10-Q/A 1 sig10q-a_mar01.txt FORM 10-Q AMENDMENT NO. 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q/A Amendment No. 1 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For quarterly period ended March 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------------- ----------------- Commission file number 1-3553 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY ------------------------------------------ (Exact name of registrant as specified in its charter) INDIANA 35-0672570 (State or other jurisdiction of (I.R.S Employer incorporation or organization) Identification No.) 20 N.W. Fourth Street, Evansville, Indiana 47741 (Address of principal executive offices and Zip Code) (812) 491-4000 --------------- (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock -Without par value 15,754,826 May 10, 2001 ----------------------------------- ---------------- ---------------- Class Number of shares Date 2 TABLE OF CONTENTS Item Page Number Number 1 Financial Statements (Unaudited) Southern Indiana Gas and Electric Company Condensed Balance Sheets 3-4 Condensed Statements of Operations 5 Condensed Statements of Cash Flows 6 Notes to Condensed Unaudited Financial Statements 7-13 2 Management's Discussion and Analysis of Results of Operations and Financial Condition 14-20 Signatures 21 3 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEETS (Unaudited - Thousands) March 31, ----------------------- December 31, ASSETS 2001 2000 2000 ------ ---------- ---------- ---------- Utility Plant at original cost: Electric $1,171,020 $1,142,496 $1,175,552 Gas 159,723 157,258 160,872 ---------- ---------- ---------- 1,330,743 1,299,754 1,336,424 Less: accumulated depreciation and amortization 661,008 626,545 650,499 ---------- ---------- ---------- 669,735 673,209 685,925 Construction work in progress 57,646 55,909 52,582 ---------- ---------- ---------- Net utility plant 727,381 729,118 738,507 ---------- ---------- ---------- Current Assets: Cash and cash equivalents 3,687 2,147 1,613 Accounts receivable, less reserves of $2,409, 2,262 and $2,639, respectively 56,571 34,743 49,554 Accounts receivable from affiliated company 9,872 8,183 27,829 Accrued unbilled revenues 11,370 12,522 24,414 Inventories 27,399 31,657 31,055 Recoverable fuel and natural gas costs 35,996 6,210 28,703 Other current assets 14 2,239 312 ---------- ---------- ---------- Total current assets 144,909 97,701 163,480 ---------- ---------- ---------- Other Investments and Property: Environmental improvement funds held by trustee 1,057 1,010 1,056 Nonutility property and other, net 2,924 2,924 1,960 ---------- ---------- ---------- Total other investments and property 3,981 3,934 3,016 ---------- ---------- ---------- Other Assets: Regulatory assets 33,445 33,636 33,443 Deferred charges, net 27,815 14,012 12,868 ---------- ---------- ---------- Total other assets 61,260 47,648 46,311 ---------- ---------- ---------- TOTAL ASSETS $ 937,531 $ 878,401 $ 951,314 ========== ========== ==========
The accompanying notes are an integral part of these condensed financial statements. 4
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED BALANCE SHEETS (Unaudited - Thousands) March 31, ------------------- December 31, SHAREHOLDER'S EQUITY AND LIABILITIES 2001 2000 2000 ------------------------------------ -------- -------- -------- Capitalization: Common stock $ 78,258 $ 78,258 $ 78,258 Retained earnings 263,405 239,653 258,877 -------- -------- -------- Total common shareholder's equity 341,663 317,911 337,135 Cumulative nonredeemable preferred stock 8,852 11,090 8,890 Cumulative redeemable preferred stock 7,500 7,500 7,500 Cumulative special preferred stock 460 576 576 Long-term debt, net of current maturities 291,550 237,602 237,799 -------- -------- -------- Total capitalization, net of current maturities 650,025 574,679 591,900 -------- -------- -------- Commitments and Contingencies (Notes 6 and 7) Current Liabilities: Current maturities of adjustable rate bonds subject to tender - 53,700 53,700 Short-term borrowings 14,828 10,318 40,154 Notes payable to affiliated company 25,000 - - Accounts payable to affiliated company 6,266 6,468 11,486 Accounts payable 40,578 26,550 60,085 Dividends payable 142 103 144 Accrued taxes 23,246 18,757 9,956 Accrued interest 5,327 5,038 6,047 Refunds to customers 4,229 1,863 3,543 Deferred income taxes 10,271 1,483 11,295 Other accrued liabilities 5,225 19,201 14,278 -------- -------- -------- Total current liabilities 135,112 143,481 210,688 -------- -------- -------- Deferred Credits and Other Liabilities: Deferred income taxes 112,145 119,421 112,122 Unamortized investment tax credits 15,606 17,015 15,944 Accrued postretirement benefits other than pensions 14,554 12,889 14,054 Accrued pensions 6,668 8,862 6,310 Other 3,421 2,054 296 -------- -------- -------- Total deferred credits and other liabilities 152,394 160,241 148,726 -------- -------- -------- TOTAL SHAREHOLDER'S EQUITY AND LIABILITIES $937,531 $878,401 $951,314 ======== ======== ========
