M6/3eZP/hkoBLBnDef8cARPBiSGTytKd0qV3/1F4ttqVVoiUSSeAewH83CvZi653 JgaNuVmlJGDjsa/r0YxWzQ== 0001096385-02-000060.txt : 20020814 0001096385-02-000060.hdr.sgml : 20020814 20020814113050 ACCESSION NUMBER: 0001096385-02-000060 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20020630 FILED AS OF DATE: 20020814 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: 02732652 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_2ndqtr.txt 2ND QTR 10Q SOUTHERN INDIANA GAS AND ELECTRIC 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 June 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 August 1, 2002 - -------------------------------- ---------------- -------------- Class Number of Shares Date As of August 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) .................................... Southern Indiana Gas and Electric Company 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....................12-19 3 Qualitative and Quantitative Disclosures About Market Risk...........20-21 Part II. Other Information 1 Legal Proceedings.................................................... 22 6 Exhibits and Reports on Form 8-K..................................... 22 Signatures........................................................... 23 Certification Pursuant To 18 U.S.C. Section 1350, As Adopted Pursuant To Section 906 Of The Sarbanes-Oxley Act Of 2002. 24 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, and 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) June 30, December 31, 2002 2001 - ------------------------------------------------ ---------- ----------- ASSETS Utility Plant Original cost $1,494,707 $1,455,826 Less: Accumulated depreciation & amortization 708,617 690,344 ---------- ---------- Net utility plant 786,090 765,482 ---------- ---------- Current Assets Cash & cash equivalents 983 2,451 Accounts receivable-less reserves of $3,129 & $3,241, respectively 47,352 41,227 Receivables from other Vectren companies 1,018 10,065 Accrued unbilled revenues 16,441 17,013 Inventories 34,698 38,322 Recoverable fuel & natural gas costs 15,531 22,132 Prepayments & other current assets 19,816 14,053 ---------- ---------- Total current assets 135,839 145,263 ---------- ---------- Investments in unconsolidated affiliates 160 160 Other investments 8,546 9,254 Non-utility property-net 3,789 4,386 Goodwill-net 5,557 5,557 Regulatory assets 54,751 41,525 Other assets 2,127 1,595 ---------- ---------- TOTAL ASSETS $ 996,859 $ 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) June 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 257,067 255,464 Accumulated other comprehensive income 76 94 -------- -------- Total common shareholder's equity 335,401 333,816 -------- -------- Cumulative redeemable preferred stock of subsidiary 344 460 Long-term debt-net of current maturities 290,798 291,702 Long-term debt to VUHI 49,460 49,460 -------- -------- Total capitalization 676,003 675,438 -------- -------- Commitments & Contingencies (Notes 4-6) Current Liabilities Accounts payable 22,241 27,135 Payables to other Vectren companies 7,843 3,390 Accrued liabilities 41,522 33,545 Short-term borrowings - 874 Short-term borrowings to VUHI 84,001 80,664 Current maturities of long-term debt 999 - -------- -------- Total current liabilities 156,606 145,608 -------- -------- Deferred Income Taxes & Other Liabilities Deferred income taxes 123,143 112,746 Deferred credits & other liabilities 41,107 39,430 -------- -------- Total deferred income taxes & other liabilities 164,250 152,176 -------- -------- TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $996,859 $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 Six Months Ended June 30, June 30, ------------------- ------------------- 2002 2001 2002 2001 - ---------------------------------------- -------- -------- -------- -------- OPERATING REVENUES Electric revenues $158,924 $ 95,020 $285,724 $183,229 Gas revenues 17,624 11,351 47,231 63,301 -------- -------- -------- -------- Total operating revenues 176,548 106,371 332,955 246,530 -------- -------- -------- -------- COST OF OPERATING REVENUES Fuel for electric generation 19,068 17,857 36,859 35,841 Purchased electric energy 87,013 33,662 146,836 46,815 Cost of gas sold 11,394 4,529 28,938 45,987 -------- -------- -------- -------- Total cost of operating revenues 117,475 56,048 212,633 128,643 -------- -------- -------- -------- TOTAL OPERATING MARGIN 59,073 50,323 120,322 117,887 OPERATING EXPENSES Other operating 27,105 25,364 51,797 48,891 Merger & integration costs - - - 302 Restructuring costs - 4,344 - 4,344 Depreciation & amortization 11,058 11,053 22,041 22,137 Income taxes 7,008 666 13,333 9,707 Taxes other than income taxes 2,900 3,227 6,318 6,853 -------- -------- -------- -------- Total operating expenses 48,071 44,654 93,489 92,234 -------- -------- -------- -------- OPERATING INCOME 11,002 5,669 26,833 25,653 Other income - net 7,113 928 8,183 1,787 Interest expense 5,729 5,117 11,485 10,373 -------- -------- -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 12,386 1,480 23,531 17,067 -------- -------- -------- -------- Cumulative effect of change in accounting principle-net of tax - - - 3,938 -------- -------- -------- -------- NET INCOME 12,386 1,480 23,531 21,005 Preferred stock dividends 2 242 10 480 -------- -------- -------- -------- NET INCOME APPLICABLE TO COMMON SHAREHOLDER $ 12,384 $ 1,238 $ 23,521 $ 20,525 ======== ======== ======== ========
