-----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, FdezkhKZFnYXFSy0v/IuUfQYPZlp/MtUi58gU7I2kPXRhsJPHElGmI00hSc2wQ8p rO9YhJx2c3EI6gXFoLFcuA== 0000092195-01-500015.txt : 20010830 0000092195-01-500015.hdr.sgml : 20010830 ACCESSION NUMBER: 0000092195-01-500015 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010829 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-K/A SEC ACT: 1934 Act SEC FILE NUMBER: 001-03553 FILM NUMBER: 1726802 BUSINESS ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47741-0001 BUSINESS PHONE: 8124914000 MAIL ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 8124914000 10-K/A 1 sig10k-a_2000.txt FORM 10-K AMENDMENT NO. 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K/A Amendment No. 1 X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) - - OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 OR __TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) ---- OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission Registrant, State of Incorporation; IRS Employer File Number Address and Telephone Number Identification No. ----------- ---------------------------- ------------------ 1-3553 Southern Indiana Gas and Electric Company 35-0672570 (An Indiana Corporation) 20 N. W. Fourth Street Evansville, Indiana 47741-0001 (812) 491-4000 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Registrant Title of each class on which registered - -------------------- ------------------------ ------------------------- Southern Indiana Gas None and Electric Company Securities registered pursuant to Section 12(g) of the Act: Name of each exchange Registrant Title of each class on which registered - --------------------- -------------------------- ----------------------- Southern Indiana Gas Cumulative Preferred Stock, New York Stock Exchange and Electric Company $100 Par Value Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X. 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 At January 30, 2001, the aggregate market values of Southern Indiana Gas and Electric Company Cumulative Preferred Stock, $100 Par Value, 163,895 shares, held by non-affiliates was $13,812,650. As of March 21, 2001, the number of shares outstanding of the Registrant's classes of common stock were: Southern Indiana Gas and Electric Company: Common stock, no par value, 15,754,826 shares Outstanding and held by Vectren Corporation 2 Table of Contents Item Page Number Number 7 Management's Discussion and Analysis of Financial Condition and Results of Operations 3 8 Financial Statements and Supplementary Data 11 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K 33 Signatures 36 3 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Results of Operations Net Income Net income applicable to common shareholder was $40.0 million for the year ended December 31, 2000. Net income applicable to common shareholder before merger and integration costs of $14.1 million, or 11.0 million after tax, was $51.0 million for the year ended December 31, 2000, as compared to net income of $45.7 million and $42.4 million for 1999 and 1998, respectively. (See merger and integration costs below.) Utility Margin (Utility Operating Revenues Less Cost of Gas, Cost of Fuel and Purchased Power) Electric margin increased $9.7 million, or 5 percent, to $224.3 million for the twelve-month period in 2000 compared to the same period in 1999. Although unit prices were lower than in 1999, sales to the wholesale energy markets contributed $4.4 million of the margin increase with volumes up 39 percent for 2000 compared to 1999. Additionally, the impact of much colder temperatures on electric heating sales and a 5 percent growth in commercial customers contributed to the 2000 electric margin increase. Mild summer temperatures impacted both 2000 and 1999. Retail and firm wholesale electric sales for 2000 increased 2 percent and total electric sales increased 8 percent. Electric utility margin for the year ended December 31, 1999 was $214.6 million, compared to $208.3 million for the prior year. The $6.4 million increase in margin reflects a 5 percent increase in retail and firm wholesale electric sales primarily due to stronger industrial and commercial sales and a $1.0 million increase in margin from sales to other wholesale customers. Although sales to other wholesale customers declined 17 percent in 1999 due to milder summer temperatures which eased demand in these markets, several new sales contracts produced higher average unit sales prices to these customers. A 1 percent increase in electric generation and higher per unit coal costs resulted in a $3.5 million, or 5 percent, increase in fuel costs for electric generation for 2000 compared to the prior year. Fuel costs for electric generation increased $3.3 million, or 5 percent, in 1999. Although SIGECO's sales of electric energy to other wholesale customers are provided primarily from otherwise unutilized capacity, SIGECO's purchases of electricity from other utilities for resale to other wholesale customers typically represent the majority of SIGECO's total purchased electric energy costs. The 39 percent increase in sales to other wholesale customers combined with higher average market prices caused purchased electric energy costs to increase $15.6 million, or 75 percent, for the year ended December 31, 2000 compared to 1999. During 1999, total purchases of electric energy declined 13 percent due to the 17 percent decline in sales to wholesale customers, however higher average market prices for energy purchased resulted in total costs remaining comparable to 1998 costs. Gas margin increased $1.8 million to $30.4 million, or 6 percent, compared to the twelve-month period in 1999. The increase reflects 12 percent (4 MMDth) greater throughput (combined sales and transportation) due to much colder temperatures during 2000 than in 1999. Although temperatures were 7 percent warmer than normal for the year, temperatures during 2000 were 13 percent colder than in 1999 causing residential and commercial sales to rise 11 percent and 14 percent, respectively. In 1999, gas utility margin was $28.6 million, as compared to $27.2 million for the prior year. The 1999 increase is primarily attributable to weather being 8 percent colder than the previous year and the addition of new residential and commercial customers. Total cost of gas sold was $78.9 million in 2000 and $39.6 million in 1999 and 1998. Total cost of gas sold increased $39.3 million, or 99 percent, for the year ended December 31, 2000 compared to 1999, primarily due to significantly higher average per unit purchased gas costs. The total average cost per Dth of gas purchased was $5.09 in 2000, compared to $3.10 in 1999. The price changes are due primarily to changing commodity costs in the marketplace. Decreases in the average per unit cost of gas sold in 1999 as compared to 1998 more than offset the impact of the increased throughput, making costs of gas sold in 1999 comparable to 1998. 4 Commodity prices for natural gas purchases during the last six months of 2000 unexpectedly increased significantly, primarily due to the expectation of a colder winter, which led to increased demand and tighter supplies. SIGECO is allowed full recovery of such charges in purchased gas costs from their retail customers through commission-approved gas cost adjustment mechanisms, and margin on gas sales should not be impacted. In 2001, SIGECO may experience higher working capital requirements, increased expenses, including unrecoverable interest costs and uncollectibles, and possibly some level of price sensitive reduction in volumes sold. Operating Expenses SIGECO's operations and maintenance expenses increased $7.4 million, or 8 percent, for the year ended December 31, 2000, compared to the same period in 1999. The increase is primarily attributable to higher general and administrative costs. Operations and maintenance expenses rose $2.3 million, or 2 percent, for 1999 as compared to 1998. This increase results from increased compensation and benefits and other general operation expenses, offset by lower maintenance costs. Depreciation and amortization decreased $ 1.7 million, or 4 percent, and increased $ 2.5 million, or 6 percent, for the years ended December 31, 2000 and 1999, respectively. The decrease in 2000 is primarily attributable to the contribution of certain information systems and equipment to a wholly owned subsidiary of SIGECO's parent, Vectren Corporation. The increase in expense over 1998 reflects depreciation of normal additions of utility plant. Federal and state income taxes declined $1.6 million in 2000, compared to 1999 due primarily to $7.3 million lower pre-tax earnings, partially offset by a higher effective tax rate resulting from the non-deductibility of certain merger costs. Federal and state income taxes increased $1.4 million, or 6 percent during 1999 compared to 1998 due primarily to higher pre-tax income in 1999. Taxes other than income taxes for 2000 and 1999 were comparable to the prior periods. Merger and Integration Costs Merger and integration costs incurred for the year ended December 31, 2000 totaled $14.1 million ($11.0 million after tax). Vectren expects to realize net merger savings of nearly $200 million over the next ten years from the elimination of duplicate corporate and administrative programs and greater efficiencies in operations, business processes and purchasing. The continued merger integration activities, which will contribute to the merger savings, will be substantially completed in 2001. Merger costs are reflected in the financial statements of the operating subsidiaries in which merger savings are expected to be realized. Of the $14.1 million of merger and integration costs incurred in 2000 by SIGECO, accruals were established at March 31, 2000 totaling $7.4 million. Of this amount, $0.7 million related to employee and executive severance and $6.7 million related to transaction costs and filing fees. At December 31, 2000, the accrual remaining for such costs totaled $0.5 million, all related to severance costs. Of the total $14.1 million, the remaining $6.7 million was expensed throughout the year for accounting fees resulting from merger related filing requirements, consulting fees related to integration activities such as organization structure, employee travel between company locations as part of integration activities, internal labor of employees assigned to integration teams, and investor relations communications activities. During the merger planning process, approximately 54 positions were identified for elimination. As of December 31, 2000, approximately 35 positions had been vacated, with the remaining 19 positions to be eliminated in 2001." The integration activities experienced by the company included such things as information system consolidation, process review and definition, organization design and consolidation, and knowledge sharing. Other Income Other income increased $ 1.6 million and $.9 million, respectively, for the years ended December 31, 2000 and 1999 due primarily to increased additional funds used during construction (AFUDC) of utility plant. The increase in 1999 related to capitalized interest was partially offset by the loss of other income resulting from sales of emission allowance credits under a five year contract ending in 1998. Other income from Emission allowance credits sold in 1998 approximated $1.4 million. 