The accompanying notes are an integral part of these condensed financial statements. 5
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF OPERATIONS (Unaudited - Thousands) Three Months Twelve Months Ended March 31, Ended March 31, ------------------- ------------------- 2001 2000 2001 2000 -------- -------- -------- -------- OPERATING REVENUES: Electric revenues $ 88,209 $ 72,990 $351,628 $309,572 Gas revenues 51,950 29,227 132,007 67,741 -------- -------- -------- -------- Total operating revenues 140,159 102,217 483,635 377,313 -------- -------- -------- -------- COST OF OPERATING REVENUES: Cost of fuel and purchased power 31,137 21,678 121,552 94,494 Cost of gas 41,458 19,634 100,727 39,741 -------- -------- -------- -------- Total cost of operating revenues 72,595 41,312 222,279 134,235 -------- -------- -------- -------- Total margin 67,564 60,905 261,356 243,078 OPERATING EXPENSES: Operations and maintenance 23,441 21,238 105,256 94,667 Merger and integration costs 388 12,357 2,103 12,357 Depreciation and amortization 11,084 11,490 42,808 45,140 Income taxes 9,041 4,237 29,636 23,334 Taxes other than income taxes 3,626 3,233 13,651 12,951 -------- -------- -------- -------- Total operating expenses 47,580 52,555 193,454 188,449 -------- -------- -------- -------- OPERATING INCOME 19,984 8,350 67,902 54,629 OTHER INCOME-NET 859 699 4,834 3,416 -------- -------- -------- -------- INCOME BEFORE INTEREST AND PREFERRED STOCK DIVIDEND 20,843 9,049 72,736 58,045 INTEREST EXPENSE 5,256 4,783 20,367 19,518 -------- -------- -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 15,587 4,266 52,369 38,527 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE-NET OF TAX 3,938 - 3,938 - -------- -------- -------- -------- NET INCOME 19,525 4,266 56,307 38,527 PREFERRED STOCK DIVIDEND 238 268 987 1,076 -------- -------- -------- -------- NET INCOME APPLICABLE TO COMMON SHAREHOLDER $ 19,287 $ 3,998 $ 55,320 $ 37,451 ======== ======== ======== ========
The accompanying notes are an integral part of these condensed financial statements. 6
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited - Thousands) Three Months Twelve Months Ended March 31, Ended March 31, --------------------- -------------------- CASH FLOWS FROM OPERATING ACTIVITIES 2001 2000 2001 2000 -------- -------- -------- -------- Net income $ 19,525 $ 4,266 $ 56,307 $ 38,527 Adjustments to reconcile net income to cash provided from operating activities - Depreciation and amortization 11,084 11,490 42,808 45,140 Deferred income taxes and investment tax credits (519) (2,430) 1,924 1,123 Allowance for funds used during construction (329) - (2,380) (296) Cumulative effect of accounting change (3,938) - (3,938) - Unrealized gain on derivatives (5,498) - (5,498) - Changes in assets and liabilities - Receivables - net 23,984 (1,927) (21,252) (8,162) Inventories 3,656 9,802 4,258 10,246 Recoverable fuel and natural gas costs (7,293) (625) (29,785) (1,741) Regulatory assets (2) (843) 1,425 (222) Accounts payable (24,727) (235) 18,520 7,292 Accrued taxes 8,849 9,961 436 3,306 Refunds to customers 686 (3,512) 2,366 (1,610) Other assets and liabilities (4,488) 6,377 (10,204) 5,869 -------- -------- -------- -------- Total adjustments 1,465 28,058 (1,320) 60,945 -------- -------- -------- -------- Net cash flows from operating activities 20,990 32,324 54,987 99,472 -------- -------- -------- -------- CASH FLOWS (REQUIRED FOR) FINANCING ACTIVITIES Retirement of preferred stock (153) (117) (2,352) (116) Proceeds from long-term debt - - - 25,000 Net change in short-term borrowings and notes payable to affiliated company (275) (6,412) 22,928 (72,483) Dividends on common and preferred stock (8,842) (8,793) (29,705) (32,556) Other - (72) 2,844 3,144 -------- -------- -------- -------- Net cash flows (required for) financing activities (9,270) (15,394) (6,285) (77,011) -------- -------- -------- -------- CASH FLOWS (REQUIRED FOR) INVESTING ACTIVITIES Capital expenditures (8,595) (14,944) (45,103) (61,681) Other (1,051) (288) (2,059) (1,345) -------- -------- -------- -------- Net cash flows (required for) investing activities (9,646) (15,232) (47,162) (63,026) -------- -------- -------- -------- Net increase (decrease) in cash 2,074 1,698 1,540 (40,565) Cash and cash equivalents at beginning of period 1,613 449 2,147 42,712 -------- -------- -------- -------- Cash and cash equivalents at end of period $ 3,687 $ 2,147 $ 3,687 $ 2,147 ======== ======== ======== ========
