-----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, IfM6OxjUukfH9LweBkHxWCb7HrwP85M+ApRsBp+J8tqQER/3dCbwn8jtjr1wnl1g 33D6XmZJJnQFmESH5+6XHw== 0001096385-05-000049.txt : 20050407 0001096385-05-000049.hdr.sgml : 20050407 20050407114755 ACCESSION NUMBER: 0001096385-05-000049 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20041231 ITEM INFORMATION: Regulation FD Disclosure FILED AS OF DATE: 20050407 DATE AS OF CHANGE: 20050407 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VECTREN UTILITY HOLDINGS INC CENTRAL INDEX KEY: 0001129542 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 352104850 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-16739 FILM NUMBER: 05738517 BUSINESS ADDRESS: STREET 1: 20 NW 4TH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 BUSINESS PHONE: 8124914000 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VECTREN CORP CENTRAL INDEX KEY: 0001096385 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 352086905 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-15467 FILM NUMBER: 05738518 BUSINESS ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 BUSINESS PHONE: 8124914000 MAIL ADDRESS: STREET 1: 20 NW FOURTH ST CITY: EVANSVILLE STATE: IN ZIP: 47708 8-K 1 vvc8k_sig-igcreport.txt VECTREN CORP 8K REPORTING FINANCIAL DATA FROM SIG & IGC SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934 Date of Report (Date of earliest event reported) April 7, 2005 VECTREN CORPORATION (Exact name of registrant as specified in its charter) Commission Registrant, State of Incorporation, I.R.S Employer File No. Address, and Telephone Number Identification No. ---------- ----------------------------------- ------------------ 1-15467 Vectren Corporation 35-2086905 (An Indiana Corporation) 20 N.W. Fourth Street, Evansville, Indiana 47708 (812) 491-4000 1-16739 Vectren Utility Holdings, Inc. 35-2104850 (An Indiana Corporation) 20 N.W. Fourth Street, Evansville, Indiana 47708 (812) 491-4000 Former name or address, if changed since last report: N/A Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions: |_| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |_| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |_| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |_| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) Item 7.01. Regulation FD Disclosure Included herein are the audited financial statements of Southern Indiana Gas & Electric Company (SIGECO) and Indiana Gas Company, Inc. (Indiana Gas), wholly owned subsidiaries of Vectren Utility Holdings, Inc. (VUHI). VUHI is a wholly owned subsidiary of Vectren Corporation (the Company). The SIGECO and Indiana Gas financial statements include footnotes thereto, abbreviated discussion of results of operations and operating statistics. The financial statements of SIGECO are included as Exhibit 99.1 and the Indiana Gas financial statements are included as Exhibit 99.2 to the Current Report. These financial statements are not intended to comply with Regulation S-X or Regulation S-K as neither SIGECO nor Indiana Gas are registrants. In accordance with SEC Release No. 33-8176, the information contained in the audited financial statements shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended. In connection with the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, the Company is hereby furnishing cautionary statements identifying important factors that could cause actual results of the Company and its subsidiaries, including Vectren Utility Holdings, Inc., Southern Indiana Gas and Electric Company, and Indiana Gas Company, Inc. to differ materially from those projected in forward-looking statements of the Company and its subsidiaries made by, or on behalf of, the Company and its subsidiaries. These cautionary statements are attached as Exhibit 99-3. 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 hereunto duly authorized. VECTREN CORPORATION VECTREN UTILITY HOLDINGS, INC. April 7, 2005 By: /s/ M. Susan Hardwick ------------------------------- M. Susan Hardwick Vice President and Controller INDEX TO EXHIBITS The following Exhibits are furnished as part of this Report to the extent described in Item 7.01: Exhibit Number Description ------- ----------- 99.1 Financial statements of Southern Indiana Gas & Electric Company, Inc. 99.2 Financial statements of Indiana Gas Company, Inc. 99.3 Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995 EX-99.1 2 sig8k_dec04-reporting.txt SOUTHERN IND. FINANCIAL REPORT Ex. 99.1 SOUTHERN INDIANA GAS & ELECTRIC COMPANY REPORTING PACKAGE For the year ended December 31, 2004 Contents Page Number Audited Financial Statements Report of Independent Registered Public Accounting Firm 1 Balance Sheets 2-3 Statements of Income 4 Statements of Cash Flows 5 Statements of Common Shareholder's Equity 6 Notes to Financial Statements 7 Results of Operations 22 Selected Operating Statistics 26 Basis of Presentation These annual financial statements should be read in conjunction with audited annual consolidated financial statements and the notes thereto of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (VUHI), the parent companies of SIGECO, filed on report Form 10-K for the year ended December 31, 2004. Vectren and VUHI make available their Securities and Exchange Commission filings and recent annual reports free of charge through its website at www.vectren.com. Frequently Used Terms AFUDC: allowance for funds used during MMBTU: millions of British thermal construction units APB: Accounting Principles Board MW: megawatts EITF: Emerging Issues Task Force MWh/GWh: megawatt hours/thousands of megawatt hours (gigawatt hours) FASB: Financial Accounting Standards NOx: nitrogen oxide Board FERC: Federal Energy Regulatory OUCC: Indiana Office of the Utility Commission Consumer Counselor IDEM: Indiana Department of SFAS: Statement of Financial Accounting Environmental Management Standards IURC: Indiana Utility Regulatory USEPA: United States Environmental Commission Protection Agency MCF/MMCF/BCF: thousands/millions/ Throughput: combined gas sales and gas billions of cubic feet transportation volumes MDth/MMDth: thousands/millions of dekatherms INDEPENDENT AUDITORS' REPORT To the Shareholder and Board of Directors of Southern Indiana Gas & Electric Company: We have audited the accompanying balance sheets of Southern Indiana Gas & Electric Company (the "Company") as of December 31, 2004 and 2003, and the related consolidated statements of income, common shareholder's equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, such financial statements present fairly, in all material respects, the financial position of Southern Indiana Gas & Electric Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. /s/ DELOITTE & TOUCHE LLP - ------------------------------------- DELOITTE & TOUCHE LLP Indianapolis, Indiana February 23, 2005 FINANCIAL STATEMENTS SOUTHERN INDIANA GAS & ELECTRIC COMPANY BALANCE SHEETS (In thousands) December 31, - ------------------------------------------------------------------------------ 2004 2003 - ------------------------------------------------------------------------------ ASSETS Utility Plant Original cost $ 1,804,843 $ 1,659,527 Less: Accumulated depreciation & amortization 761,256 719,787 - ------------------------------------------------------------------------------ Net utility plant 1,043,587 939,740 - ------------------------------------------------------------------------------ Current Assets Cash & cash equivalents 1,777 3,675 Accounts receivable - less reserves of $1,148 & $1,202, respectively 55,109 38,817 Receivables from other Vectren companies 1,547 76 Accrued unbilled revenues 36,402 28,162 Inventories 36,599 37,214 Recoverable fuel & natural gas costs - 3,900 Prepayments & other current assets 7,376 4,875 - ------------------------------------------------------------------------------ Total current assets 138,810 116,719 - ------------------------------------------------------------------------------ Investments in unconsolidated affiliates 150 150 Other investments 9,481 10,474 Non-utility property - net 3,568 3,769 Goodwill - net 5,557 5,557 Regulatory assets 50,239 54,625 Other assets 85 688 - ------------------------------------------------------------------------------ TOTAL ASSETS $ 1,251,477 $ 1,131,722 ============================================================================== The accompanying notes are an integral part of these financial statements SOUTHERN INDIANA GAS & ELECTRIC COMPANY BALANCE SHEETS (In thousands) December 31, - ------------------------------------------------------------------------------ 2004 2003 - ------------------------------------------------------------------------------ LIABILITIES & SHAREHOLDER'S EQUITY Capitalization Common shareholder's equity Common stock (no par value) $ 128,263 $ 128,258 Retained earnings 265,935 266,911 - ------------------------------------------------------------------------------ Total common shareholder's equity 394,198 395,169 - ------------------------------------------------------------------------------ Cumulative redeemable preferred stock 112 228 Long-term debt payable to third parties - net of debt subject to tender 226,028 216,330 Long-term debt payable to VUHI 148,484 148,484 - ------------------------------------------------------------------------------ Total capitalization 768,822 760,211 - ------------------------------------------------------------------------------ Commitments & Contingencies (Notes 3, 7, 8 & 9) Current Liabilities Accounts payable 37,159 18,437 Accounts payable to affiliated companies 11,266 8,312 Payables to other Vectren companies 9,929 11,456 Accrued liabilities 37,803 38,619 Short-term borrowings 339 830 Short-term borrowings payable to VUHI 170,171 82,929 Long-term debt subject to tender - 9,975 - ------------------------------------------------------------------------------ Total current liabilities 266,667 170,558 - ------------------------------------------------------------------------------ Deferred Income Taxes & Other Liabilities Deferred income taxes 121,917 109,951 Regulatory liabilities 51,439 48,153 Deferred credits & other liabilities 42,632 42,849 - ------------------------------------------------------------------------------ Total deferred income taxes & other liabilities 215,988 200,953 - ------------------------------------------------------------------------------ TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $1,251,477 $1,131,722 ============================================================================== The accompanying notes are an integral part of these financial statements SOUTHERN INDIANA GAS & ELECTRIC COMPANY STATEMENTS OF INCOME (In thousands) Year Ended December 31, - --------------------------------------------------------------------------- 2004 2003 - --------------------------------------------------------------------------- OPERATING REVENUES Electric utility $ 371,279 $ 335,694 Gas utility 110,373 102,736 - --------------------------------------------------------------------------- Total operating revenues 481,652 438,430 - --------------------------------------------------------------------------- COST OF OPERATING REVENUES Fuel for electric generation 96,132 86,477 Purchased electric energy 20,655 16,172 Cost of gas sold 78,314 73,427 - --------------------------------------------------------------------------- Total cost of operating revenues 195,101 176,076 - --------------------------------------------------------------------------- TOTAL OPERATING MARGIN 286,551 262,354 OPERATING EXPENSES Other operating 112,113 102,994 Depreciation & amortization 58,484 47,649 Income taxes 31,853 30,640 Taxes other than income taxes 13,334 12,448 - --------------------------------------------------------------------------- Total operating expenses 215,784 193,731 - --------------------------------------------------------------------------- OPERATING INCOME 70,767 68,623 Other income - net 3,145 5,048 Interest expense 25,333 24,814 - --------------------------------------------------------------------------- NET INCOME 48,579 48,857 - --------------------------------------------------------------------------- Preferred stock dividends 13 23 - --------------------------------------------------------------------------- NET INCOME APPLICABLE TO COMMON SHAREHOLDER $ 48,566 $ 48,834 =========================================================================== The accompanying notes are an integral part of these financial statements SOUTHERN INDIANA GAS & ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (In thousands) Year Ended December 31, - ------------------------------------------------------------------------------- 2004 2003 - ------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 48,579 $ 48,857 Adjustments to reconcile net income to cash from operating activities: Depreciation & amortization 58,484 47,649 Deferred income taxes & investment tax credits 14,937 (6,195) Pension & postretirement periodic benefit cost 2,657 2,896 Unrealized loss (gain) on derivative instruments 1,399 (654) Other non-cash charges - net 223 (1,521) Changes in working capital accounts: Accounts receivable, including to Vectren companies & accrued unbilled revenue (27,853) 33,538 Inventories 1,228 2,439 Recoverable fuel & natural gas costs 3,900 5,715 Prepayments & other current assets (2,707) 608 Accounts payable, including to Vectren companies & affiliated companies 20,149 (11,700) Accrued liabilities (393) 9,458 Changes in noncurrent assets 2,512 (6,015) Changes in noncurrent liabilities (6,950) 60 - ------------------------------------------------------------------------------- Net cash flows from operating activities 116,165 125,135 - ------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Long-term debt due to VUHI - 61,900 Additional capital contribution - 25,000 Requirements for: Dividends to parent (49,542) (52,104) Retirement of long-term debt, including premiums paid (450) (68,438) Redemption of preferred stock (116) (116) Dividends on preferred stock (13) (23) Net change in short-term borrowings, including from VUHI 86,751 44,340 Other activity - (1,744) - ------------------------------------------------------------------------------- Net cash flows from financing activities 36,630 8,815 - ------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Requirements for: Capital expenditures (155,814) (132,420) Other investments 1,121 - - ------------------------------------------------------------------------------- Net cash flows from investing activities (154,693) (132,420) - ------------------------------------------------------------------------------- Net increase (decrease) in cash & cash equivalents (1,898) 1,530 Cash & cash equivalents at beginning of period 3,675 2,145 - ------------------------------------------------------------------------------- Cash & cash equivalents at end of period $ 1,777 $ 3,675 =============================================================================== Cash paid during the year for: Income taxes $ 26,486 $ 30,595 Interest 24,422 24,512 The accompanying notes are an integral part of these financial statements SOUTHERN INDIANA GAS & ELECTRIC COMPANY STATEMENTS COMMON SHAREHOLDER'S EQUITY (In thousands) Common Retained Stock Earnings Total - ------------------------------------------------------------------------------- Balance at January 1, 2003 $ 103,258 $ 270,181 $ 373,439 =============================================================================== Net income & comprehensive income 48,857 48,857 Common stock: Additional capital contribution 25,000 25,000 Dividends to parent (52,104) (52,104) Preferred stock dividends (23) (23) - ------------------------------------------------------------------------------- Balance at December 31, 2003 $ 128,258 $ 266,911 $ 395,169 =============================================================================== Net income & comprehensive income 48,579 48,579 Common stock: Other 5 5 Dividends to parent (49,542) (49,542) Preferred stock dividends (13) (13) - ------------------------------------------------------------------------------- Balance at December 31, 2004 $ 128,263 $ 265,935 $ 394,198 =============================================================================== The accompanying notes are an integral part of these financial statements SOUTHERN INDIANA GAS AND ELECTRIC COMPANY NOTES TO THE FINANCIAL STATEMENTS 1. Organization and Nature of Operations Southern Indiana Gas and Electric Company (the Company or SIGECO), an Indiana corporation, provides energy delivery services to approximately 136,000 electric customers and approximately 110,000 gas customers located near Evansville in southwestern Indiana. SIGECO also owns and operates electric generation to serve its electric customers and optimizes those assets in the wholesale power market. SIGECO is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). SIGECO generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana. 2. Summary of Significant Accounting Policies A. Cash & Cash Equivalents All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. B. Inventories Inventories consist of the following: At December 31, - ----------------------------------------------------------------------------- (In thousands) 2004 2003 - ----------------------------------------------------------------------------- Materials & supplies $ 19,801 $ 17,304 Fuel (coal and oil) for electric generation 8,762 10,680 Gas in storage - at LIFO cost 7,728 8,599 Emission allowances 308 631 - ----------------------------------------------------------------------------- Total inventories $ 36,599 $ 37,214 ============================================================================= Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2004, and 2003, by approximately $30.4 million and $30.1 million, respectively. All other inventories are carried at average cost. C. Utility Plant & Depreciation Utility plant is stated at historical cost, including AFUDC. Depreciation of utility property is provided using the straight-line method over the estimated service lives of the depreciable assets. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows: At & For the Year Ended December 31, - ---------------------------------------------------------------------------------------------- (In thousands) 2004 2003 - ---------------------------------------------------------------------------------------------- Depreciation Depreciation Rates as a Rates as a Percent of Percent of Original Cost Original Cost Original Cost Original Cost - ---------------------------------------------------------------------------------------------- Electric utility plant $ 1,458,063 3.6% $ 1,322,367 3.4% Gas utility plant 175,353 3.0% 170,870 3.0% Common utility plant 44,126 2.7% 44,290 2.7% Construction work in progress 127,301 - 122,000 - - ---------------------------------------------------------------------------------------------- Total original cost $ 1,804,843 $ 1,659,527 ==============================================================================================
AFUDC represents the cost of borrowed and equity funds used for construction purposes and is charged to construction work in progress during the construction period and is included in Other - net in the Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows: Year Ended December 31, - -------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------- AFUDC - equity funds $ 1,515 $ 2,863 AFUDC - borrowed funds 1,310 1,904 - -------------------------------------------------------------------------- Total AFUDC capitalized $ 2,825 $ 4,767 ========================================================================== Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred unless deferral is authorized by a rate order. When property that represents a retirement unit is replaced or removed, the cost of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation and Regulatory liabilities for the cost of removal. D. Impairment Review of Long-Lived Assets Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires the evaluation for impairment involve the comparison of an asset's carrying value to the estimated 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 based on the difference between the asset's carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. E. Goodwill Goodwill arising from business combinations is accounted for in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). SFAS 142 uses impairment-only approach to account for the effect of goodwill on the operating results. Goodwill is tested for impairment at a reporting unit level at least annually and that test is performed at the beginning of each year. The impairment review consists of a comparison of the fair value of a reporting unit to its carrying amount. If the fair value of a reporting unit is less than its carrying amount, an impairment loss is recognized in operations. Through December 31, 2004, no goodwill impairment has been recorded. The Company's goodwill is included in the Gas Utility Services operating segment. F. Regulation SFAS 71 Retail public utility operations affecting Indiana customers are subject to regulation by the IURC. The Company's accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS 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 rate-making process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. The Company assesses the recoverability of costs recognized as regulatory assets and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets. Regulatory assets consist of the following: At December 31, - ----------------------------------------------------------------------------- (In thousands) 2004 2003 - ----------------------------------------------------------------------------- Future amounts recoverable from ratepayers: Income taxes $ 3,354 $ 9,184 Other 962 858 - ----------------------------------------------------------------------------- 4,316 10,042 Amounts deferred for future recovery: Demand side management programs 25,878 24,888 Other 6,555 5,347 - ----------------------------------------------------------------------------- 32,433 30,235 Amounts currently recovered through base rates: Unamortized debt issue costs 5,105 4,515 Premiums paid to reacquire debt 5,712 5,915 Demand side management programs 2,322 2,746 Rate case expenses 706 - - ----------------------------------------------------------------------------- 13,845 13,176 Amounts currently recovered through authorized Indiana tracking mechanisms (355) 1,172 - ----------------------------------------------------------------------------- Total regulatory assets $ 50,239 $ 54,625 ============================================================================= Of the $13.8 million currently being recovered through base rates, $13.1 million is earning a return with a weighted average recovery period of 14.8 years. The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable. Cost of Removal and SFAS 143 The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. The Company records amounts expensed in advance of payments as a regulatory liability because the liability does not meet the threshold of a legal asset retirement obligation (ARO) as defined by SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). At December 31, 2004, and 2003, such removal costs approximated $51.4 million and $48.2 million, respectively. SFAS 143 requires entities to record the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company's results of operations. Refundable or Recoverable Gas Costs, Fuel for Electric Production & Purchased Power All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an agreed upon benchmark, is also recovered through regulatory proceedings. The Company records any under-or-over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or-over-recovery 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. G. Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas and electricity delivered to customers but not billed at the end of the accounting period. H. Utility Receipts Taxes A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of Operating revenues. Utility receipts taxes paid are recorded as a component of Taxes other than income taxes. I. Earnings Per Share Earnings per share are not presented as SIGECO's common stock is wholly owned by Vectren Utility Holdings, Inc. J. Other Significant Policies Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes (Note 3) and derivatives (Note 10). K. 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. 3. Transactions with Other Vectren Companies Support Services and Purchases Vectren and certain subsidiaries of Vectren provided corporate and general and administrative services to the Company including legal, technology, finance, tax, risk management, human resources, and charges for share-based compensation and for pension and other postretirement benefits not directly charged to subsidiaries. These costs have been allocated using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are based on cost. SIGECO received corporate allocations totaling $45.9 million and $42.3 million for the years ended December 31, 2004, and 2003, respectively. Vectren Fuels, Inc., a wholly owned subsidiary of Vectren, owns and operates coal mines from which SIGECO purchases fuel used for electric generation. Amounts paid for such purchases for the years ended December 31, 2004, and 2003, totaled $79.0 million and $77.0 million, respectively. Amounts charged by Vectren Fuels, Inc. are established by supply agreements with the utility. Retirement Plans and Other Postretirement Benefits Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 87 "Employers' Accounting for Pensions" and SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions," respectively. An allocation of expense is determined by Vectren's