5 Other Operating Matters Operation of Warrick Generating Station On August 21, 2000, SIGECO announced that no later than April 18, 2001, ALCOA, INC. (ALCOA) would begin operating the Warrick Generating Station. In 1956, arrangements were made for SIGECO to operate the Warrick Generating Station as an agent for ALCOA. Three generating units at the plant are owned by ALCOA. SIGECO owns the fourth unit equally with ALCOA. The operating change will have no impact on SIGECO's generating capacity and is not expected to have any negative impact on the company's financial results. Additionally, SIGECO will retain ALCOA as a wholesale power and transmission services customer. Transition of the plant operations was completed in March 2001. Realignment Effective January 1, 2001, the SIGECO's operations were reorganized into two primary business units, Energy Delivery and Power Supply. Environmental Matters NOx SIP Call Matter. In October 1997, the United States Environmental Protection Agency (USEPA) proposed a rulemaking that could require uniform nitrogen oxide (NOx) emissions reductions of 85 percent by utilities and other large sources in a 22-state region spanning areas in the Northeast, Midwest, Great Lakes, Mid-Atlantic and South. This rule is referred to as the "NOx SIP call". The USEPA provided each state a proposed budget of allowed NOx emissions, a key ingredient of ozone, which requires a significant reduction of such emissions. Under that budget, utilities may be required to reduce NOx emissions to a rate of 0.15 lb/mmBtu below levels already imposed by Phase I and Phase II of the Clean Air Act Amendments of 1990 (the Act). Midwestern states (the alliance) have been working together to determine the most appropriate compliance strategy as an alternative to the USEPA proposal. The alliance submitted its proposal, which calls for a smaller, phased in reduction of NOx levels, to the USEPA and the Indiana Department of Environmental Management (IDEM) in June 1998. In July 1998, Indiana submitted its proposed plan to the USEPA in response to the USEPA's proposed new NOx rule and the emissions budget proposed for Indiana. The Indiana plan, which calls for a reduction of NOx emissions to a rate of 0.25 lb/mmBtu by 2003, is less stringent than the USEPA proposal but more stringent than the alliance proposal. On October 27, 1998, 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). The final rule requires that 23 states and jurisdictions must file revised state implementation plans (SIPs) with the USEPA by no later than September 30, 1999, which was essentially unchanged from its October 1997, proposed rule. The USEPA has encouraged states to target utility coal-fired boilers for the majority of the reductions required, especially NOx emissions. Northeastern states have claimed that ozone transport from Midwestern states (including Indiana) is the primary reason for their ozone concentration problems. Although this premise is challenged by others based on various air quality modeling studies, including studies commissioned by the USEPA, the USEPA intends to incorporate a regional control strategy to reduce ozone transport. The USEPA's final ruling is being litigated in the federal courts by approximately ten Midwestern states, including Indiana. During the second quarter of 1999, the USEPA lost two federal court challenges to key air-pollution control requirements. In the first ruling by the U.S. Circuit Court of Appeals for the District of Columbia on May 14, 1999, the Court struck down the USEPA's attempt to tighten the one-hour ozone standard to an eight-hour standard and the attempt to tighten the standard for particulate emissions, finding the actions unconstitutional. In the second ruling by the same Court on May 25, 1999, the Court placed an indefinite stay on the USEPA's attempts to reduce the allowed NOx emissions rate from levels required by the Clean Air Act Amendments of 1990. The USEPA appealed both court rulings. On October 29, 1999, the Court refused to reconsider its May 14, 1999 ruling. On March 3, 2000, the D.C. Circuit of Appeals upheld the USEPA's October 27, 1998 final rule requiring 23 states and the District of Columbia to file revised SIPs with the USEPA by no later than September 30, 1999. Numerous petitioners, including several states, have filed petitions for rehearing with the U.S. Court of Appeals for the District of Columbia in Michigan v. the USEPA. On June 22, 2000, the D.C. Circuit Court of Appeals denied petition for rehearing en banc and lifted its May 25, 1999 stay. Following this decision, on August 30, 2000, the D.C. Circuit Court of Appeals issued an extension of the SIP Call implementation deadline, previously May 1, 2003, to May 31, 2004. On September 20, 2000, petitioners filed a Petition of Writ of Certiori with the United 6 States Supreme Court requesting review of the D.C. Circuit Court's March 3, 2000 Order. The Court has not yet ruled on the Petition for Certiorari. The EPA granted Section 126 Petitions filed by northeastern states that require named sources in the eastern half of Indiana to achieve NOx reduction by May 1, 2003. No SIGECO facilities are named in the Section 126 Petitions filed by northeastern states, therefore the compliance date remains May 31, 2004. The proposed NOx emissions budget for Indiana stipulated in the USEPA's final ruling requires a 36 percent reduction in total NOx emissions from Indiana. The ruling, pending finalization of state rule making, could require SIGECO to lower its system-wide emissions by approximately 70 percent. Depending on the level of system-wide emissions reductions ultimately required, and the control technology utilized to achieve the reductions, the estimated construction costs of the control equipment could reach $160 million, which are expected to be expended during the 2001-2004 period, and related additional operation and maintenance expenses could be an estimated $8 million to $10 million, annually. No accrual has been recorded by the company related to the NOx SIP Call matter. The rules governing NOx emissions, once finalized, are to be applied prospectively. Mercury Emissions. On December 14, 2000, the USEPA released a statement announcing that reductions of mercury emissions from coal-fired plants will be required in the near future. The USEPA will propose regulations by December 2003 and issue final rules by December 2004. Under the Act, the USEPA is required to study emissions from power plants in order to determine if additional regulations are necessary to protect public health. The USEPA reported its study to Congress in February 1998. That study concluded that of all toxic pollution examined, mercury posed the greatest concern to public health. An earlier USEPA study concluded that the largest source of human-made mercury pollution in the United States was coal-fired power plants. After completion of the study, the Act required the USEPA to determine whether to proceed with the development of regulations. The USEPA announced that it had affirmatively decided that mercury air emissions from power plants should be regulated. Because rules governing mercury emissions are under development, the determination of exposure, if any, is impossible as there are no standards or rules by which compliance (or lack thereof) can be measured. Accordingly, no accrual has been recorded by the company related to the Mercury Emissions matter. Culley Generating Station Investigation Matter. 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 performance standards should be applied to the modifications and whether the best available control technology was, or should have been, used. Numerous other electric utilities were, and are currently, being investigated by the USEPA under an industry-wide review for similar compliance. SIGECO responded to all of the USEPA's data requests during the investigation. 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 the 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 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: (i) making modifications to its Culley Generating Station in Yankeetown, Indiana without obtaining required permits; (ii) making major modifications to the Culley Generating Station without installing the best available emission control technology; and (iii) 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 to comply with federal new source performance standards. 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 emission 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 the lawsuit. 7 The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per violation. The lawsuit does not specify the number of days or violations the USEPA believes occurred. The lawsuit also seeks a court order requiring SIGECO to install the best available emissions technology at the Culley Generating Station. If the USEPA is successful in obtaining an order, SIGECO estimates that it would incur capital costs of approximately $40 million to $50 million complying with the order. In the event that SIGECO is required to install system-wide NOx emission control equipment, as a result of the NOx SIP call issue, the majority of the $40 million to $50 million for best available emissions technology at Culley Generating Station would be included in the $160 million expenditure previously discussed. The USEPA has also issued an administrative notice of violation to SIGECO making the same allegations, but alleging that violations began in 1977. While it is possible that SIGECO could be subjected to criminal penalties if the Culley Generating Station continues to operate without complying with the new source performance standards 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, no accrual has been recorded by the company, and SIGECO anticipates at this time that the plant will continue 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(a) of the Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO plans to provide all information requested, and management believes that no significant issues will arise from this request. As a result of the ongoing appeal of a generic order issued by the IURC in August 1999 regarding guidelines for the recovery of purchased power costs, SIGECO entered into a settlement agreement with the Indiana Office of Utility Consumer Counselor (OUCC) that provides certain terms with respect to the recoverability of such costs. The settlement, originally approved by the IURC on August 9, 2000, has been extended by agreement through March 2002. Under the settlement, SIGECO can recover the entire cost of purchased power up to an established benchmark, and during forced outages, SIGECO will bear a limited share of its purchased power costs regardless of the market costs at that time. Based on this agreement, SIGECO believes it has significantly limited its exposure to unrecoverable purchased power costs. Regulatory Matters See Note 13 in SIGECO's financial statements included in Item 8 Financial Statements and Supplementary Data regarding matters affecting operations regarding purchased power costs recovery. New Accounting Pronouncement In June 1998, the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS 133, as amended, is effective for fiscal years beginning after June 15, 2000 and must be applied to derivative instruments and certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1998. SIGECO has completed the process of identifying all derivative instruments, determining fair market values of these derivatives, designating and documenting hedge relationships, and evaluating the effectiveness of those hedge relationships. As a result of the successful completion of this process, SIGECO adopted SFAS 133 as of January 1, 2001. SFAS 133 requires that as of the date of initial adoption, the difference between the fair market value of derivative instruments recorded on the balance sheet and the previous carrying amount of those derivatives be reported in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle in accordance with APB 20, "Accounting Changes." A limited number of SIGECO's contracts are defined as derivatives under SFAS 133. These derivatives are forward physical contracts for the purchase and sale of electricity by power marketing operations. The cumulative impact of the adoption of SFAS 133 on January 1, 2001 is an earnings gain of approximately $6.3 million. 