The accompanying notes are an integral part of these condensed financial statements. 7 SOUTHERN INDIANA GAS AND ELECTRIC COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) 1. Organization and Nature of Operations Southern Indiana Gas and Electric Company (SIGECO) operates as a separate wholly owned subsidiary of Vectren Corporation (Vectren) and 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 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. 2. Basis of Presentation The interim condensed financial statements included in this report have been prepared by SIGECO, without audit, as provided in the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted as provided in such rules and regulations. SIGECO believes that the information in this report reflects all adjustments necessary to fairly state the results of the interim periods reported. These condensed financial statements and related notes should be read in conjunction with SIGECO's audited annual financial statements for the year ended December 31, 2000 filed on Form 10-K. Because of the seasonal nature of SIGECO's operations, the results shown on a quarterly basis are not necessarily indicative of annual results. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications have been made to prior period financial statements to conform with the current year classification. These reclassifications have no impact on previously reported net income. 3. Merger and Integration Costs Merger and integration costs incurred for the three and twelve months ended March 31, 2001 were $0.4 million and $2.1 million, respectively. Merger costs are reflected in the financial statements of the subsidiaries in which merger savings are expected to be realized. The continued merger integration activities will be completed in 2001. Since March 31, 2000, $14.5 has been expensed associated with merger and integration activities. Accruals were established at March 31, 2000 totaling $7.4 million. Of this amount, $0.7 million related to employee and executive 8 severance and $6.7 million related to transaction costs and filing fees. At March 31, 2001, the accrual remaining for such costs totaled $0.4 million, all related to severance costs. Of the $14.5 million expensed, the remaining $7.1 million was expensed through March 31, 2001 ($6.7 million in 2000 and $0.4 in 2001) 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. 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. 4. Long - Term Debt 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 reset annually, and the bonds subject to tender were presented in the Balance Sheets as current liabilities. Effective March 1, 2001, the bonds were reset for a five-year period and have been classified as long-term debt. Resulting from the reset, the interest rate on the $31.5 million Series A bonds increased from 4.30 % to 4.75 %, and the interest rate on the $22.2 million Series C bonds increased from 4.45 % to 5.00 %. 5. New Accounting Principle 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 both the purchase and sale of electricity. SIGECO uses derivative and non-derivative forward contracts in its power marketing operations to effectively manage the utilization of its generation capacity. Certain forward sales contracts are used to sell the excess generation 9 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. This cumulative impact is an earnings gain of approximately $6.3 million ($3.9 million after tax). As of March 31, 2001, the fair value of power marketing derivative contracts total $11.8 million and is included in deferred charges, net in the Condensed Balance Sheets. The difference between the current market value and the market value on the date of adoption of $5.5 million is reflected in cost of fuel and purchased power in the Condensed Statements of Operations. 6. Contingencies 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 (See Note 7), there are no legal proceedings pending against SIGECO that are likely to have a material adverse effect on its financial position or results of operations. 7. 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 % 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, requiring 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). 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. On March 3, 2000, the United States Circuit Court of Appeals for the District of Columbia (D.C. Court 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. Numerous petitioners, including several states, filed petitions for 10 rehearing with the D.C. Court of Appeals. On June 22, 2000, the D.C. Court of Appeals denied petition for rehearing en banc. Following this decision, on August 30, 2000, the D.C. Court of Appeals issued an extension of the SIP Call implementation deadline 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. Court of Appeals March 3, 2000 Order, which was denied. Therefore, SIGECO's compliance date remains May 31, 2004. The proposed NOx emissions budget for Indiana stipulated in the USEPA's final ruling requires a 36 % 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 %. 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. 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 11 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 has provided all information requested, and management believes that no significant issues will arise from this request. 8. Rate and Regulatory Matters Commodity prices for natural gas purchases have increased significantly, primarily due to a colder winter, increased demand and tighter supplies. SIGECO is allowed full recovery of such changes in purchased gas and fuel costs for its retail customers through commission-approved gas and fuel cost adjustment mechanisms. 