actuaries, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the FAS 87/106 liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with "multiemployer" benefit accounting as described in SFAS 87 and 106. For the years ended December 31, 2004 and 2003, periodic pension costs totaling $2.0 million and $2.4 million, respectively, was directly charged by Vectren to the Company. For the years ended December 31, 2004 and 2003, other periodic postretirement benefit costs totaling $0.6 million and $0.5 million, respectively, was directly charged by Vectren to the Company. As of December 31, 2004 and 2003, $25.9 million and $26.4 million, respectively, is included in Deferred credits & other liabilities and represents expense directly charged to the Company that is yet to be funded to Vectren. Cash Management Arrangements The Company participates in a centralized cash management program with Vectren, other wholly owned subsidiaries, and banks which permits funding of checks as they are presented. See Note 5 regarding long-term and short-term intercompany borrowing arrangements. Share-Based Incentive Plans In December 2004, the FASB issued Statement 123 (revised 2004), "Share-Based Payments" (SFAS 123R) that will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces FASB Statement No. 123, "Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25, "Accounting for Stock Issued to Employees." The effective date of SFAS 123R for the Company is July 1, 2005. SFAS 123R provides for multiple transition methods, and the Company is still evaluating potential methods for adoption. SIGECO does not have share-based compensation plans separate from Vectren. An insignificant number of the Company's employees participate in Vectren's share-based compensation plans. The adoption of this standard is not expected to have any material effect on the Company's operating results or financial condition. Guarantees of Parent Company Debt Vectren's three operating utility companies, SIGECO, Indiana Gas Company, Inc. (Indiana Gas) and Vectren Energy Delivery of Ohio, Inc. are guarantors of VUHI's $350 million in short-term credit facilities, of which approximately $308.0 million is outstanding at December 31, 2004, and VUHI's $550 million unsecured senior notes outstanding at December 31, 2004. The guarantees are full and unconditional and joint and several, and VUHI has no subsidiaries other than the subsidiary guarantors. Income Taxes Vectren and subsidiary companies file a consolidated federal income tax return. For financial reporting purposes, SIGECO's current and deferred tax expense is computed on a separate company basis. The components of income tax expense and utilization of investment tax credits follow: Year Ended December 31, - ---------------------------------------------------------------------------- (In thousands) 2004 2003 - ---------------------------------------------------------------------------- Current: Federal $ 11,900 $ 27,440 State 5,137 9,447 - ---------------------------------------------------------------------------- Total current taxes 17,037 36,887 - ---------------------------------------------------------------------------- Deferred: Federal 14,523 (2,358) State 1,656 (2,534) - ---------------------------------------------------------------------------- Total deferred taxes 16,179 (4,892) - ---------------------------------------------------------------------------- Amortization of investment tax credits (1,242) (1,303) - ---------------------------------------------------------------------------- Total income tax expense 31,974 30,692 - ---------------------------------------------------------------------------- Less: Income tax expense included in other - net 121 52 - ---------------------------------------------------------------------------- Total income tax expense in operating income $ 31,853 $ 30,640 ============================================================================ A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, - ------------------------------------------------------------------------------- 2004 2003 - ------------------------------------------------------------------------------- Statutory rate 35.0 % 35.0 % State & local taxes, net of federal benefit 5.5 5.6 Amortization of investment tax credit (1.5) (1.6) All other - net 0.7 (0.4) - ------------------------------------------------------------------------------- Effective tax rate 39.7 % 38.6 % =============================================================================== The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow: At December 31, - ------------------------------------------------------------------------------- (In thousands) 2004 2003 - ------------------------------------------------------------------------------- Noncurrent deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 130,421 $ 111,404 Regulatory assets recoverable through future rates 9,115 15,614 Regulatory liabilities to be settled through future rates (5,762) (6,430) Employee benefit obligations (11,085) (10,371) Other - net (772) (266) - ------------------------------------------------------------------------------- Net noncurrent deferred tax liability 121,917 109,951 - ------------------------------------------------------------------------------- Current deferred tax liability: Deferred fuel costs - net 1,729 3,691 - ------------------------------------------------------------------------------- Net current deferred tax liability 1,729 3,691 - ------------------------------------------------------------------------------- Net deferred tax liability $ 123,646 $ 113,642 =============================================================================== At December 31, 2004 and 2003, investment tax credits totaling $10.7 million and $11.9 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. The Company has no tax credit carryforwards at December 31, 2004. 4. Transactions with Vectren Affiliates ProLiance Energy, LLC ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to SIGECO, Indiana Gas, the Ohio operations, Citizens Gas and others. ProLiance's primary business is optimizing the gas portfolios of utilities and providing services to large end use customers. Transactions with ProLiance Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2004, and 2003, totaled $79.1 million and $72.8 million, respectively. Amounts owed to ProLiance at December 31, 2004, and 2003, for those purchases were $11.3 million and $8.3 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility. Other Affiliate Transactions Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that perform underground construction and repair, facilities locating, and meter reading services to the Company. For the years ended December 31, 2004, and 2003, fees for these services and construction-related expenditures paid by the Company to Vectren affiliates totaled less than $0.1 million and $0.3 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates other than ProLiance totaled less than $0.1 million at December 31, 2004, and 2003, respectively. 5. Borrowing Arrangements & Other Financing Transactions Short-Term Borrowings SIGECO mainly relies on the short-term borrowing arrangements of VUHI for its short-term working capital needs. Borrowings, including third party borrowings, outstanding at December 31, 2004 and 2003, were $170.5 million and $83.8 million, respectively. The intercompany credit line is limited by VUHI's available capacity, which is $42 million at December 31, 2004. The line is subject to the same terms and conditions as VUHI's commercial paper program. Short-term borrowings bear interest at VUHI's weighted average daily cost of short-term funds. Additionally, at December 31, 2004, the Company has approximately $5 million of short-term borrowing capacity with third parties to supplement its intercompany borrowing arrangements, of which $4.6 million is available. See the table below for interest rates and outstanding balances: Year ended December 31, - ------------------------------------------------------------------------------ 2004 2003 - ------------------------------------------------------------------------------ Weighted average total outstanding during the year payable to VUHI (in thousands) $ 111,756 $ 41,456 Weighted average total outstanding during the year payable to third parties (in thousands $ 580 $ 928 Weighted average interest rates during the year: VUHI 1.69% 1.31% Bank loans 2.19% 1.86% Long-Term Debt Senior unsecured obligations and first mortgage bonds outstanding and classified as long-term follow: At December 