8 Liquidity and Capital Resources SIGECO's capitalization objectives are 40-55 percent permanent capitalization. This objective may have varied, and will vary, from time to time, depending on particular business opportunities and seasonal factors that affect the company's operation. SIGECO's common equity component was 52 percent of its total capitalization, including current maturities of long-term debt and adjustable rate bonds subject to tender, at December 31, 2000 and 1999. Short-term cash working capital is required primarily to finance customer accounts receivable, unbilled utility revenues resulting from cycle billing, gas in underground storage, prepaid gas delivery services, capital expenditures and investments until permanently financed. Short-term borrowings tend to be greatest during the summer when accounts receivable and unbilled utility revenues related to electricity are highest and gas storage facilities are being refilled. During 2000, however, short-term borrowings related to working capital requirements were greatest during the last six months of the year due to the higher natural gas costs. Cash Flow From Operations SIGECO's primary source of liquidity to fund working capital requirements has been cash generated from operations, which totaled approximately $66.3 million, $110.1 million and $88.4 million in 2000, 1999 and 1998 respectively. Cash provided by operations decreased during 2000 as compared to 1999 by approximately $43.8 million. The decrease is primarily attributable to merger and integration costs causing lower net income, increased recoverable fuel and natural gas costs and increased working capital requirements resulting from higher natural gas costs. The increase of 1999 cash flow from operations as compared to 1998 of approximately $21.7 million is primarily attributable to lower inventories in storage at year end and increased net income. Capital Expenditures and Other Investing Activities Cash required for investing activities was $52.7 million for the year ended December 31, 2000. This is a decrease of approximately $9.0 million over prior year due primarily to increased expenditures in 1999 for the design and implementation of several comprehensive information systems necessary to meet expanding customer needs and to better manage resources. This expenditure was also the primary reason 1999 investing activities exceeded 1998 levels. New construction and normal system improvements needed to provide service to a growing customer base will continue to require substantial capital expenditures. Additionally, during the four year period 2001 through 2004, construction costs for NOx emissions control equipment are estimated to total approximately $160 million. Capital expenditures for the five year period 2001 - 2005 are as follows (in millions): 2001 $ 96.5 2002 84.8 2003 83.4 2004 62.4 2005 73.6 ---- Total $ 400.7 The above projected expenditures include the following: - - Expenditures for NOx compliance of approximately $40 million in 2001, $30 million in 2002, $55 million in 2003 and $35 million in 2004. - - Expenditures for an 80-megawatt gas combustion turbine generator of $20 million in 2001 and $13 million in 2002. - - Expenditures for additional generation assets of approximately $40 million in 2005. Financing Activities Cash flow required for financing activities of $12.4 million for the year ended December 31, 2000 includes $16.8 million of additional net borrowings offset by $32.0 million of dividends on shares of common and preferred stock and reductions in preferred stock. 9 Cash required for financing activities in 1999 increased $16.7 million compared to 1998 requirements. The increase is primarily the result of internally generated funds used to pay down short term borrowings. The decrease in short-term borrowings was partially offset by the issuance of long term notes payable. SIGECO has $53.7 million of adjustable rate pollution control series first mortgage bonds which could, at the election of the bondholder, be tendered to SIGECO when the interest rates are reset. Prior to the latest reset on March 1, 2001, the interest rates were set annually and the bonds subject to tender were presented as current liabilities. On March 1, 2000, the interest rate on $31.5 million of Adjustable Rate Pollution Control bonds of SIGECO, due March 1, 2025, was changed from 3.00 percent to 4.30 percent. The new interest rate was fixed through February 28, 2001. Also on March 1, 2000, the interest rate on $22.2 million of Adjustable Rate Pollution Control bonds of SIGECO, due March 1, 2020, was changed from 3.05 percent to 4.45 percent. The new interest rate was also fixed through February 28, 2001. On March 1, 2001, the two series of bonds were reset for a five-year period effective on that date at 4.65 percent for the $31.5 million bonds and 5.00 percent for the $22.2 million bonds. As a result, the bonds will be presented as long-term debt going forward. SIGECO's credit rating on outstanding debt at December 31, 2000 was A/A1. At December 31, 2000, SIGECO had $63 million of short-term borrowing capacity for use in its operations, of which approximately $23 million was available. 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 statements. Certain matters described in Management's Discussion and Analysis of Financial Condition and Results of Operations, including, but not limited to, Vectren's realization of net merger savings, are forward-looking statements. Such statements are based on management's beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words "believe," "anticipate," "endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal," and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause SIGECO's actual results to differ materially from those contemplated in any forward-looking statements included, among others, the following: o Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas supply costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints. o Increased competition in the energy environment including effects of industry restructuring and unbundling. o Regulatory factors such as unanticipated changes in rate- setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases. o Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission, state public utility commissions, state entities which regulate natural gas transmission, gathering and processing, and similar entities with regulatory oversight. o Economic conditions including inflation rates and monetary fluctuations. o Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited 10 to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks. o Availability or cost of capital, resulting from changes in SIGECO, interest rates, and securities ratings or market perceptions of the utility industry and energy-related industries. o Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages. o Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures. o Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters, including, but not limited to, those described in the Other Operating Matters section of Management's Discussion and Analysis of Financial Condition and Results of Operations. o Changes in federal, state or local legislature requirements, such as changes in tax laws or rates, environmental laws and regulations. SIGECO 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. 11 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA SOUTHERN INDIANA GAS AND ELECTRIC COMPANY BALANCE SHEETS (in thousands) December 31 2000 1999 ---- ---- ASSETS Utility Plant, at original cost: Electric $1,175,552 $1,160,216 Gas 160,872 156,918 ---------- ---------- 1,336,424 1,317,134 Less: accumulated depreciation and amortization 650,499 623,611 ---------- ---------- 685,925 693,523 Construction work in progress 52,582 45,393 ---------- ---------- Net utility plant 738,507 738,916 ---------- ---------- Current Assets: Cash and cash equivalents 1,613 449 Accounts receivables, less reserves of $2,639 and $2,138, respectively 49,554 34,738 Accounts receivable from affiliated company 27,829 1,159 Accrued unbilled revenues 24,414 18,736 Inventories 31,055 41,459 Recoverable fuel and natural gas costs 28,703 5,585 Other current assets 312 5,306 ---------- ---------- Total current assets 163,480 107,432 ---------- ---------- Other Investments and Property: Environmental improvement fund held by trustee 1,056 996 Nonutility property and other, net 1,960 1,627 ---------- ---------- Total other investments and property 3,016 2,623 ---------- ---------- Other Assets: Regulatory assets 33,443 34,027 Deferred charges 12,868 11,761 ---------- ---------- Total other assets 46,311 45,788 ---------- ---------- TOTAL ASSETS $ 951,314 $ 894,759 ========== ========== The accompanying notes to financial statements are an integral part of these statements. 12 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY BALANCE SHEETS (in thousands) December 31 2000 1999 ---- ---- SHAREHOLDER'S EQUITY AND LIABILITIES Capitalization: Common Stock $ 78,258 $ 78,258 Retained Earnings 258,877 256,312 -------- -------- Total common shareholder's equity 337,135 334,570 Cumulative nonredeemable preferred stock 8,890 11,090 Cumulative redeemable preferred stock 7,500 7,500 Cumulative special preferred stock 576 692 Long-term debt, net of current maturities 237,799 238,282 -------- -------- Total capitalization, net of current maturities 591,900 592,134 -------- -------- Commitments and Contingencies Current Liabilities: Current maturities of adjustable rate bonds subject to tender 53,700 53,700 Short-term borrowings 40,154 22,880 Accounts payable to affiliated company 11,486 - Accounts payable 60,085 28,560 Dividends payable 144 117 Accrued taxes 9,956 8,408 Accrued interest 6,047 6,012 Refunds to customers 3,543 5,375 Deferred income taxes 11,295 2,427 Other accrued liabilities 14,278 14,346 -------- -------- Total current liabilities 210,688 141,825 -------- -------- Deferred Credits And Other Liabilities: Deferred income taxes 112,122 120,550 Unamortized investment tax credits 15,944 17,372 Accrued postretirement benefits other than pensions 14,054 12,041 Accrued pensions 6,310 8,360 Other 296 2,477 -------- -------- Total deferred credits and other liabilities 148,726 160,800 -------- -------- TOTAL SHAREHOLDER'S EQUITY AND LIABILITIES $951,314 $894,759 ======== ======== The accompanying notes to financial statements are an integral part of these statements. 13 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF INCOME (in thousands) Year Ended December 31 ----------- 2000 1999 1998 ---- ---- ---- OPERATING REVENUES: Electric revenues $336,409 $307,569 $297,865 Gas revenues 109,284 68,212 66,801 -------- -------- -------- Total operating revenues 445,693 375,781 364,666 -------- -------- -------- COST OF OPERATING REVENUES: Cost of fuel and purchased power 112,093 92,946 89,611 Cost of gas 78,903 39,612 39,627 -------- -------- -------- Total cost of operating revenues 190,996 132,558 129,238 -------- -------- -------- Total margin 254,697 243,223 235,428 OPERATING EXPENSES: Operations and maintenance 103,053 95,658 93,399 Merger and integration costs 14,072 - - Depreciation and amortization 43,214 44,868 42,401 Income taxes 24,832 26,428 25,035 Taxes other than income taxes 13,258 12,844 12,591 -------- -------- -------- Total operating expenses 198,429 179,798 173,426 -------- -------- -------- OPERATING INCOME 56,268 63,425 62,002 OTHER INCOME -NET 4,674 3,109 2,221 -------- -------- -------- INCOME BEFORE INTEREST AND PREFERRED STOCK DIVIDEND 60,942 66,534 64,223 INTEREST EXPENSE 19,894 19,766 20,681 -------- -------- -------- NET INCOME 41,048 46,768 43,542 PREFERRED STOCK DIVIDEND 1,017 1,078 1,095 -------- -------- -------- NET INCOME APPLICABLE TO COMMON SHAREHOLDER $ 40,031 $ 45,690 $ 42,447 ======== ======== ======== The accompanying notes to financial statements are an integral part of these statements. 14
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (in thousands) Year Ended December 31 2000 1999 1998 ---- ---- ---- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 41,048 $ 46,768 $ 43,542 Adjustments to reconcile net income to net cash Provided from operating activities: Depreciation and amortization 43,214 44,868 42,401 Deferred income taxes and investment tax credits, net 13 3,396 2,665 Allowance for other funds used during construction (2,051) (296) - Changes in assets and liabilities: Receivables, net (including accrued unbilled revenues) (47,163) (5,183) 5,152 Inventories 10,404 5,201 (12,586) Recoverable fuel costs (23,117) 346 3,198 Regulatory assets 584 1,435 970 Accounts payable 43,012 433 1,061 Accrued taxes 1,548 3,637 (1,153) Refunds to customers (1,832) 3,219 1,000 Other assets and liabilities 661 6,312 2,163 --------- --------- --------- Net cash flows from operating activities 66,321 110,136 88,413 --------- --------- --------- CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES: Retirement of long-term debt - (55,000) (14,000) Proceeds from long-term debt - 80,000 - Dividends paid (29,656) (32,380) (30,188) Reduction in preferred stock (2,316) (116) (116) Net change in short-term borrowings 16,791 (44,379) 13,588 Other 2,773 3,393 (1,065) --------- --------- --------- Net cash flows (required for) financing activities (12,408) (48,482) (31,781) --------- --------- --------- CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES: Construction expenditures (net of allowance for funds used during construction) (51,119) (60,677) (55,313) Change in nonutility property (333) (50) (25) Other (1,297) (990) (1,896) --------- --------- --------- Net cash flows (required for) investing activities (52,749) (61,717) (57,234) --------- --------- --------- Net increase (decrease) in cash and cash equivalents 1,164 (63) (602) Cash and cash equivalents at beginning of period 449 512 1,114 --------- --------- --------- Cash and cash equivalents at end of period $ 1,613 $ 449 $ 512 ========= ========= =========