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 limited its exposure to unrecoverable purchased power costs. 9. Affiliate Transactions Certain wholly owned subsidiaries of Vectren began providing support services to SIGECO beginning April 1, 2000. As of March 31, 2000, certain assets owned by SIGECO were contributed to a wholly owned subsidiary of Vectren (Vectren Resources, LLC). The contribution of assets was reflected as a reduction of common shareholder's equity and is omitted from the Condensed Statements of Cash Flows. 12 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 $11.1 million and $41.1 million for the three and twelve months ended March 31, 2001, respectively. Prior to April 1, 2000, these costs were incurred by SIGECO directly. Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases fuel used for electric generation. Amounts paid for such purchases for the three months ended March 31, 2001 and 2000 were $10.4 million and $6.6 million respectively. Amounts paid for such purchases for the twelve months ended March 31, 2001 and 2000 were $28.6 million and $22.2 million, respectively. Amounts charged by Vectren Fuels, Inc. are market based. SIGECO also participates in a centralized cash management program with its parent, affiliated companies and banks which permits funding of checks as they are presented. Amounts owed to wholly owned subsidiaries of Vectren as of March 31, 2001, March 31, 2000 and December 31, 2000 totaled $31.3 million, $6.5 million and $11.5 million, respectively, and are included in accounts payable to affiliated company. Amounts due from wholly owned subsidiaries of Vectren as of March 31, 2001, March 31, 2000 and December 31, 2000 totaled $9.9 million, $8.2 million, and $27.8 million, respectively, and are included in accounts receivable from affiliated company. 10. Segment Reporting Operating segments are defined as components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision makers in deciding how to allocate resources and in the assessment of performance. There were two operating segments of SIGECO during the reported periods: (1) Electric Utility Services and (2) Gas Utility Services. The Electric Utility Services segment generates, transmits, distributes and sells electricity primarily within southwestern Indiana and in periods of under utilized capacity, sells excess electricity to other wholesale customers. The Gas Utility Services segment distributes, transports and sells natural gas to Evansville, Indiana and 64 communities in ten counties in southwestern Indiana. Revenues for each segment are attributable to customers in the United States. Effective January 1, 2001, SIGECO announced the reorganization of its utility operations into two primary business units: Energy Delivery and Power Supply. During 2001, organizational alignment will occur along with the development of management reporting processes. As a result, SIGECO will report segment information as Gas Utility Services and Electric Utility Services. 13 Certain information relating to SIGECO's business segments is presented below. Three Months Twelve Months Ended March 31, Ended March 31, ------------------- ------------------- In thousands 2001 2000 2001 2000 -------- -------- -------- -------- Operating Revenues: Electric Utility Services $ 88,209 $ 72,990 $351,628 $309,572 Gas Utility Services 51,950 29,227 132,007 67,741 -------- -------- -------- -------- Total operating revenues $140,159 $102,217 $483,635 $377,313 ======== ======== ======== ======== Net Income Applicable to Common Shareholder: Electric Utility Services $ 16,869 $ 2,607 $ 51,072 $ 35,017 Gas Utility Services 2,418 1,391 4,248 2,434 -------- -------- -------- -------- Net income applicable to common shareholder $ 19,287 $ 3,998 $ 55,320 $ 37,451 ======== ======== ======== ======== March 31, March 31, December 31, 2001 2000 2000 -------- -------- -------- Identifiable Assets: Electric Utility Services $788,506 $755,884 $799,104 Gas Utility Services 149,025 122,517 152,210 -------- -------- -------- Total identifiable assets $937,531 $878,401 $951,314 ======== ======== ======== 14 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION SOUTHERN INDIANA GAS AND ELECTRIC COMPANY Description of the Business Southern Indiana Gas and Electric Company (SIGECO) operates as a separate wholly owned subsidiary of Vectren Corporation (Vectren) and 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 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. Results of Operations Net Income Applicable to Common Shareholder For the three months ended March 31, 2001, net income applicable to common shareholder was $19.3 million. Net income applicable to common shareholder before merger and integration costs and the cumulative effect of the accounting change (adoption of FAS 133) was $15.6 million, compared to net income applicable to common shareholder