The accompanying notes are an integral part of these condensed financial statements. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited - In thousands) Six Months Ended June 30, -------------------- 2002 2001 - ---------------------------------------------- -------- -------- NET CASH FLOWS FROM OPERATING ACTIVITIES $ 59,142 $ 35,620 -------- -------- CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES Requirements for: Dividends on common stock (21,910) (16,329) Redemption of preferred stock (116) (153) Dividends on preferred stock (10) (479) Net change in short-term borrowings, including to VUHI 2,463 1,136 Proceeds (payments) from other financing activities - (15) -------- -------- Net cash flows (required for) financing activities (19,573) (15,840) -------- -------- CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES Proceeds from sale of other investments 1,400 - Requirements for: Capital expenditures (42,437) (18,511) Other investments - (2,134) -------- -------- Net cash flows (required for) investing activities (41,037) (20,645) -------- -------- Net increase in cash & cash equivalents (1,468) (865) Cash & cash equivalents at beginning of period 2,451 1,613 -------- -------- Cash & cash equivalents at end of period $ 983 $ 748 ======== ======== 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 June 2002, the EITF reached a final consensus in EITF Issue 02-03 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-03) that states mark-to-market gains and losses on energy trading contracts (whether realized or unrealized and whether financially or physically settled) should be shown net in the income statement and that expanded disclosure of energy trading activities is required. This consensus is effective for periods ending after July 15, 2002, with reclassification of prior period amounts required. The Company currently accounts for all its power marketing contracts at gross in the Condensed Statements of Income. The Company has reviewed all of its current power marketing contracts and contracts closed in prior periods and identified no energy trading contracts subject to EITF 02-03. 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. 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 June 30, 2002 and 2001, amounts billed by other wholly owned subsidiaries of Vectren to the Company were $10.7 million and $10.4 million, respectively. For the six months ended June 30, 2002 and 2001, amounts billed by other wholly owned subsidiaries of Vectren to the Company were $23.3 million and $21.5 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 June 30, 2002 and 2001 were $15.0 million and $9.7 million, respectively. Amounts paid for such purchases for the six months ended June 30, 2002 and 2001 were $28.2 million and $20.9 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 $116.2 million is outstanding at June 30, 2002 and VUHI's $350.0 million unsecured senior notes outstanding at June 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. The Company has recently filed another proceeding with the IURC to receive approval of additional capital costs and to obtain approval for recovery of future operating costs, including depreciation, related to the SCR's through a rider mechanism. 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 $240 million to $250 million and is expected to be expended during the 2001-2006 period. Through June 30, 2002, $41.0 million has been expended. After the equipment is installed and operational, related additional annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million. 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. 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 better utilize and optimize the return on these key assets. The contracts entered into are primarily "buy-sell" transactions, short-term in nature, and 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 June 30, 2002, contracts had a net asset value of $0.1 million compared to a net asset value of $3.2 million at December 31, 2001. The Company has determined these energy marketing contracts are derivatives within the scope of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." 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, or absent quoted market prices, other valuation techniques. 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 June 30, 2002 totaled $9.7 million of prepayments and other current assets and $9.6 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 to $0.1 million at June 30, 2002 from $3.2 million at December 31, 2001 resulted in an unrealized loss of $0.1 million and $3.1 million, respectively, for the three and six months ended June 30, 2002. For the three and six months ended June 30, 2001, the Company's power marketing operations resulted in unrealized losses of $7.9 million and $2.4 million, respectively. Including these unrealized changes in fair value, overall margin (revenue net of purchased power) from power marketing operations for the three and six months ended June 30, 2002 was $2.4 million and $3.4 million, respectively, and for the three and six months ended June 30, 2001 was ($4.6) million and $6.8 million, respectively. 8. Segment Reporting The Company had two operating segments during the three and six months ended June 30, 2002: (1) Gas Utility Services and (2) Electric Utility Services. The Gas Utility Services segment provides natural gas distribution and transportation services in southwest Indiana. The Electric Utility Services segment includes the operations of the Company's power generating and marketing operations, and electric transmission and distribution services, which provides electricity to primarily southwestern Indiana. The following tables provide information about business segments. The Company makes decisions on finance and dividends at the corporate level. Three Months Six Months Ended June 30, Ended June 30, ---------------------- --------------------- In thousands 2002 2001 2002 2001 - ----------------------------- --------- --------- --------- --------- Operating Revenues Electric Utility Services $ 158,924 $ 95,020 $ 285,724 $ 183,229 Gas Utility Services 17,624 11,351 47,231 63,301 --------- --------- --------- --------- Total operating revenues $ 176,548 $ 106,371 $ 332,955 $ 246,530 ========= ========= ========= ========= Net Income Applicable to Common Shareholder Electric Utility Services $ 12,233 $ 3,272 $ 19,902 $ 20,141 Gas Utility Services 151 (2,034) 3,619 384 --------- --------- --------- --------- Net income applicable to common shareholder $ 12,384 $ 1,238 $ 23,521 $ 20,525 ========= ========= ========= ========= June 30, December 31, In thousands 2002 2001 - ----------------------------- --------- ----------- Identifiable Assets Electric Utility Services $ 841,244 $ 811,248 Gas Utility Services 155,615 161,974 -------- -------- Total identifiable assets $ 996,859 $ 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 The Company's operations are comprised of its Electric Utility Services and Gas Utility Services segments. The Electric Utility Services segment includes the Company's power supply operations, power marketing operations, and electric transmission and distribution services that provide electricity to primarily southwestern Indiana. The Gas Utility Services segment includes the operations of the Company's natural gas distribution business and provides natural gas distribution and transportation services in southwestern Indiana. The results of operations are as follows:
Three Months Six Months Ended June 30, Ended June 30, ------------------- ------------------- In thousands 2002 2001 2002 2001 - --------------------------------------------- -------- -------- -------- -------- Net income applicable to common shareholder, as reported $ 12,384 $ 1,238 $ 23,521 $ 20,525 Merger and integration costs-net of tax - - - 187 Restructuring costs-net of tax - 2,697 - 2,697 Cumulative effect of change in accounting principle-net of tax - - - (3,938) -------- -------- -------- -------- Net income applicable to common shareholder before nonrecurring items $ 12,384 $ 3,935 $ 23,521 $ 19,471 ======== ======== ======== ========
Net Income Applicable to Common Shareholder For the three months ended June 30, 2002, net income applicable to common shareholder increased $11.1 million primarily due to the accrual in 2002 of carrying costs on the Company's demand side management programs consistent with an existing IURC rate order and the completion in 2001 of merger and restructuring activities and related costs, and favorable weather, and favorable fluctuations in fair value of derivative contracts. For the six months ended June 30, 2002, net income applicable to common shareholder increased $3.0 million. The increases affecting the quarterly results were offset for the year to date period by decreased margins resulting from the effects of warm weather during the peak heating season, and reduced price volatility affecting energy marketing activity. New Accounting Principles EITF 02-03 In June 2002, the EITF reached a final consensus in EITF Issue 02-03 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-03) that states mark-to-market gains and losses on energy trading contracts (whether realized or unrealized and whether financially or physically settled) should be shown net in the income statement and that expanded disclosure of energy trading activities is required. This consensus is effective for periods ending after July 15, 2002, with reclassification of prior period amounts required. The Company currently accounts for all its power marketing contracts at gross in the Condensed Statements of Income. The Company has reviewed all of its current power marketing contracts and contracts closed in prior periods and identified no energy trading contracts subject to EITF 02-03. 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. 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 months ended June 30, 2002 of $52.8 million increased $9.3 million, or 21%, from 2001 primarily due to fluctuations in fair value of derivative contracts. Non-firm wholesale margins in 2001 reflect a $7.9 million reduction due to fair value fluctuations, compared to a $0.1 million reduction in 2002. The remaining increase, attributable to retail and firm wholesale sales, results from weather 16% warmer than normal and 10% warmer than the prior year and a cash return on NOx compliance expenditures pursuant to a rate recovery rider approved by the IURC in August 2001. Electric Utility margin for the six months ended June 30, 2002 of $102.0 million increased $1.5 million, or 1%, from 2001 due to the effects of warmer weather, offset somewhat by decreases in non-firm wholesale margin. When generation capacity is not needed to serve utility customers, the Company markets available power from its owned generation assets to better utilize and optimize the return on these key assets. The contracts entered into are primarily "buy-sell" transactions, short-term in nature, and expose the Company to limited market risk. During 2002, the Company has increased its activity in the wholesale market, as evidenced by increased electric revenues and purchased power. While volumes both sold and purchased 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, non-firm wholesale power margins decreased $3.4 million for the year-to-date period. Gas Utility Margin Gas Utility margin for the three months ended June 30, 2002 of $6.2 million decreased $0.6 million, or 9%, compared to 2001. The decrease is primarily due to decreased throughput. Despite cooler temperatures than in the prior year, throughput declined from 6.8 MMDth in 2001 to 6.0 MMDth in 2002 or 12% due to customer conservation offset somewhat by customer growth. Gas Utility margin for the six months ended June 30, 2002 of $18.3 million increased $1.0 million, or 6%, 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 peak heating season and customer conservation. These offsets resulted in an overall 10% decrease in total throughput from 18.7 MMDth in 2001 to 16.7 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 June 30, 2002 increased $1.7 million, or 7%, and $2.9 million, or 6% for the six months ended June 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 $6.3 million and $3.6 million for the three and six months ended June 30, 2002, respectively. The increase results from higher pretax earnings offset somewhat by a small decrease in the current year effective tax rate from 37% to 36%. Other income-net Other income-net increased $6.2 million and $6.4 million for the three and six months ended June 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. Interest Expense Interest expense increased $0.6 million and $1.1 million for the three and six months ended June 30, 2002. The increase was due primarily to increased borrowings 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. The Company has recently filed another proceeding with the IURC to receive approval of additional capital costs and to obtain approval for recovery of future operating costs, including depreciation, related to the SCR's through a rider mechanism. 