The accompanying notes to financial statements are an integral part of these statements. 15 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF RETAINED EARNINGS (in thousands) December 31 ----------- 2000 1999 1998 --------- --------- --------- Balance Beginning of Period $ 256,312 $ 241,924 $ 228,570 Net Income 41,048 46,768 43,542 --------- --------- --------- 297,360 288,692 272,112 Preferred Stock Dividends 1,017 1,078 1,095 Common Stock Dividends 28,639 31,302 29,093 --------- --------- --------- 29,656 32,380 30,188 --------- --------- --------- Other 317 - - Contribution of assets to parent (9,144) - - --------- --------- --------- Balance End of Period $ 258,877 $ 256,312 $ 241,924 ========= ========= ========= The accompanying notes to financial statements are an integral part of these statements 16 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 1. Organization and Nature of Operations Southern Indiana Gas and Electric Company (SIGECO) provides generation, transmission, distribution and the sale of electric power to Evansville, Indiana, and 74 other communities, and the distribution and sale of natural gas to Evansville, Indiana, and 64 communities in ten counties in southwestern Indiana. Vectren Corporation (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), SIGECO's former parent company. On March 31, 2000, the merger of Indiana Energy with SIGCORP and into Vectren was consummated with a tax-free exchange of shares that has been accounted for as a pooling-of-interests. The merger did not affect SIGECO's preferred stock or debt securities. SIGECO operates as a separate wholly owned subsidiary of Vectren. 2. Merger and Integration Costs Merger and integration costs incurred for the year ended December 31, 2000 totaled $14.1 million. The continued merger and integration activities will be substantially completed in 2001. Merger costs are reflected in the operating subsidiaries in which merger savings are expected to be realized. Of the $14.1 million of merger and integration costs incurred in 2000 by SIGECO, accruals were established at March 31, 2000 totaling $7.4 million. Of this amount, $0.7 million related to employee and executive severance and $6.7 million related to transaction costs and filing fees. At December 31, 2000, the accrual remaining for such costs totaled $0.5 million, all related to severance costs. Of the total $14.1 million, the remaining $6.7 million was expensed throughout the year for accounting fees resulting from merger related filing requirements, consulting fees related to integration activities such as organization structure, employee travel between company locations as part of integration activities, internal labor of employees assigned to integration teams, and investor relations communications activities. During the merger planning process, approximately 54 positions were identified for elimination. As of December 31, 2000, approximately 35 positions had been vacated, with the remaining 19 positions to be eliminated in 2001." The integration activities experienced by the company included such things as information system consolidation, process review and definition, organization design and consolidation, and knowledge sharing. 3. Summary of Significant Accounting Policies A. Utility Plant and Depreciation Utility plant is stated at historical cost, including an allowance for the cost of funds used during construction. Depreciation of utility property is provided using the straight-line method over the estimated service lives of the depreciable assets. The average depreciation rates, expressed as a percentage of original cost, were 3.3 percent, 3.5 percent and 3.4 percent for the years ended December 31, 2000, 1999 and 1998, respectively. SIGECO follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When property that represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, together with the cost of removal less salvage, is charged to the accumulated provision for depreciation. 17 B. Cash Flow Information For purposes of the Statements of Cash Flows, SIGECO considers cash investments with an original maturity of three months or less to be cash equivalents. Cash paid during the periods reported for interest and income taxes were as follows: Year Ended December 31 (in thousands) 2000 1999 1998 ------- ------- ------- Cash paid during the year for Interest (net of amount capitalized) $17,506 $15,437 $18,484 Income taxes 21,627 25,476 23,789 During 2000, SIGECO contributed computer software and hardware with a book value of approximately $9.1 million to Vectren as a special dividend. This transaction resulted in no gain or loss and is omitted from the Statement of Cash Flows. C. Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, SIGECO records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period. Excise taxes are embedded in rates charged to customers. Accordingly, the company records excise tax received as a component of operating revenues. Excise taxes paid are recorded as a component of taxes other than income taxes. D. Earnings Per Share Historical earnings per share are not presented as Vectren holds the common shares of SIGECO. E. Reclassifications Certain reclassifications have been made to the prior years' financial statements to conform to the current year presentation. These reclassifications have no impact on net income previously reported. F. Inventories SIGECO accounts for inventories under the average cost method except for gas in underground storage which is accounted for under the last-in, first-out (LIFO) method. At December 31 (in thousands) 2000 1999 ------- ------- Fuel (coal and oil) for electric generation $ 4,111 $12,229 Materials and supplies 15,022 13,352 Emission allowances 3,860 4,437 Gas in underground storage - at LIFO cost 8,062 11,441 ------- ------- Total inventories $31,055 $41,459 ======= ======= Based on the average cost of gas purchased during December, the cost of replacing the current portion of gas in underground storage exceeded LIFO cost at December 31, 2000 and 1999 by approximately $35 million and $12 million, respectively. G. Refundable or Recoverable Gas Costs, Fuel for Electric Production and Purchased Power All metered gas rates contain a gas cost adjustment clause, which allows for adjustment in charges for changes in the cost of purchased gas. Metered electric rates typically contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel and the net energy cost of purchased power. SIGECO also collects through a quarterly rate adjustment mechanism the margin on electric sales lost due to the implementation of demand side management programs. SIGECO records any adjustment clause under-or-overrecovery each month in revenues. A corresponding asset or liability is recorded until such time as the under-or-overrecovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers and the cost of fuel for electric generation is charged to operating expense when consumed. 18 H. Allowance for Funds used During Construction An allowance for funds used during construction (AFUDC), which represents the cost of borrowed and equity funds used for construction purposes, is charged to construction work in progress during the period of construction and included in other - net on the Statements of Income. The table below reflects the total AFUDC capitalized and the portion of which was computed on borrowed and equity funds for all periods reported. Year Ended December 31 (in thousands) 2000 1999 1998 ------ ------ ------ AFUDC - borrowed funds $1,817 $2,508 $1,465 AFUDC - equity funds 2,051 296 - ------ ------ ------ Total AFUDC capitalized $3,868 $2,804 $1,465 ====== ====== ====== I. Income Taxes The liability method of accounting is used for income taxes under which deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities. Deferred investment tax credits are being amortized over the life of the related asset. J. Use of Estimates 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. K. Regulation SIGECO is subject to regulation by the Indiana Utility Regulatory Commission (IURC). The wholesale energy sales of SIGECO are subject to regulation by the Federal Energy Regulatory Commission (FERC). The accounting policies of SIGECO give recognition to the ratemaking and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The following regulatory assets and liabilities are reflected in the financial statements: At December 31 (in thousands) 2000 1999 ------- ------- Regulatory Assets: Demand side management programs $26,243 $25,900 Unamortized premium on reacquired debt 4,192 4,416 Unamortized debt discount and expenses 2,886 2,456 Other 122 1,255 ------- ------- Regulatory assets in other assets 33,443 34,027 Recoverable fuel and natural gas costs 28,703 5,585 ------- ------- Total regulatory assets $62,146 $39,612 ======= ======= As of December 31, 2000, the recovery of $40.7 million of SIGECO's $ 62.1 million of total regulatory assets is reflected in rates charged to customers. The remaining $21.4 million of regulatory assets, which are not yet included in rates, represent SIGECO's demand side management (DSM) costs incurred after 1993. When SIGECO files its next electric base rate case, these costs will be included in rate base and requested to earn a return. Amortization of the costs over a period anticipated to be 15 years will be recovered through rates as a cost of operations. SIGECO is currently recovering $4.8 million of DSM costs in rates. Based upon this prior regulatory authority, management believes that future recovery of the $21.4 million of regulatory assets for DSM costs is probable. 19 Of the $40.7 million of regulatory assets currently reflected in rates, a total of $9.1 million is earning a return: $4.9 million of pre-1994 DSM costs and $4.2 million of unamortized premium on reacquired debt. The remaining recovery periods for the DSM costs and premium on reacquired debt are 11.5 years and 20 years, respectively. The remaining $31.6 million of regulatory assets included in rates, but not earning a return, are being recovered over varying periods: $7.1 million of fuel costs and $21.6 million of gas costs, over 12 months; and $2.9 million of unamortized debt discount and expense to be recovered over the lives of the related issues. SIGECO's policy is to continually assess the recoverability of costs recognized as regulatory assets and the ability to continue to account for their activities in accordance with SFAS 71, based on the criteria set forth in SFAS 71. Based on current regulation, SIGECO believes such accounting is appropriate. If all or part of SIGECO's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, SIGECO would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets. L. New Accounting Pronouncement In June 1998, the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), which requires that every derivative instrument be recorded on the balance sheet as an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS 133, as amended, is effective for fiscal years beginning after June 15, 2000 and must be applied to derivative instruments and certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1998. SIGECO has completed the process of identifying all derivative instruments, determining fair market values of these derivatives, designating and documenting hedge relationships, and evaluating the effectiveness of those hedge relationships. As a result of the successful completion of this process, SIGECO adopted SFAS 133 as of January 1, 2001. SFAS 133 requires that as of the date of initial adoption, the difference between the fair market value of derivative instruments recorded on the balance sheet and the previous carrying amount of those derivatives be reported in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle in accordance with APB 20, "Accounting Changes." A limited number of SIGECO's contracts are defined as derivatives under SFAS 133. SIGECO uses derivative and non-derivative forward contracts in its power marketing operations to effectively manage the utilization of its generation capability. Certain forward sales contracts are used to sell the excess generation capacity of SIGECO when demand conditions warrant this activity. These contracts involve the normal sale of electricity and therefore do not require fair value accounting under SFAS 133. Certain forward purchase and sale contracts entered into as part of "buy-sell" transactions with other utilities and power marketers are derivatives but do not qualify for hedge accounting. The mark to market impact of these derivatives upon adoption of SFAS 133 is reflected as part of the transition adjustment recorded to earnings on January 1, 2001. The cumulative impact of the adoption of SFAS 133 on January 1, 2001 is an earnings gain of approximately $6.3 million. M. Impairment Review of Long Lived Assets Long-lived assets are reviewed for impairment in accordance with SFAS No. 121, Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, as facts and circumstances indicate that the carrying amount may be impaired. Specifically, the evaluation for impairment involves the comparison of an asset's carrying value and the estimated undiscounted future cash flows the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded as a charge to operations based on the difference between the asset's carrying amount and its fair value. 