before merger and integration costs for the first quarter of 2000 of $13.0 million. (See discussion of merger and integration costs and cumulative effect of change in accounting principle below.) For the twelve months ended March 31, 2001, net income applicable to common shareholder was $55.3 million. Net income applicable to common shareholder before merger and integration costs and the cumulative effect of the accounting change (adoption of FAS 133) was $53.2 million, compared to net income applicable to common shareholder before merger and integration costs for the twelve months ended March 31, 2000 of $46.5 million. Utility Margin (Operating Revenues Less Cost of Fuel, Purchased Power and Cost of Gas) Electric Utility Margin Electric Utility margin for the three months ended March 31, 2001 of $57.1 million, increased $5.8 million, or 11 %, over 2000 primarily due to a $5.5 million gain recorded to reflect certain wholesale power marketing purchase and sale contracts at current market values as required by Statement of Financial Accounting Standard No. 133 "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). Electric Utility margin for the twelve months ended March 31, 2001 of $230.1 million, increased $15.0 million, or 7 % over 2000 primarily due to the current quarter $5.5 million gain recorded to reflect certain wholesale power marketing purchase and sale contracts at current market values as required by SFAS 133. The remaining $9.5 million increase results from increased margin from sales to wholesale energy markets with volumes increasing 69 % over 2000, and a 5 % 15 increase in sales to retail customers for the period due to the impact of colder weather on retail electric heating sales and an increasing customer base. Total cost of fuel for electric generation and purchased power increased $9.5 million, or 44 %, and $27.1 million, or 29 %, for the three and twelve month periods ended March 31, 2001, compared to the same periods in the prior year due primarily to increased purchased power related to the greater sales to other utilities and power marketers. Gas Utility Margin Gas Utility margin for the three months ended March 31, 2001 of $10.5 million increased $0.9 million, or 9 %, compared to 2000. The increase is due to an 8 % increase in throughput resulting primarily from temperatures being 16 % colder than the previous year. These favorable impacts were partially offset by reduced consumption and the cost of unaccounted for gas due to much higher gas costs (see below). Total cost of gas sold was $41.5 million for the three months ended March 31, 2001 compared to $19.6 million in 2000. This increase of $21.8 million, or 111 % is primarily due to significantly higher average per unit purchased gas costs. The total average cost per dekatherm of gas purchased by SIGECO for the three months ended March 31, 2001 was $6.74 compared to $3.86 for the same period in 2000. Gas Utility margin for the twelve months ended March 31, 2001 of $31.3 million increased $3.3 million, or 12 %, compared to 2000. The increase is due to a 15 % increase in throughput resulting primarily from temperatures being 27 % colder than the previous year and a 2 % increase in the residential customer base. These favorable impacts on gas margin were partially offset by the cost of unaccounted for gas due to higher gas costs. Total cost of gas sold was $100.7 million for the twelve months ended March 31, 2001 and $39.7 million in 2000. This increase of $61.0 million, or 153 %, compared to 2000 is primarily due to significantly higher per unit purchased gas costs. Commodity prices for natural gas purchases have increased significantly, primarily due to a colder winter, increased demand and tighter supplies. Subject to compliance with applicable state laws, 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. However, in 2001, SIGECO has experienced and may continue to experience higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectibles and unaccounted for gas, and some level of price sensitive reduction in volumes sold. Operating Expenses Operations and Maintenance Operations and maintenance expenses increased $2.2 million, or 10 %, for the three months ended March 31, 2001 compared to the prior year, and operations and maintenance expenses increased $10.6 million, or 11 % for the twelve months ended March 31, 2001. The increases reflect primarily higher general and administrative costs and plant and system maintenance. 