31, - ----------------------------------------------------------------------------- (In thousands) 2004 2003 - ----------------------------------------------------------------------------- Senior Unsecured Notes Payable to VUHI: 2011, 6.625% $ 86,584 $ 86,584 2018, 5.75% 61,900 61,900 - ----------------------------------------------------------------------------- Total long-term debt payable to VUHI $ 148,484 $ 148,484 ============================================================================= First Mortgage Bonds Payable to Third Parties: 2016, 1986 Series, 8.875% $ 13,000 $ 13,000 2023, Series B, adjustable rate presently 2.08%, tax exempt, auction rate mode, weighted average for 2004: 4.44% 22,550 22,800 2029, 1999 Senior Notes, 6.72% 80,000 80,000 2015, 1985 Pollution Control Series A, adjustable rate presently 2.03%, tax exempt, weighted average for 2004: 3.09% 9,775 9,975 2025, 1998 Pollution Control Series A, adjustable rate presently 4.75%, tax exempt, next rate adjustment: 2006 31,500 31,500 2024, 2000 Environmental Improvement Series A, 4.65%, tax exempt 22,500 22,500 - ----------------------------------------------------------------------------- Total first mortgage bonds 179,325 179,775 - ----------------------------------------------------------------------------- Senior Unsecured Bonds Payable to Third Parties: 2020, 1998 Pollution Control Series B, 4.50%, tax exempt 4,640 4,640 2030, 1998 Pollution Control Series B, 5.00%, tax exempt 22,000 22,000 2030, 1998 Pollution Control Series C, adjustable rate presently 5.00%, tax exempt, next rate adjustment: 2006 22,200 22,200 - ----------------------------------------------------------------------------- Total senior unsecured bonds 48,840 48,840 - ----------------------------------------------------------------------------- Total long-term debt outstanding payable to third parties 228,165 228,615 Long-term debt subject to tender - (9,975) Unamortized debt premium & discount & other - net (2,137) (2,310) - ----------------------------------------------------------------------------- Long-term debt payable to third parties - net $ 226,028 $ 216,330 ============================================================================= Issuance Payable to VUHI in 2003 In 2003, the Company issued $61.9 million of long-term debt payable to VUHI. The note has terms identical to the terms of notes issued by VUHI in July 2003 through a public offering. Those notes have an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity and are due August 2018. They have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by VUHI, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in VUHI's indenture, plus 25 basis points. At present, VUHI has no intent to call the notes; therefore the notes are classified as long term on the accompanying Balance Sheets. Debt Call During 2003, the Company called two first mortgage bonds. The first bond had a principal amount of $45.0 million, an interest rate of 7.60%, was originally due in 2023, and was redeemed at 103.745% of its stated principal amount. The second bond had a principal amount of $20.0 million, an interest rate of 7.625%, was originally due in 2025, and was redeemed at 103.763% of the stated principal amount. Pursuant to regulatory authority, the premiums paid to retire the net carrying value of these notes totaling $2.4 million were deferred in Regulatory assets. The proceeds to fund the early redemption were received from VUHI in the form of new long-term debt discussed above and $25 million in additional equity. To generate the initial proceeds to fund these transactions, in July 2003, VUHI completed a public offering of long-term debt netting proceeds of approximately $203 million, and, in August 2003, Vectren completed a public offering of common stock netting proceeds of approximately $163 million. Other Financing Transactions During 2004, the Company remarketed two first mortgage bonds. The remarketing effort converted $32.8 million of outstanding fixed rate debt into variable rate debt where interest rates reset weekly. One bond, due in 2023, had a principal amount of $22.8 million and an interest rate of 6%. The other bond, due in 2015, had a principal amount of $10.0 million and an interest rate of 4.3%. These bonds are classified in Long-term debt. During 2003, the Company re-marketed $22.5 million of first mortgage bonds subject to interest rate exposure on a long term basis. The $22.5 million of mortgage bonds were remarketed through 2024 at a 4.65% fixed interest rate. Long-Term Debt Sinking Fund Requirements & Maturities The annual sinking fund requirement of SIGECO's first mortgage bonds is one percent of the greatest amount of bonds outstanding under the Mortgage Indenture. This requirement may be satisfied by certification to the Trustee of unfunded property additions in the prescribed amount as provided in the Mortgage Indenture. SIGECO intends to meet the 2005 sinking fund requirement by this means and, accordingly, the sinking fund requirement for 2005 is excluded from Current liabilities in the Balance Sheets. At December 31, 2004, $563.9 million of SIGECO's utility plant remained unfunded under SIGECO's Mortgage Indenture. There are no maturities and/or sinking fund requirements on long-term debt during the five years following 2004. Long-Term Debt Put & Call Provisions Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements, such as when notes are re-marketed. Debt which may be put to the Company during the years following 2004 (in millions) is zero in 2005, 2006, 2007, and 2008, $80.0 in 2009 and zero thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities. Covenants Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2004, the Company was in compliance with all financial covenants. 6. Cumulative Preferred Stock Redeemable, Special This series of redeemable preferred stock has a dividend rate of 8.50% and in the event of involuntary liquidation the amount payable is $100 per share, plus accrued dividends. This series may be redeemed at $100 per share, plus accrued dividends on any of its dividend payment dates, and is also callable at the Company's option at a rate of 1,160 shares per year. As of December 31, 2004, and 2003, there were 1,177 shares and 2,277 shares outstanding, respectively. 7. Commitments & Contingencies Commitments Firm purchase commitments for commodities total $3.7 million in 2005. Firm purchase commitment for utility and non-utility plant total $13.2 million. Legal Proceedings The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 8 regarding environmental matters. 8. Environmental Matters Clean Air Act NOx SIP Call Matter The Company has taken steps to comply with Indiana's State Implementation Plan (SIP) of the Clean Air Act (the Act). These steps include installing Selective Catalytic Reduction (SCR) systems at Culley Generating Station Unit 3 (Culley), Warrick Generating Station Unit 4, and A.B. Brown Generating Station Units 1 and 2. SCR systems reduce flue gas NOx emissions to atmospheric nitrogen and water using ammonia in a chemical reaction. This technology is known to currently be the most effective method of reducing nitrogen oxide (NOx) emissions where high removal efficiencies are required. The IURC has issued orders that approve: o the Company's project to achieve environmental compliance by investing in clean coal technology; o a total capital cost investment for this project up to $244 million (excluding AFUDC), subject to periodic review of the actual costs incurred; o a mechanism whereby, prior to an electric base rate case, the Company may recover through a rider that is updated every six months, an 8% return on its weighted capital costs for the project; and o ongoing recovery of operating costs, including depreciation and purchased emission allowances, related to the clean coal technology once the facility is placed into service. Based on the level of system-wide emissions reductions required and the control technology utilized to achieve the reductions, the current estimated construction cost is consistent with amounts approved in the IURC's orders. Through December 31, 2004, $238 million has been expended, and three of the four SCR's are operational. Once all equipment is installed and operational, related annual operating expenses, including depreciation expense, are estimated to be between $24 million and $27 million. The Company is recovering the operational costs associated with the SCR's and related technology. The 8% return on capital investment approximates the return authorized in the Company's last electric rate case in 1995 and includes a return on equity. The