4. Preferred Stock Cumulative Preferred Stock The amount payable in the event of involuntary liquidation of each series of the $100 par value preferred stock is $100 per share, plus accrued dividends. This nonredeemable preferred stock is callable at the option of SIGECO as follows: 20 the 4.8% Series at $110 per share, plus accrued dividends; and the 4.75% Series at $101 per share, plus accrued dividends. As of December 31, 2000 and 1999, there were 85,895 shares of the 4.8% Series outstanding and 3,000 shares and 25,000 shares of the 4.75% Series outstanding, respectively. Cumulative Redeemable Preferred Stock The Series has a dividend rate of 6.50% and is redeemable at $100 per share on December 1, 2002. In the event of involuntary liquidation of this series of $100 par value preferred stock, the amount payable is $100 per share, plus accrued dividends. As of December 31, 2000 and 1999, there were 75,000 shares outstanding. Cumulative Special Preferred Stock The Cumulative Special Preferred Stock has a dividend rate of 8.5% and in the event of involuntary liquidation the amount payable is $100 per share, plus accrued dividends. This Series is callable at the option of the company at a rate of 1,160 shares per year. As of December 31, 2000 and 1999, there were 5,757 shares and 6,917 shares outstanding, respectively. 5. Long-Term Debt First mortgage bonds and notes payable outstanding and classified as long-term are as follows: At December 31 (in thousands) 2000 1999 --------- --------- First Mortgage Bonds due: 2014, 4.60% Pollution Control Series A $ 22,500 $ 22,500 Adjustable Rate Pollution Control: 2015, Series A, presently 4.55% 9,975 9,975 2016, 8.875% 13,000 13,000 2020, 4.40% Pollution Control Series B 4,640 4,640 Adjustable Rate Environmental Improvement: 2023, Series B, presently 6% 22,800 22,800 2023, 7.60% 45,000 45,000 2025, 7.625% 20,000 20,000 2029, 6.72% 80,000 80,000 2030, 4.40% Pollution Control Series B 22,000 22,000 --------- --------- Total first mortgage bonds 239,915 239,915 --------- --------- Notes Payable: Tax Exempt, due 2003, 6.25% 1,000 1,000 --------- --------- Total long-term debt outstanding 240,915 240,915 Less: Maturities and sinking fund requirements - - Unamortized debt premium and discount, net (3,116) (2,633) --------- --------- Total long-term debt and other obligations, net of current maturities $ 237,799 $ 238,282 ========= ========= Consolidated maturities and sinking fund requirements on long-term debt subject to mandatory redemption during the five years following 2000 (in millions) are $0 in 2001, $0 in 2002, $1.0 in 2003, $0 in 2004, and $0 in 2005. In addition to the obligations presented in the table above, SIGECO has $53.7 million of adjustable rate pollution control series first mortgage bonds which could, at the election of the bondholder, be tendered to SIGECO annually in March. If SIGECO's agent is unable to remarket any bonds tendered at that time, SIGECO would be required to obtain additional funds for payment to bondholders. For financial statement presentation purposes those bonds subject to tender in 2001 are shown as current liabilities. The two series of bonds will be re-set for a five-year period effective March 1, 2001. The annual sinking fund requirement of SIGECO's first mortgage bonds is 1 percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of 21 unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2001 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2001 is excluded from current liabilities on the Balance Sheets. At December 31, 2000, $220.9 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. The above debt agreements contain certain financial covenants and other restrictions with which SIGECO must comply, and SIGECO was in compliance with all financial covenants and restrictions. 6. Short-Term Borrowings At December 31, 2000, SIGECO has approximately $63 million of short-term borrowing capacity of which approximately $23 million is available for operations. See the table below for outstanding balances and interest rates. At December 31 (in thousands) 2000 1999 ---------- ---------- Notes Payable Balance at year end $ 40,154 $ 22,880 Weighted average interest rate on year end balance 7.26% 6.42% Average daily amount outstanding during the year $ 20,026 $ 54,576 Weighted average interest rate on average daily amount outstanding during the year 6.24% 5.74% 7. Income Taxes The components of income tax expense were as follows: Year Ended December 31 ( in thousands) 2000 1999 1998 -------- -------- -------- Current: Federal $ 21,754 $ 19,837 $ 19,521 State 3,065 3,195 2,849 -------- -------- -------- Total current taxes 24,819 23,032 22,370 -------- -------- -------- Deferred: Federal 1,030 4,080 3,270 State 411 746 842 -------- -------- -------- Total deferred taxes 1,441 4,826 4,112 -------- -------- -------- Amortization of Investment tax credit (1,428) (1,430) (1,447) Income tax expense $ 24,832 $ 26,428 $ 25,035 ======== ======== ======== A reconciliation of the statutory rate to the effective income tax rate is as follows: Year Ended December 31 2000 1999 1998 ------ ------ ------ Statutory federal and state rate 37.9% 37.9% 37.9% Non deductible merger costs 3.5 - - Amortization of deferred investment tax credit (2.2) (1.9) (2.1) All other, net (0.9) 0.6 1.3 ------ ------ ------ Effective tax rate 38.3% 36.6% 37.1% ------ ------ ------ Significant components of SIGECO's net deferred tax liability as of December 31, 2000 and 1999 are as follows: At December 31 (in thousands) 2000 1999 --------- --------- Deferred Tax Liabilities: Depreciation and cost recovery timing differences $ 113,075 $ 120,307 Deferred fuel costs, net 8,168 2,427 Regulatory assets recoverable through future rates 24,836 26,128 Other 3,128 - Deferred Tax Assets: Regulatory liabilities to be settled through future rates (17,654) (20,388) Other (8,136) (5,497) --------- --------- Net deferred income tax liability $ 123,417 $ 122,977 ========= ========= 22 8. Retirement Plans and Other Postretirement Benefits Prior to July 1, 2000, SIGECO and Indiana Energy had separate retirement and other postretirement benefit plans. Effective July 1, 2000, the SIGECO and Indiana Energy pension plans and retirement savings plans for employees not covered by a collective bargaining unit were merged. The pension plans and retirement savings plans described above became Vectren plans. As a result, the respective plan assets and plan obligations were transferred to Vectren. Vectren paid cash to SIGECO for assets received and received cash from SIGECO for the assumption of liabilities. The transfers resulted in no gain or loss. SIGECO has multiple defined benefit pension and other postretirement benefit plans which cover eligible full-time regular employees. All of the plans are non-contributory. The nonpension plans include plans for health care and life insurance through a combination of self-insured and fully insured plans. The IURC has authorized SIGECO to recover the costs related to postretirement benefits other than pensions under the accrual method of accounting consistent with Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Amounts accrued prior to that authorization were deferred as allowed by the IURC and amortized over a 60-month period. The detailed disclosures of benefit components that follow are based on an actuarial valuation performed for the December 31, 2000 financial statements using a measurement date as of September 30, 2000. Net periodic benefit cost consisted of the following components:
Year Ended December 31, ------------------------------- Pension Benefits Other Benefits --------------------------- -------------------------- In thousands 2000 1999 1998 2000 1999 1998 ------- ------- ------- ------- ------- ------- Service cost $ 1,907 $ 3,020 $ 2,639 $ 542 $ 620 $ 578 Interest cost 4,346 5,637 5,020 1,914 1,707 1,664 Expected return on plan assets (4,891) (6,517) (5,985) (921) (751) (577) Amortization of prior service cost 210 307 178 - - - Amortization of transitional (asset) obligation (330) (418) (418) 1,294 1,311 1,311 Recognized actuarial gain (464) (300) (47) (816) (757) (743) Settlement charge 711 - - - - - Special termination benefit charge - - - - - - ------- ------- ------- ------- ------- ------- Net periodic benefit cost $ 1,489 $ 1,729 $ 1,387 $ 2,013 $ 2,130 $ 2,233 ======= ======= ======= ======= ======= =======
A reconciliation of the plan's benefit obligations, fair value of plan assets, funded status and amounts recognized in the Balance Sheets follows:
At December 31, ------------------------------------- Benefit obligation Pension Benefits Other Benefits -------------------- -------------------- In thousands 2000 1999 2000 1999 -------- -------- -------- -------- Benefit obligation at beginning of year $ 81,702 $ 79,743 $ 24,908 $ 25,529 Service cost - benefits earned during the year 1,907 3,020 542 620 Interest cost on projected benefit obligation 4,346 5,637 1,914 1,707 Plan amendments - 33 (711) - Transfers (46,989) - - - Settlements 711 - - - Benefits paid (2,118) (3,286) (1,082) (661) Actuarial (gain) loss (610) (3,445) 111 (2,287) -------- -------- -------- -------- Benefit obligation at end of year $ 38,949 $ 81,702 $ 25,682 $ 24,908 ======== ======== ======== ========
23
Fair value of Plan Assets Pension Benefits Other Benefits -------------------- -------------------- In thousands 2000 1999 2000 1999 -------- -------- -------- -------- Plan assets at fair value at beginning of year $ 86,051 $ 83,337 $ 11,709 $ 9,511 Actual return on plan assets 5,020 6,000 595 1,434 Employer contributions - - - 1,425 Transfers (48,058) - - - Benefits paid (2,118) (3,286) (1,082) (661) -------- -------- -------- -------- Fair value of plan assets at end of year $ 40,895 $ 86,051 $ 11,222 $ 11,709 ======== ======== ======== ========
Funded Status Pension Benefits Other Benefits -------------------- --------------------- In thousands 2000 1999 2000 1999 -------- -------- ---------- --------- Funded status $ 1,946 $ 4,349 $ (14,458) $(13,199) Unrecognized transitional obligation (asset) (804) (1,398) 15,037 17,043 Unrecognized service cost 1,125 3,180 - - Unrecognized net (gain) loss and other (8,577) (14,491) (14,633) (15,885) -------- -------- ---------- --------- Net amount recognized $ (6,310) $ (8,360) $ (14,054) $(12,041) ======== ======== ========== =========
The fair value of plan assets for pension plans with benefit obligations is in excess of the benefit obligation as of December 31, 2000 and 1999. Weighted-average assumptions used in the accounting for these plans were as follows: Year Ended December 31, ---------------------------------- Pension Benefits Other Benefits ---------------- ------------------- 2000 1999 2000 1999 ------ ------ ------- ------ Discount rate 7.75% 7.50% 7.75% 7.50% Expected return on plan assets 8.50% 8.50% N/A N/A Rate of compensation increase 5.00% 5.00% N/A N/A CPI rate N/A N/A 7.00% 6.50% As of December 31, 2000, the health care cost trend is 7 percent declining to 5 percent in 2004 and remaining level thereafter. The accrued health care cost trend rate for 2001 is 7 percent. The estimated cost of these future benefits could be significantly affected by future changes in health care costs, work force demographics, interest rates or plan changes. A 1 percent change in the assumed health care cost trend for the postretirement health care plan would have the following effects: In thousands 1% Increase 1% Decrease --------- ---------- Effect on the aggregate of the service and interest cost components $ 309 $ (242) Effect on the postretirement benefit obligation 2,549 (2,038) SIGECO has adopted Voluntary Employee Beneficiary Association (VEBA) Trust Agreements for the benefit of SIGECO employees for the funding of postretirement health benefits for retirees and their eligible dependents and beneficiaries. Annual funding is discretionary and is based on the projected cost over time of benefits to be provided to cover persons consistent with acceptable actuarial methods. To the extent these postretirement benefits are funded, the benefits will not be shown as a liability on SIGECO's financial statements. 24 9. Fair Value of Financial Instruments Except for the following financial instruments, fair value of SIGECO's financial instruments is equivalent to carrying value due to their short-term nature.