16 Depreciation and Amortization Depreciation and amortization decreased $0.4 million and $2.3 million for the three and twelve months ended March 31, 2001, respectively, compared to the prior year due to the contribution of certain information systems and equipment to a wholly owned subsidiary of Vectren. Income Taxes Federal and state income taxes increased $4.8 million and $6.3 million for the three and twelve months ended March 31, 2001,respectively, compared to the prior year due primarily to higher pre-tax earnings, partially offset by normal effective tax rates in 2001. The effective tax rate for the three month period in 2000 was higher as a result of the non-deductibility of certain merger and integration costs. Taxes Other Than Income Taxes Taxes other than income taxes increased $0.4 million and $0.7 million for the three and twelve month periods ended March 31, 2001, respectively. The increases result from increases in gross receipts and property taxes. Merger and Integration Costs Merger and integration costs incurred for the three and twelve months ended March 31, 2001, totaled $0.4 million ($0.2 million after tax) and $2.1 million ($1.8 million after tax) respectively, and for both the three and twelve months ended March 31, 2000 totaled $12.4 million ($9.0 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 completed in 2001. Merger costs are reflected in the financial statements of Vectren's operating subsidiaries in which merger savings are expected to be realized. Since March 31, 2000, $14.5 million has been expensed associated with merger and integration activities. Accruals were established at March 31, 2000 totaling $7.4 million. Of this amount, $0.7 million related to employee and executive severance costs and $6.7 related to transaction costs and regulatory filing fees incurred prior to the closing of the merger. At March 31, 2001, the accrual remaining for such costs totaled $0.4 million, all related to severance costs. Of the $14.5 million expensed, the remaining $7.1 million was expensed through March 31, 2001 ($6.7 million in 2000 and $0.4 million in 2001) 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, investor relations communications activities, and certain benefit costs. 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, Net Other income, net increased $0.2 million and $1.4 million for the three and twelve months ended March 31, 2001 compared to the prior year due to increased allowance for funds used during construction (AFUDC) resulting from increased utility plant construction in progress. 17 Interest Expense Interest expense increased by $0.5 million and $0.8 million, respectively, for the three and twelve months ended March 31, 2001, respectively, when compared to the prior year. The increases were due primarily to increased working capital requirements resulting from higher natural gas prices. Other Operating Matters New Accounting Principle and Cumulative Effect of Change in Accounting Principle See Note 5 in the condensed financial statements regarding the adoption of SFAS 133, as amended. Realignment Effective January 1, 2001, SIGECO announced the reorganization of its utility operations into two primary business units: Energy Delivery and Power Supply. During 2001, organizational alignment will occur along with the development of management reporting processes. As a result, SIGECO will report segment information as Gas Utility Services and Electric Utility Services. Financial Condition Environmental and Regulatory Matters See Notes 7 and 8 in SIGECO's condensed financial statements included in Part I, Item 1 regarding matters affecting operations including Clean Air Act compliance (Note 7) and purchased power costs recovery (Note 8). Liquidity and Capital Resources SIGECO's capitalization objective is 40-55 % 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 53 %, 51 % and 52 % of total capitalization, including current maturities of long-term debt, at March 31, 2001, March 31, 2000 and December 31, 2000, respectively. Short-term cash working capital is required primarily to finance customer accounts receivable, unbilled utility revenues resulting from cycle billing, gas in underground storage, prepaid gas delivery services, capital expenditures and investments until permanently financed. Short-term borrowings tend to be greatest during the summer when accounts receivable and unbilled utility revenues related to electricity are highest and gas storage facilities are being refilled. However, working capital requirements have been significantly higher during other periods 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 $21.0 million and $32.3 million for the three months ended March 31, 2001 and 2000, 18 respectively, and $55.0 million and $99.5 million for the twelve months ended March 31, 2001 and 2000, respectively. Cash flow from operations decreased during the three and twelve months ended March 31, 2001 compared to 2000 by $11.3 million and $44.5 million, respectively, due to increased working capital requirements due to higher gas costs offset by decreased merger and integration costs. SIGECO expects the majority of its capital expenditures and debt security redemptions to be provided by internally generated funds. Financing Activities Cash flow required for financing activities of $34.3 million for the three months ended March 31, 2001 includes $25.3 million of reductions in net borrowings and preferred stock and $8.8 million common and preferred stock dividends. This is an increase in cash required for financing activities when compared to the three months ended March 31, 2000 of $18.9 million. The increase is primarily due to increased payments on short-term borrowings from internally generated funds in 2001. Cash flow required for financing activities of $31.3 million for the twelve months ended March 31, 2001 includes $4.4 million of reductions in net borrowings and preferred stock and $29.7 million of common and preferred stock dividends. This is a decrease in cash requirements for financing activities of $45.7 million over the same period in the prior year due primarily to a decrease in short-term borrowings being paid down in 2001. 