Company has achieved timely compliance through the reduction of the Company's overall NOx emissions to levels compliant with Indiana's NOx emissions budget allotted by the USEPA. Therefore, the Company has recorded no accrual for potential penalties that may result from noncompliance. Culley Generating Station Litigation During 2003, the U.S. District Court for the Southern District of Indiana entered a consent decree among SIGECO, the Department of Justice (DOJ), and the USEPA that resolved a lawsuit originally brought by the USEPA against SIGECO. The lawsuit alleged violations of the Clean Air Act by SIGECO at its Culley Generating Station for (1) making modifications to generating station without obtaining required permits, (2) making major modifications to the generating station without installing the best available emission control technology, and (3) failing to notify the USEPA of the modifications. Under the terms of the agreement, the DOJ and USEPA agreed to drop all challenges of past maintenance and repair activities at the Culley Generating Station. In reaching the agreement, SIGECO did not admit to any allegations in the government's complaint, and SIGECO continues to believe that it acted in accordance with applicable regulations and conducted only routine maintenance on the units. SIGECO entered into this agreement to further its continued commitment to improve air quality and avoid the cost and uncertainties of litigation. Under the agreement, SIGECO committed to o either repower Culley Unit 1 (50 MW) with natural gas and equip it with SCR control technology for further reduction of nitrogen oxide, or cease operation of the unit by December 31, 2006; o operate the existing SCR control technology recently installed on Culley Unit 3 (287 MW) year round at a lower emission rate than that currently required under the NOx SIP Call, resulting in further nitrogen oxide reductions; o enhance the efficiency of the existing scrubber at Culley Units 2 and 3 for additional removal of sulphur dioxide emissions; o install a baghouse for further particulate matter reductions at Culley Unit 3 by June 30, 2007; o conduct a Sulphuric Acid Reduction Demonstration Project as an environmental mitigation project designed to demonstrate an advance in pollution control technology for the reduction of sulfate emissions; and o pay a $600,000 civil penalty. The Company notified the USEPA of its intention to shut down Culley Unit 1 effective December 31, 2006. The Company does not believe that implementation of the settlement will have a material effect to its results from operations or financial condition. The $600,000 civil penalty was accrued during 2003 and is reflected in Other-net. Information Request On January 23, 2001, SIGECO received an information request from the USEPA under Section 114 of the Act for historical operational information on the Warrick and A.B. Brown generating stations. SIGECO has provided all information requested with the most recent correspondence provided on March 26, 2001. Manufactured Gas Plants In October 2002, the Company received a formal information request letter from the IDEM regarding five manufactured gas plants owned and/or operated by SIGECO and not currently enrolled in the IDEM's VRP. In response, SIGECO submitted to the IDEM the results of preliminary site investigations conducted in the mid-1990's. These site investigations confirmed that based upon the conditions known at the time, the sites posed no risk to human health or the environment. Follow up reviews have been initiated by the Company to confirm that the sites continue to pose no such risk. On October 6, 2003, SIGECO filed applications to enter four of the manufactured gas plant sites in IDEM's VRP. The remaining site is currently being addressed in the VRP by another Indiana utility. SIGECO added those four sites into the renewal of the global Voluntary Remediation Agreement that Indiana Gas has in place with IDEM for its manufactured gas plant sites. That renewal was approved by the IDEM on February 24, 2004. On July 13, 2004, SIGECO filed a declaratory judgment action against its insurance carriers seeking a judgment finding its carriers liable under the policies for coverage of further investigation and any necessary remediation costs that SIGECO may accrue under the VRP program. The total investigative costs, and if necessary, costs of remediation at the four SIGECO sites, as well as the amount of any PRP or insurance recoveries, cannot be determined at this time. 9. Rate & Regulatory Matters Gas Base Rate Settlements On June 30, 2004, the IURC approved a $5.7 million base rate increase for SIGECO's gas distribution business. The new rate designs include a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in SIGECO's service territory was implemented on July 1, 2004, resulting in additional 2004 revenues of $2.5 million. The order also permits SIGECO to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $500,000 thereafter. Any costs incurred in excess of these annual caps are to be deferred for future recovery. 10. Derivatives & Other Financial Instruments Accounting Policy for Derivatives The Company executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations, optimizing its generation assets, and managing risk. The Company accounts for its derivative contracts in accordance with SFAS 133, "Accounting for Derivatives" and its related amendments and interpretations. In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met. When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale, it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges or as an adjustment to the underlying's basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company's use of mark-to-market accounting related to asset optimization and natural gas procurement. Asset Optimization Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of the margin from these activities is generated from contracts that are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk. Contracts with counter-parties subject to master netting arrangements are presented net in the Consolidated Balance Sheets. Asset optimization contracts are recorded at market value. Asset optimization contracts recorded at market value at December 31, 2004, totaled $2.5 million of Prepayments & other current assets and $3.1 million of Accrued liabilities, compared to $2.4 million of Prepayments & other current assets and $2.8 million of Accrued liabilities at December 31, 2003. The proceeds received and paid upon settlement of both purchase and sale contracts along with changes in market value of open contracts are recorded in Electric utility revenues. Net revenues from asset optimization activities totaled $23.8 million in 2004 and $26.5 million in 2003. Natural Gas Procurement Activity The Company's regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas and electricity for retail customers due to current Indiana and Ohio regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas and fuel cost adjustment mechanisms. Although the Company's regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold. The Company mitigates these risks by executing derivative contracts that manage the price of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. At December 31, 2004 and 2003, the market values of these contracts were not significant. Fair Value of Other Financial Instruments The carrying values and estimated fair values of the Company's other financial instruments follow: At December 31, - -------------------------------------------------------------------------------- 2004 2003 ---------------------- --------------------- Carrying Est. Carrying Est. (In thousands) Amount Fair Value Amount Fair Value - ---------------------------------- ---------------------- --------------------- Long term debt $ 228,165 $ 240,294 $ 228,615 $ 239,407 Long term debt payable to VUHI 148,484 159,519 148,484 159,927 Short-term borrowings 339 339 830 830 Short-term borrowings from VUHI 170,171 170,171 82,929 82,929 Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value. Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations. 