At December 31 (in thousands) 2000 1999 ---------------------- --------------------- Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value --------- ---------- -------- ---------- Long-Term Debt (includes current maturities) $291,499 $326,653 $291,982 $316,535 Redeemable Preferred Stock 5,300 5,467 7,500 7,538
Certain methods and assumptions must be used to estimate the fair value of financial instruments. Because of the short maturity of notes payable, the carrying amounts approximate fair values for these financial instruments. The fair value of SIGECO's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered for debt of the same remaining maturities. The fair value of redeemable preferred stock was based on the current quoted market rate of long-term debt with similar characteristics. The market price used to value these transactions reflects management's best estimate of market prices considering various factors, including published prices for certain delivery locations, time value and volatility factors underlying the commitments. 10. Stock-Based Compensation SIGECO does not have stock-based compensation plans separate from Vectren. SIGECO's employees, officers and directors participate in Vectren's stock-based compensation plans that provide for awards of restricted stock and stock options to purchase Vectren common stock at prices equal to the fair value of the underlying shares at the date of grant. Consistent with Vectren, SIGECO accounts for participation in these plans in accordance with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations in measuring compensation costs for its stock options and discloses pro forma net income as if compensation costs had been determined consistent with the SFAS No. 123, "Accounting for Stock-based Compensation." Had compensation cost for stock options been determined consistent with SFAS No. 123 "Accounting for Stock-based Compensation," net income applicable to common shareholder would not have been materially different than reported amounts. Certain SIGECO employees held options to purchase SIGCORP common shares granted under the 1994 SIGECO Stock Option Plan and other employee compensation benefits arrangements. When the merger was consummated, each unexpired and unexercised option to purchase SIGCORP common shares was automatically converted into an option to purchase the number of Vectren common shares that could have been purchased under the original option multiplied by 1.333 (the exchange ratio in the merger between Indiana Energy, Inc. and SIGCORP). The exercise price per Vectren common share under the new option is equal to the original per share price divided by 1.333. The new Vectren options will otherwise be subject to the same terms and conditions as the original SIGCORP options. The conversion resulted in no compensation expense, as the requirements set forth in paragraph 82 of the FASB Interpretation No. 44, "Accounting for Certain Transactions Involving Stock Compensation" were met. 11. Commitments and Contingencies Vectren, through a wholly owned subsidiary, has entered into a contract to purchase and construct an 80-megawatt combustion gas turbine generator which, upon regulatory approval will be owned by SIGECO. The total capital cost of the project is estimated to be $33 million during the 2001-2002 construction period. SIGECO is party to various legal proceedings arising in the normal course of business. In the opinion of management, with the exception of the litigation matter related to the Clean Air Act (the Act), there are no legal proceedings 25 pending against SIGECO that are likely to have a material adverse effect on the financial position or results of operations. Refer to Note 12 for litigation matters concerning the Clean Air Act. 12. Environmental Matters NOx SIP Call Matter. In October 1997, the United States Environmental Protection Agency (USEPA) proposed a rulemaking that could require uniform nitrogen oxide (NOx) emissions reductions of 85 percent by utilities and other large sources in a 22-state region spanning areas in the Northeast, Midwest, Great Lakes, Mid-Atlantic and South. This rule is referred to as the "NOx SIP call". The USEPA provided each state a proposed budget of allowed NOx emissions, a key ingredient of ozone, which requires a significant reduction of such emissions. Under that budget, utilities may be required to reduce NOx emissions to a rate of 0.15 lb/mmBtu below levels already imposed by Phase I and Phase II of the Clean Air Act Amendments of 1990 (the Act). Midwestern states (the alliance) have been working together to determine the most appropriate compliance strategy as an alternative to the USEPA proposal. The alliance submitted its proposal, which calls for a smaller, phased in reduction of NOx levels, to the USEPA and the Indiana Department of Environmental Management (IDEM) in June 1998. In July 1998, Indiana submitted its proposed plan to the USEPA in response to the USEPA's proposed new NOx rule and the emissions budget proposed for Indiana. The Indiana plan, which calls for a reduction of NOx emissions to a rate of 0.25 lb/mmBtu by 2003, is less stringent than the USEPA proposal but more stringent than the alliance proposal. On October 27, 1998, 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). The final rule requires that 23 states and jurisdictions must file revised state implementation plans (SIPs) with the USEPA by no later than September 30, 1999, which was essentially unchanged from its October 1997, proposed rule. The USEPA has encouraged states to target utility coal-fired boilers for the majority of the reductions required, especially NOx emissions. Northeastern states have claimed that ozone transport from midwestern states (including Indiana) is the primary reason for their ozone concentration problems. Although this premise is challenged by others based on various air quality modeling studies, including studies commissioned by the USEPA, the USEPA intends to incorporate a regional control strategy to reduce ozone transport. The USEPA's final ruling is being litigated in the federal courts by approximately ten midwestern states, including Indiana. During the second quarter of 1999, the USEPA lost two federal court challenges to key air-pollution control requirements. In the first ruling by the U.S. Circuit Court of Appeals for the District of Columbia on May 14, 1999, the Court struck down the USEPA's attempt to tighten the one-hour ozone standard to an eight-hour standard and the attempt to tighten the standard for particulate emissions, finding the actions unconstitutional. In the second ruling by the same Court on May 25, 1999, the Court placed an indefinite stay on the USEPA's attempts to reduce the allowed NOx emissions rate from levels required by the Clean Air Act Amendments of 1990. The USEPA appealed both court rulings. On October 29, 1999, the Court refused to reconsider its May 14, 1999 ruling. On March 3, 2000, the D.C. Circuit of Appeals upheld the USEPA's October 27, 1998 final rule requiring 23 states and the District of Columbia to file revised SIPs with the USEPA by no later than September 30, 1999. Numerous petitioners, including several states, have filed petitions for rehearing with the U.S. Court of Appeals for the District of Columbia in Michigan v. the USEPA. On June 22, 2000, the D.C. Circuit Court of Appeals denied petition for rehearing en banc and lifted its May 25, 1999 stay. Following this decision, on August 30, 2000, the D.C. Circuit Court of Appeals issued an extension of the SIP Call implementation deadline, previously May 1, 2003, to May 31, 2004. On September 20, 2000, petitioners filed a Petition of Writ of Certiori with the United States Supreme Court requesting review of the D.C. Circuit Court's March 3, 2000 Order. The Court has not yet ruled on the Petition for Certiorari. The EPA granted Section 126 Petitions filed by northeastern states that require named sources in the eastern half of Indiana to achieve NOx reduction by May 1, 2003. No SIGECO facilities are named in the Section 126 Petitions filed by northeastern states, therefore the compliance date remains May 31, 2004. The proposed NOx emissions budget for Indiana stipulated in the USEPA's final ruling requires a 36 percent reduction in total NOx emissions from Indiana. The ruling, pending finalization of state rule making, could require SIGECO to lower its system-wide emissions by approximately 70 percent. Depending on the level of system-wide emissions reductions ultimately required, and the control technology utilized to achieve the reductions, the estimated construction costs of the 26 control equipment could reach $160 million, which are expected to be expended during the 2001-2004 period, and related additional operation and maintenance expenses could be an estimated $8 million to $10 million, annually. No accrual has been recorded by the company related to the NOx SIP Call matter. The rules governing NOx emissions, once finalized, are to be applied prospectively. Mercury Emissions. On December 14, 2000, the USEPA released a statement announcing that reductions of mercury emissions from coal-fired plants will be required in the near future. The USEPA will propose regulations by December 2003 and issue final rules by December 2004. Under the Act, the USEPA is required to study emissions from power plants in order to determine if additional regulations are necessary to protect public health. The USEPA reported its study to Congress in February 1998. That study concluded that of all toxic pollution examined, mercury posed the greatest concern to public health. An earlier USEPA study concluded that the largest source of human-made mercury pollution in the United States was coal-fired power plants. After completion of the study, the Act required the USEPA to determine whether to proceed with the development of regulations. The USEPA announced that it had affirmatively decided that mercury air emissions from power plants should be regulated. Because rules governing mercury emissions are under development, the determination of exposure, if any, is impossible as there are no standards or rules by which compliance (or lack thereof) can be measured. Accordingly, no accrual has been recorded by the company related to the Mercury Emissions matter. Culley Generating Station Investigation Matter. 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 performance standards should be applied to the modifications and whether the best available control technology was, or should have been, used. Numerous other electric utilities were, and are currently, being investigated by the USEPA under an industry-wide review for similar compliance. SIGECO responded to all of the USEPA's data requests during the investigation. 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 the 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 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: (i) making modifications to its Culley Generating Station in Yankeetown, Indiana without obtaining required permits; (ii) making major modifications to the Culley Generating Station without installing the best available emission control technology; and (iii) 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 to comply with federal new source performance standards. 