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 $240 million to $250 million and is expected to be expended during the 2001-2006 period. Through June 30, 2002, $41.0 million has been expended. After the equipment is installed and operational, related additional annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million. 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. 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 June 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. 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 in future years due to significant capital expenditure for NOx compliance equipment. SIGECO's credit ratings on outstanding secured debt at June 30, 2002 are A-/A1 as rated by Standard and Poor's and Moody's, respectively. 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 $59.1 million and $35.6 million, for the six months ended June 30, 2002 and 2001, respectively. Cash flow from operations increased during the six months ended June 30, 2002 compared to 2001 by $23.5 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 ($208.8 million at June 30, 2002) and is subject to the same terms and conditions as VUHI's commercial paper program. Borrowings outstanding at June 30, 2002 were $84.0 million. At June 30, 2002, the Company had approximately $5 million of short-term borrowing capacity with third parties to supplement its intercompany borrowing arrangements all of which 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 $116.2 million is outstanding at June 30, 2002 and VUHI's $350.0 million unsecured senior notes outstanding at June 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 program existing at December 31, 2001, were removed as the facility was renewed during 2002. Financing Cash Flow Cash flow required for financing activities of $19.6 million for the six months ended June 30, 2002 includes $21.9 million in common stock dividends and $0.1 million paid for the redemption of preferred stock offset by $2.5 million of increases in borrowings. This is an increase in cash requirements of $3.7 million over the prior year due primarily due to increased common stock dividends. 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 $41.0 million for the six months ended June 30, 2002 includes $42.4 million for capital expenditures. Investing activities for the six months ended June 30, 2001 were $20.6 million. The increase is attributable to NOx compliance expenditures and expenditures for the construction of the new 80 megawatt peaking unit. 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 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. 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 better utilize and optimize the return on these key assets. The contracts entered into are primarily "buy-sell" transactions, short-term in nature, and 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 June 30, 2002, contracts had a net asset value of $0.1 million compared to a net asset value of $3.2 million at December 31, 2001. The Company has determined these energy marketing contracts are derivatives within the scope of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." Power marketing contracts at June 30, 2002 totaled $9.7 million of prepayments and other current assets and $9.6 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 to $0.1 million at June 30, 2002 from $3.2 million at December 31, 2001 resulted in an unrealized loss of $0.1 million and $3.1 million, respectively, for the three and six months ended June 30, 2002. For the three and six months ended June 30, 2001, the Company's power marketing operations resulted in unrealized losses of $7.9 million and $2.4 million, respectively. Including these unrealized changes in fair value, overall margin (revenue net of purchased power) from power marketing operations for the three and six months ended June 30, 2002 was $2.4 million and $3.4 million, respectively, and for the three and six months ended June 30, 2001 was ($4.6) million and $6.8 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 six months ended June 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 $0.1 million and $1.5 million, respectively. For the three and six months ended June 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 $1.4 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. 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 April 25, 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, financial position and cash flows for the three and twelve month periods ended March 31, 2002. The financial information was released to the public through this filing. Item 5. Other Events Item 7. Exhibits 99.1 - Press Release - First 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 On May 20, 2002, SIGECO filed an amendment to Current Report on Form 8-K, originally filed on March 26, 2002 with respect to its decision to dismiss Arthur Andersen LLP as the Company's independent auditors effective May 17, 2002. Deloitte & Touche LLP has been selected as the independent auditors for the Company, effective May 17, 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 May 20, 2002. 99 - Press release regarding selection of Deloitte & Touche LLP dated May 20, 2002. 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 August 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) CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED 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 14th day of August, 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-----