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 reset annually, and the bonds subject to tender were presented in the Balance Sheets as current liabilities. Effective March 1, 2001, the bonds were reset for a five-year period and have been classified as long-term debt. Resulting from the reset, the interest rate on the $31.5 million Series A bonds increased from 4.30 % to 4.75 %, and the interest rate on the $22.2 million Series C bonds increased from 4.45 % to 5.00 %. At March 31, 2001, SIGECO has approximately $74 million of short-term borrowing capacity for use in its operations, of which approximately $59 million is available. SIGECO's credit rating on outstanding debt at March 31, 2001 was A/A1. 19 Capital Expenditures and Other Investment Activities Cash required for investing activities of $9.6 million and $47.2 for the three and twelve months ended March 31, 2001 is comprised mainly of capital expenditures. Cash requirements for investing activities have decreased from prior year requirements primarily due a decrease in capital expenditures for utility plant. New construction, normal system maintenance and improvements, and technology investments needed to provide service to a growing customer base will continue to require substantial expenditures. Capital expenditures for the remainder of 2001 are estimated at $88 million. Forward-Looking Information A "safe harbor" for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Certain matters described in Management's Discussion and Analysis of Results of Operations and Financial Condition, including, but not limited to Vectren's realization of net merger savings, are forward-looking statements. Such statements are based on management's beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words "believe," "anticipate," "endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal," and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause Vectren and its subsidiaries' actual results to differ materially from those contemplated in any forward-looking statements included, among others, the following: |X| Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unusual maintenance or repairs; unanticipated changes to fossil fuel costs; unanticipated changes to gas supply costs, or availability due to higher demand, shortages, transportation problems or other developments; environmental or pipeline incidents; transmission or distribution incidents; unanticipated changes to electric energy supply costs, or availability due to demand, shortages, transmission problems or other developments; or electric transmission or gas pipeline system constraints. |X| Increased competition in the energy environment including effects of industry restructuring and unbundling. |X| Regulatory factors such as unanticipated changes in rate-setting policies or procedures, recovery of investments and costs made under traditional regulation, and the frequency and timing of rate increases. |X| Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission, state public utility commissions, state entities which regulate natural gas transmission, gathering and processing, and similar entities with regulatory oversight. 20 |X| Economic conditions including inflation rates and monetary fluctuations. |X| Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks. |X| Availability or cost of capital, resulting from changes in SIGECO, interest rates, and securities ratings or market perceptions of the utility industry and energy-related industries. |X| Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages. |X| Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures. |X| Costs and other effects of legal and administrative proceedings, settlements, investigations, claims, and other matters, including, but not limited to, those described in Management's Discussion and Analysis of Results of Operations and Financial Condition. |X| Changes in federal, state or local legislature requirements, such as changes in tax laws or rates, environmental laws and regulations. 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. 21 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SOUTHERN INDIANA GAS AND ELECTRIC COMPANY Registrant August 27, 2001 /s/Jerome A. Benkert, Jr. ------------------------- Jerome A. Benkert, Jr. Executive Vice President and Chief Financial Officer /s/M. Susan Hardwick ------------------------- M. Susan Hardwick Vice President and Controller