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 emission 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 the lawsuit. The lawsuit seeks fines against SIGECO in the amount of $27,500 per day per violation. The lawsuit does not specify the number of days or violations the USEPA believes occurred. The lawsuit also seeks a court order requiring SIGECO to install the best available emissions technology at the Culley Generating Station. If the USEPA is successful in obtaining an order, SIGECO estimates that it would incur capital costs of approximately $40 million to $50 million complying with the order. In the event that SIGECO is required to install system-wide NOx emission control equipment, as a result of the NOx SIP call issue, the majority of the $40 million to $50 million for best available emissions technology at Culley Generating Station would be included in the $160 million expenditure previously discussed. 27 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 new source performance standards 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, no accrual has been recorded by the company, and SIGECO anticipates at this time that the plant will continue 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(a) of the Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO plans to provide all information requested, and management believes that no significant issues will arise from this request. 13. Rate and Regulatory Matters As a result of the ongoing appeal of a generic order issued by the IURC in August 1999 regarding guidelines for the recovery of purchased power costs, SIGECO entered into a settlement agreement with the Indiana Office of Utility Consumer Counselor (OUCC) that provides certain terms with respect to the recoverability of such costs. The settlement, originally approved by the IURC on August 9, 2000, has been extended by agreement through March 2002. Under the settlement, SIGECO can recover the entire cost of purchased power up to an established benchmark, and during forced outages, SIGECO will bear a limited share of its purchased power costs regardless of the market costs at that time. Based on this agreement, SIGECO believes it has significantly limited its exposure to unrecoverable purchased power costs. 14. Affiliate Transactions Vectren and certain subsidiaries of Vectren have provided certain corporate general and administrative services to the company including legal, finance, tax, risk management and human resources. The costs have been allocated to SIGECO using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are based on cost. Management believes that the allocation methodology is reasonable and approximates the costs that would have been incurred had SIGECO secured those services on a stand-alone basis. SIGECO received corporate allocations totaling $30.0 million for the year ended December 31, 2000. No amounts were charged in 1999 and 1998 as such services were provided by SIGECO personnel during those periods. Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases fuel used for electric generation. Amounts paid for such purchases for the years ended December 31, 2000, 1999 and 1998 totaled $25.7 million $20.5 million and $16.8 million, respectively. Amounts charged by Vectren Fuels, Inc. are market based. The Company incurred approximately $171,000 in 2000 for janitorial services provided by an entity owned by a relative of a director of the Company. As of December 31, Amounts owed to unconsolidated affiliates totaled $11.5 million and $0 at December 31, 2000 and 1999, respectively. Amounts due from unconsolidated affiliates totaled $27.8 million and $1.2 million at December 31, 2000 and 1999, respectively. 15. Segment Reporting SFAS No. 131 "Disclosures about Segments of an Enterprise and Related Information" establishes standards for reporting information about operating segments in financial statements and disclosures about products and services and geographic areas. Operating segments are defined as components of an enterprise for which separate financial information is available and is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. During 2000, SIGECO had two operating segments: (1) Electric Utility Services and (2) Gas Utility Services. The Electric Utility Services segment generates, transmits, distributes and sells electricity to Evansville, Indiana, and 74 28 other cities, towns and communities, and adjacent rural areas; and in periods of under utilized capacity, excess electricity is sold to other wholesale customers, cities and municipalities. The Gas Utility Services segment distributes, transports and sells natural gas to Evansville, Indiana and 64 communities in ten counties in southwestern Indiana. Certain financial information relating to significant segments of business is presented below:
Year Ended December 31 (in thousands) 2000 1999 1998 --------- --------- --------- Operating revenues: Electric Utility Services $ 336,409 $ 307,569 $ 297,865 Gas Utility Services 109,284 68,212 66,801 --------- --------- --------- Total $ 445,693 $ 375,781 $ 364,666 --------- --------- --------- Interest expense: Electric Utility Services $ 18,103 $ 18,031 $ 18,882 Gas Utility Services 1,791 1,735 1,799 --------- --------- --------- Total $ 19,894 $ 19,766 $ 20,681 --------- --------- --------- Income taxes: Electric Utility Services $ 23,386 $ 24,331 $ 22,881 Gas Utility Services 1,446 2,097 2,154 --------- --------- --------- Total $ 24,832 $ 26,428 $ 25,035 --------- --------- --------- Net Income applicable to common shareholder: Electric Utility Services $ 36,811 $ 41,820 $ 38,342 Gas Utility Services 3,220 3,870 4,105 --------- --------- --------- Total $ 40,031 $ 45,690 $ 42,447 --------- --------- --------- Depreciation and amortization: Electric Utility Services $ 38,639 $ 40,829 $ 38,077 Gas Utility Services 4,575 4,039 4,324 --------- --------- --------- Total $ 43,214 $ 44,868 $ 42,401 --------- --------- --------- Capital Expenditures: Electric Utility Services $ 43,520 $ 51,080 $ 47,114 Gas Utility Services 9,650 9,893 8,199 Equity component of AFUDC (2,051) (296) --------- --------- --------- Total $ 51,119 $ 60,677 $ 55,313 --------- --------- --------- Identifiable assets: Electric Utility Services $ 799,104 $ 751,598 $ 740,746 Gas Utility Services 152,210 143,161 141,174 --------- --------- --------- Total assets $ 951,314 $ 894,759 $ 881,920 ========= ========= =========
16. Other Income-Net For the years ended December 31, 2000, 1999 and 1998, other income, net consists of the following: (In thousands) 2000 1999 1998 ------- ------- ------- AFUDC $ 3,868 $ 2,804 $ 1,465 Other income 1,484 408 2,309 Other expense (678) (103) (1,553) ------- ------- ------- Other income, net $ 4,674 $ 3,109 $ 2,221 ======= ======= ======= 29 17. Selected Quarterly Financial Data (Unaudited) (1) 2000 - ------------- In thousands Q1 Q2 Q3 Q4 -------- -------- -------- -------- Operating revenues $102,217 $ 92,471 $112,675 $138,330 Operating income (2) 8,350 10,700 20,867 16,351 Net income (2) 3,998 6,459 16,782 12,792 1999 - ------------- In thousands Q1 Q2 Q3 Q4 -------- -------- -------- -------- Operating revenues $100,685 $ 84,318 $101,930 $ 88,848 Operating income 17,147 12,338 21,219 12,721 Net income 12,237 7,617 17,601 8,235 (1) Information in any one quarterly period is not indicative of annual results due to seasonal variations common to the utility industry. (2) Includes merger and integration charges. See Note 2. 30 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The management of Southern Indiana Gas and Electric Company (SIGECO) is responsible for the preparation of the financial statements and the related financial data contained in this report. The financial statements are prepared in conformity with accounting principles generally accepted in the United States and follow accounting policies and principles applicable to regulated public utilities. The integrity and objectivity of the data in this report, including required estimates and judgments, are the responsibility of management. Management maintains a system of internal control and utilizes an internal auditing program to provide reasonable assurance of compliance with company policies and procedures and the safeguard of assets. The board of directors of SIGECO's parent company, Vectren Corporation, pursues its responsibility for these financial statements through its audit committee, which meets periodically with management, the internal auditors and the independent auditors, to assure that each is carrying out its responsibilities. Both the internal auditors and the independent auditors meet with the audit committee of Vectren's board of directors, with and without management representatives present, to discuss the scope and results of their audits, their comments on the adequacy of internal accounting control and the quality of financial reporting. /s/ J. Gordon Hurst J. Gordon Hurst President January 24, 2001. 31 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholder and Board of Directors of Southern Indiana Gas and Electric Company: We have audited the accompanying balance sheets of Southern Indiana Gas and Electric Company (an Indiana corporation) as of December 31, 2000 and 1999, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 2000. These financial statements and the schedule referred to below are the responsibility of Southern Indiana Gas and Electric Company's management. Our responsibility is to express an opinion on these financial statements and the schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southern Indiana Gas and Electric Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed under Item 14(a) (2) is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. The schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ Arthur Andersen LLP Arthur Andersen LLP Indianapolis, Indiana, January 24, 2001. 32 ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a)(1) Financial Statements Financial statements filed as part of this Form 10-K are included under Part II, Item 8. (a)(2) Financial Statement Schedules: PAGES IN FORM 10-K/A -------------------- Report of Independent Accountants 32 For the years ended December 31, 2000, 1999, and 1998: Schedule II - Valuation and Qualifying Accounts 34 All other schedules are omitted as the required information is inapplicable or the information is presented in the Financial Statements or related notes. 33 SCHEDULE II
Southern Indiana Gas And Electric Company VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E - -------- -------- ------------------ -------- -------- Additions Balance Charged Charged Deductions Balance Beginning to to Other from End of Description of Year Expenses Accounts Reserves, Net Year - ----------- -------- -------- -------- --------- ------ (in thousands) VALUATION AND QUALIFYING ACCOUNTS: Year 2000 - Accumulated Provision for uncollectible Accounts $2,138 $1,189 $ - $ 688 $2,639 Year 1999 - Accumulated Provision for uncollectible Accounts $2,156 $ 604 $ - $ 622 $2,138 Year 1998 - Accumulated Provision for uncollectible Accounts $ 328 $2,797 $ - $ 969 $2,156 OTHER RESERVES: Year 2000 - Reserve for Merger and integration costs $ - $7,400 $ - $6,874 $ 526 Year 2000 - Reserve for Injuries and damages $1,047 $ 351 $ - $ 374 $1,024 Year 1999 - Reserve for Injuries and damages $ 782 $ 661 $ - $ 396 $1,047 Year 1998 - Reserve for Injuries and damages $1,047 $ 68 $ 261 $ 594 $ 782
34 (a)(3) EXHIBITS Exhibits for the company are listed in the Index to Exhibits beginning on page 37. (b) REPORTS ON FORM 8-K On December 15, 2000, Southern Indiana Gas and Electric Company filed a Current Report on Form 8-K with respect to providing an update on potential impact of Increased Gas Costs and Gas Cost Adjustment Proceedings. Items reported include: Item 5. Other Events 35 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 Dated August 27, 2001 /S/ Niel C. Ellerbrook -------------------------------- Niel C. Ellerbrook, Chairman and Chief Executive Officer 36 INDEX TO EXHIBITS EX - 3.1 Amended Articles of Incorporation as amended March 26, 1985. (Filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 3-A.) Articles of Amendment of the Amended Articles of Incorporation, dated March 24, 1987. (Filed and designated in Form 10-K for the fiscal year 1987, File No. 1-3553, as Exhibit 3-A.) Articles of Amendment of the Amended Articles of Incorporation, dated November 27, 1992. (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 3-A) EX - 3.2 By-Laws as amended through December 18, 1990. (Filed in Form 10-K for the fiscal year 1990, File No. 1-3553, as Exhibit 3-B.) By-Laws as amended through September 22, 1993. (Filed and designated in Form 10-K for the fiscal year 1993, File No. 1-3553, as EX-3 (b).) By-Laws as amended through January 1, 1995. (Filed and designated in Form 10-K for the fiscal year 1995, File No. 1-3553, as EX-3(b).) EX - 4.1 Mortgage and Deed of Trust dated as of April 1, 1932 between Southern Indiana Gas and Electric Company and Bankers Trust Company, as Trustee, and Supplemental Indentures thereto dated August 31, 1936, October 1, 1937, March 22, 1939, July 1, 1948, June 1, 1949, October 1, 1949, January 1, 1951, April 1, 1954, March 1, 1957, October 1, 1965, September 1, 1966, August 1, 1968, May 1, 1970, August 1, 1971, April 1, 1972, October 1, 1973, April 1, 1975, January 15, 1977, April 1, 1978, June 4, 1981, January 20, 1983, November 1, 1983, March 1, 1984, June 1, 1984, November 1, 1984, July 1, 1985, November 1, 1985, June 1, 1986. (Filed and designated in Registration No. 2-2536 as Exhibits B-1 and B-2; in Post-effective Amendment No. 1 to Registration No. 2-62032 as Exhibit (b)(4)(ii), in Registration No. 2-88923 as Exhibit 4(b)(2), in Form 8-K, File No. 1-3553, dated June 1, 1984 as Exhibit (4), File No. 1-3553, dated March 24, 1986 as Exhibit 4-A, in Form 8-K, File No. 1-3553, dated June 3, 1986 as Exhibit (4).) July 1, 1985 and November 1, 1985 (Filed and designated in Form 10-K, for the fiscal year 1985, File No. 1-3553, as Exhibit 4-A.) November 15, 1986 and January 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1986, File No. 1-3553, as Exhibit 4-A.) December 15, 1987. (Filed and designated in Form 10-K, for the fiscal year 1987, File No. 1-3553, as Exhibit 4-A.) December 13, 1990. (Filed and designated in Form 10-K, for the fiscal year 1990, File No. 1-3553, as Exhibit 4-A.) April 1, 1993. (Filed and designated in Form 8-K, dated April 13, 1993, File 1-3553, as Exhibit 4.) June 1, 1993 (Filed and designated in Form 8-K, dated June 14, 1993, File 1-3553, as Exhibit 4.) May 1, 1993. (Filed and designated in Form 10-K, for the fiscal year 1993, File No. 1-3553, as Exhibit 4(a).) July 1, 1999. (Filed and designated in Form 10-Q, dated August 16, 1999, File 1-3553, as Exhibit 4(a).) EX - 10.1 Agreement, dated, January 30, 1968, for Unit No. 4 at the Warrick Power Plant of Alcoa Generating Corporation ("Alcoa"), between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Registration No. 2-29653 as Exhibit 4(d)-A.) EX - 10.2 Letter of Agreement, dated June 1, 1971, and Letter Agreement, dated June 26, 1969, between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Registration No. 2-41209 as Exhibit 4(e)-2.) EX - 10.3 Letter Agreement, dated April 9, 1973, and Agreement dated April 30, 1973, between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Registration No. 2-53005 as Exhibit 4(e)-4.) EX - 10.4 Electric Power Agreement (the "Power Agreement"), dated May 28, 1971, between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Registration No. 2-41209 as Exhibit 4(e)-1.) EX - 10.5 Second Supplement, dated as of July 10, 1975, to the Power Agreement and Letter Agreement dated April 30, 1973 - First Supplement. (Filed and designated in Form 10-K for the fiscal year 1975, File No. 1-3553, as Exhibit 1(e).) EX - 10.6 Third Supplement, dated as of May 26, 1978, to the Power Agreement. (Filed and designated in Form 10-K for the fiscal year 1978 as Exhibit A-1.) 37 EX - 10.7 Letter Agreement dated August 22, 1978 between Southern Indiana Gas and Electric Company and Alcoa, which amends Agreement for Sale in an Emergency of Electrical Power and Energy Generation by Alcoa and Southern Indiana Gas and Electric Company dated June 26, 1979. (Filed and designated in Form 10-K for the fiscal year 1978, File No. 1-3553, as Exhibit A-2.) EX - 10.8 Fifth Supplement, dated as of December 13, 1978, to the Power Agreement. (Filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-3.) EX - 10.9 Sixth Supplement, dated as of July 1, 1979, to the Power Agreement. (Filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-5.) EX - 10.10 Seventh Supplement, dated as of October 1, 1979, to the Power Agreement. (Filed and designated in Form 10-K for the fiscal year 1979, File No. 1-3553, as Exhibit A-6.) EX - 10.11 Eighth Supplement, dated as of June 1, 1980 to the Electric Power Agreement, dated May 28, 1971, between Alcoa and Southern Indiana Gas and Electric Company. (Filed and designated in Form 10-K for the fiscal year 1980, File No. 1-3553, as Exhibit (20)-1.) EX - 10.12 Summary description of Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-17.) EX - 10.13 Supplemental Post Retirement Death Benefits Plan, dated October 10, 1984. (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-18.) EX - 10.14 Summary description of Southern Indiana Gas and Electric Company's Corporate Performance Incentive Plan. (Filed and designated in Form 10-K for the fiscal year 1992, File No. 1-3553, as Exhibit 10-A-19.) EX - 10.15 Southern Indiana Gas and Electric Company's Corporate Performance Incentive Plan as amended for the plan year beginning January 1, 1994. (Filed and designated in Form 10-K for the fiscal year 1993, File No. 1-3553, as Exhibit 10-A-20.) EX - 10.16 Southern Indiana Gas and Electric Company 1994 Stock Option Plan (Filed and designated in Southern Indiana Gas and Electric Company's Proxy Statement dated February 22, 1994, File No. 1-3553, as Exhibit A.) EX - 10.17 Summary description of Southern Indiana Gas and Electric Company's Corporate Performance Incentive Plan as amended for the plan year beginning January 1, 1997. (Filed and designated in the SIGCORP, Inc. and Southern Indiana Gas and Electric Company's Joint Proxy Statement dated March 23, 1998, File No. 1-11603 and File No. 1-3553, under "Compensation Committee Report On Executive Compensation", page 9.) EX - 10.18 Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan as amended, effective April 16, 1997. (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.) EX - 10.19 Agreement dated April 16, 1997 between Southern Indiana Gas and Electric Company and Ronald G. Reherman regarding supplemental pension and disability benefits, which supercedes such agreement dated February 1, 1995. (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.27.) EX - 10.20 Southern Indiana Gas and Electric Company's nonqualified Supplemental Retirement Plan as amended, effective April 16, 1997. (Filed and designated in Form 10-K for the fiscal year 1997, File No. 1-3553, as Exhibit 10.29.) 38 EX - 10.21 Indiana Energy, Inc. Director's Restricted Stock Plan as amended and restated effective May 1, 1997. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 1997, File 1-9091, as Exhibit 10-B.) EX - 10.22 First Amendment to Indiana Energy, Inc. Director's Restricted Stock Plan, effective December 1, 1998. (Filed and designated in Form 10-Q for the quarterly period ended December 31, 1998, File 1-9091, as Exhibit 10-J.) EX - 10.23 Second Amendment to Indiana Energy, Inc. Director's Restricted Stock Plan, renamed the Vectren Corporation Directors Restricted Stock Plan effective October 1, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2000, File No. 1-15467, as Exhibit 10.34.) EX - 10.24 Third Amendment to Indiana Energy, Inc. Director's Restricted Stock Plan, renamed the Vectren Corporation Directors Restricted Stock Plan effective March 28, 2000. (Filed and designated in Form 10-K for the year ended December 31, 2000, File No. 1-15467, as Exhibit 10.35.) EX - 10.25 Vectren Corporation Retirement Savings Plan. (Filed and designated in Form 10-Q for the quarterly period ended September 30, 2000, File 1-15467, as Exhibit 99.1.) EX - 10.26 Vectren Corporation Combined Non-Bargaining Retirement Plan. (Filed and designated in Form 10-Q for the quarterly period ended September 30, 2000, File 1-15467, as Exhibit 99.2.) EX - 10.27 Vectren Corporation Employment Agreement between Vectren Corporation and Niel C. Ellerbrook dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File 1-15467, as Exhibit 99.1.) EX - 10.28 Vectren Corporation Employment Agreement between Vectren Corporation and Andrew E. Goebel dated as of March 31, 2000(Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File 1-15467, as Exhibit 99.2.) EX - 10.29 Vectren Corporation Employment Agreement between Vectren Corporation and Jerome A. Benkert, Jr. dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File 1-15467, as Exhibit 99.3.) EX - 10.30 Vectren Corporation Employment Agreement between Vectren Corporation and Ronald E. Christian dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File 1-15467, as Exhibit 99.5.) EX - 10.31 Vectren Corporation Employment Agreement between Vectren Corporation and Timothy M. Hewitt dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File 1-15467, as Exhibit 99.6.) EX - 10.32 Vectren Corporation Employment Agreement between Vectren Corporation and J. Gordon Hurst dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File 1-15467, as Exhibit 99.7.) EX - 10.33 Vectren Corporation Employment Agreement between Vectren Corporation and Richard G. Lynch dated as of March 31, 2000. (Filed and designated in Form 10-Q for the quarterly period ended June 30, 2000, File 1-15467, as Exhibit 99.8.) EX - 12 Ratio of Ratio of Earning to Fixed Charges. (Filed and designated in Form 10-K for the year ended December 31, 2000, File 1-15467, as Exhibit 12.) EX - 99.1 Vectren Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934, but not including the Compensation Committee Report and Performance Graph. (Filed and designated in Form 10-K for the year ended December 31, 2000, File 1-15467, as Exhibit 99.1.) 39 EX - 99.2 Agreement and Plan of Merger dated as of June 11,1999 among Indiana Energy, Inc., SIGCORP, Inc. and Vectren Corporation (the "Merger Agreement "). (Filed and designated in Form S-4 to (No. 333-90763) filed on November 12, 1999, File 1-15467, as Exhibit 2.) EX - 99.3 Amendment No. 1 to the Merger Agreement dated December 14,1999 (Filed and designated in Current Report on Form 8-K filed December 16, 1999, File 1-09091, as Exhibit 2.) EX - 99.4 Amended and Restated Articles of Incorporation of Vectren Corporation effective March 31,2000. (Filed and designated in Current Report on Form 8-K filed April 12, 2000, File 1-15467, as Exhibit 4.1.) EX - 99.5 Code of By-Laws of Vectren Corporation. (Filed and designated in Form S-3 (No 333-5390) filed January 19, 2001, File 1-15467, as Exhibit 4.2.) EX - 99.6 Shareholders Rights Agreement dated as of October 21, 1999 between Vectren Corporation and Equiserve Trust Company, N.A., as Rights Agent. (Filed and designated in Form S-4 to (No. 333-90763) filed on November 12, 1999, File 1-15467, as Exhibit 4.) -----END PRIVACY-ENHANCED MESSAGE-----