11. Additional Operational & Balance Sheet Information Other - net in the Statements of Income consists of the following: Year ended December 31, - ------------------------------------------------------------------------------ (In thousands) 2004 2003 - ------------------------------------------------------------------------------ AFUDC $ 2,825 $ 4,767 Other income 675 1,699 Other expense (355) (1,418) - ------------------------------------------------------------------------------ Total other - net $ 3,145 $ 5,048 ============================================================================== Accrued liabilities in the Balance Sheets consist of the following: At December 31, - ----------------------------------------------------------------------------- (In thousands) 2004 2003 - ----------------------------------------------------------------------------- Accrued taxes $ 7,978 $ 15,979 Deferred income taxes 1,729 3,691 Accrued interest 4,458 5,710 Refunds to customers & customer deposits 13,240 5,124 Accrued salaries & other 10,398 8,115 - ----------------------------------------------------------------------------- Total accrued liabilities $ 37,803 $ 38,619 ============================================================================= 12. Segment Reporting The Company has two operating segments: (1) Gas Utility Services and (2) Electric Utility Services as defined by SFAS 131 "Disclosure About Segments of an Enterprise and Related Information" (SFAS 131). Gas Utility Services provides natural gas distribution and transportation services in southwestern Indiana, including counties surrounding Evansville. Electric Utility Services provides electricity primarily to southwestern Indiana, and includes the Company's power generating and marketing operations. For its operations the Company uses after tax operating income as a measure of profitability, consistent with regulatory reporting requirements. The Company cross manages its operations as separated between Energy Delivery, which includes the gas and electric transmission and distribution functions, and Power Supply, which includes the power generating and marketing operations. The Company makes decisions on finance and dividends at the corporate level. Information related to the Company's business segments is summarized below: Year Ended December 31, - ----------------------------------------------------------------------------- (In thousands) 2004 2003 - ----------------------------------------------------------------------------- Revenues Electric Utility Services $ 371,279 $ 335,694 Gas Utility Services 110,373 102,736 - ----------------------------------------------------------------------------- Total operating revenues $ 481,652 $ 438,430 ============================================================================= Profitability Measure Operating Income Electric Utility Services $ 65,697 $ 63,767 Gas Utility Services 5,070 4,856 - ----------------------------------------------------------------------------- Total operating income $ 70,767 $ 68,623 ============================================================================= Amounts Included in Profitability Measures Depreciation & Amortization Electric Utility Services $ 53,341 $ 42,627 Gas Utility Services 5,143 5,022 - ----------------------------------------------------------------------------- Total depreciation & amortization $ 58,484 $ 47,649 ============================================================================= Income Taxes Electric Utility Services $ 30,770 $ 29,808 Gas Utility Services 1,083 832 - --------------------------------------------------- ------------------------- Total income taxes $ 31,853 $ 30,640 ============================================================================= At December 31, - ----------------------------------------------------------------------------- (In thousands) 2004 2003 - ----------------------------------------------------------------------------- Assets Electric Utility Services $1,090,130 $ 974,576 Gas Utility Services 161,347 157,146 - ----------------------------------------------------------------------------- Total assets $1,251,477 $1,131,722 ============================================================================= Year Ended December 31, - ----------------------------------------------------------------------------- (In thousands) 2004 2003 - ----------------------------------------------------------------------------- Capital Expenditures Electric Utility Services $ 150,586 $ 124,058 Gas Utility Services 5,228 8,362 - ----------------------------------------------------------------------------- Total capital expenditures $ 155,814 $ 132,420 ============================================================================= 13. Impact of Recently Issued Accounting Guidance FIN 46/46-R (Revised in December 2003) In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 addresses consolidation by business enterprises of variable interest entities (VIE) and significantly changes the consolidation requirements for those entities. FIN 46 is intended to achieve more consistent application of consolidation policies related to VIE's and thus improves comparability between enterprises engaged in similar activities when those activities are conducted through VIE's. In December 2003, the FASB completed its deliberations of proposed modifications to FIN 46 and decided to codify both the proposed modifications and other decisions previously issued through certain FASB Staff Positions into one document that was issued as a revision to the original Interpretation (FIN 46R). FIN 46R currently applies to VIE's created after January 31, 2003, and to VIE's in which an enterprise obtains an interest after that date. For entities created prior to January 31, 2003, FIN 46R is to be adopted no later than the end of the first interim or annual reporting period ending after March 15, 2004. The Company has neither created nor obtained an interest in a VIE since January 31, 2003. Adoption of FIN 46R did not have a material impact on the Company's results of operations or financial position. 15. Quarterly Financial Data (Unaudited) Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company's utility operations. Summarized quarterly financial data for 2004 and 2003 follows: - -------------------------------------------------------------------------------- (In thousands) Q1 Q2 Q3 Q4 - -------------------------------------------------------------------------------- 2004 Results of Operations: Operating revenues $136,804 $104,621 $114,622 $125,605 Operating margin 71,673 64,119 77,126 73,633 Operating income 15,309 12,723 22,261 20,474 Net income applicable to common shareholder 10,040 7,221 16,744 14,561 2003 Results of Operations: Operating revenues $135,067 $89,600 $106,257 $107,506 Operating margin 68,325 56,685 71,328 66,016 Operating income 17,883 12,781 21,361 16,598 Net income applicable to common shareholder 13,381 6,050 16,182 13,221 The following discussion and analysis should be read in conjunction with the financial statements and notes thereto and the annual reports filed on Forms 10-K of both Vectren and VUHI. Executive Summary of Consolidated Results of Operations SIGECO generates revenue primarily from the delivery of natural gas and electric service to its customers. The primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services. Results are impacted by weather patterns in its service territory and general economic conditions both in its service territory as well as nationally. In 2004, Earnings were $48.6 million as compared to $48.8 million in 2003. The minor decrease in earnings is due to increased operating expenses, partially offset by margin growth. The primary expense changes were higher depreciation expense and maintenance costs. Margin growth results from the recovery of NOx related environmental expenditures, gas base rate increases implemented in 2004, and customer growth. During 2003, the Company initiated a base rate case for gas service territory. An order was received in July 2004, and on an annual basis, will increase margins an estimated $5.7 million. During 2004 the rate increase provided additional margin of $2.5 million. The order also allows for the recovery of pipeline integrity management costs capped at $750,000 in 2005 and $500,000 thereafter, with any costs greater than those amounts deferred for future recovery. The Company has sought and received regulatory recovery mechanisms (trackers) affecting electric margin that provide a return on utility plant constructed for environmental compliance and that allow for recovery of related operating expenses. After tax earnings associated with the NOx compliance trackers totaled $9.0 million in 2004 and $4.7 million in 2003. Significant Fluctuations Throughout this discussion, the terms Gas Utility margin and Electric Utility margin are used. Gas Utility margin and Electric Utility margin could be considered non-GAAP measures of income. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas. Electric Utility margin is calculated as Electric utility revenues less Fuel for electric generation and Purchased electric energy. These measures exclude Other operating expenses, Depreciation and amortization, and Taxes other than income taxes, which are included in the calculation of operating income. The Company believes Gas Utility and Electric Utility margins are better indicators of relative contribution than revenues since gas prices and fuel costs can be volatile and are generally collected on a dollar for dollar basis from customers. Margins should not be considered an alternative to, or a more meaningful indicator of, operating performance than operating income or net income as determined in accordance with accounting principles generally accepted in the United States. Margin Margin generated from the sale of natural gas and electricity to residential and commercial customers is seasonal and impacted by weather patterns in the Company's service territory. Margin generated from sales to large customers (generally industrial, other contract, and firm wholesale customers) is primarily impacted by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas costs, and is also impacted by some level of price sensitivity in volumes sold. Electric generating asset optimization activities are primarily affected by market conditions, the level of excess generating capacity, and electric transmission availability. Following is a discussion and analysis of margin generated from regulated utility operations. Electric Utility Margin (Electric Utility Revenues less Fuel for Electric Generation and Purchased Electric Energy) Electric Utility margin by revenue type follows: Year Ended December 31, - ------------------------------------------------------------------------ (In thousands) 2004 2003 - ------------------------------------------------------------------------ Residential & commercial $ 159,716 $ 141,061 Industrial 62,398 53,533 Municipalities & other 17,424 20,174 - ------------------------------------------------------------------------ Total retail & firm wholesale 239,538 214,768 Asset optimization 14,954 18,277 - ------------------------------------------------------------------------ Total electric utility margin $ 254,492 $ 233,045 ======================================================================== Retail & Firm Wholesale Margin Native load and firm wholesale margin was $239.5 million for the year ended December 31, 2004. This represents a $24.8 million increase over 2003. Additional NOx recoveries increased margin $14.6 million in 2004. Cooling weather for the year was 12% warmer than last year, increasing margin an estimated $2.0 million. The remaining increase in margin was attributable to increased small customer usage and increased sales to industrial customers. Due to the above factors, volumes sold increased 5% to 6.19 GWh for 2004, compared to 5.90 GWh in 2003. Margin from Asset Optimization Activities Periodically, generation capacity is in excess of that needed to serve native load and firm wholesale customers. The Company markets this unutilized capacity to optimize the return on its owned generation assets. Substantially all of the margin from these activities is generated from contracts that are integrated with portfolio requirements around power supply and delivery and are short-term purchase and sale transactions that expose the Company to limited market risk. Following is a reconciliation of asset optimization activity: Year Ended December 31, - ------------------------------------------------------------------------------ (In thousands) 2004 2003 - ------------------------------------------------------------------------------ Beginning of Year Net Asset Optimization Position $ (424) $ (718) Statement of Income Activity Mark-to-market gains (losses) recognized (1,399) 654 Realized gains (losses) recognized 16,353 17,623 - ------------------------------------------------------------------------------ Net activity in electric utility margin 14,954 18,277 - ------------------------------------------------------------------------------ Net cash received & other adjustments (15,156) (17,983) - ------------------------------------------------------------------------------ End of Year Net Asset Optimization Position $ (626) $ (424) ============================================================================== Net wholesale margins decreased $3.3 million compared to 2003 due to reduced available capacity. The availability of excess capacity was impacted by scheduled outages of owned generation, related to the installation of environmental compliance equipment and an increase in demand by native load customers due to both weather and increased usage. Gas Utility Margin (Gas Utility Revenues less Cost of Gas Sold) Gas Utility margin and throughput by customer type follows: Year Ended December 31, - ------------------------------------------------------------------------ (In thousands) 2004 2003 - ------------------------------------------------------------------------ Residential $ 20,296 $ 18,989 Commercial 5,734 5,367 Contract 4,625 4,024 Other 1,404 929 - ------------------------------------------------------------------------ Total gas utility margin $ 32,059 $ 29,309 ======================================================================== Volumes in MMDth: Sold to residential & commercial customers 11,548 12,495 Sold & transported to contract customers 18,701 19,052 - ------------------------------------------------------------------------ Total throughput 30,249 31,547 ======================================================================== Gas utility margins were $32.1 million for the year ended December 31, 2004. This represents an increase in gas utility margin of $2.8 million compared to 2003. Base rate increases added $2.5 million compared to the prior year. Heating weather for the year ended December 31, 2004, was 8% warmer than normal and 8% warmer than the prior year. The estimated unfavorable impact on gas utility margin caused by weather was approximately $0.8 million compared to 2003. Also offsetting the effects of weather were increased late and reconnect fees and customer growth. Gas sold and transported volumes were 4% less in 2004, compared to the prior year. The decreased throughput was primarily attributable to weather. The average cost per dekatherm of gas purchased was $6.31 in 2004 and $5.78 in 2003. Operating Expenses Other Operating Other operating expenses increased $9.1 million for the year ended December 31, 2004, as compared to 2003. NOx-related expenses recovered through rates increased $2.6 million. Maintenance expenses increased $3.5 million primarily due to planned turbine maintenance. Bad debt expense increased approximately $1.0 million due in part to higher gas costs. Year-over-year results were also affected by higher labor and benefit costs and increased corporate charges for use of shared assets. Depreciation & Amortization For the year ended December 31, 2004, depreciation expense increased $10.8 million compared to 2003. NOx-related depreciation contributed $4.8 million of the increase. The year-over-year increase also affected by a $3.6 million of additional depreciation resulting from a true-up of demand side management amortization to existing regulatory orders recorded during 2004. The remaining increase is primarily due to normal additions to utility plant. Upgrades implemented in 2002 and 2003 now included in annual depreciation expense include a gas-fired peaker unit, customer system upgrades, and other upgrades to existing transmission and distribution facilities. Income Taxes For the year ended December 31, 2004, income taxes were $1.2 million higher than 2003 primarily due to an increased effective rate. Taxes Other Than Income Taxes Taxes other than income taxes increased $0.9 million in 2004 compared to 2003. Almost all of the 2004 increase corresponds with increased collections of utility receipts taxes due to higher revenues. Other Income (Expense) Total other income (expense)-net decreased $1.9 million during 2004 compared to 2003. Lower amounts of AFUDC were recorded in 2004 as NOx expenditures were placed in service. Interest Expense In the second half of 2003, the Company completed permanent financing transactions in which short term borrowings from VUHI and $65 million of higher coupon third party debt were replaced with $25 million in equity and $61.9 in long-term debt payable to VUHI. The changes in interest expense in 2004 compared 2003 reflect the full impact of those transactions. Other Operating Matters MISO The FERC approved the Midwest Independent System Operator (MISO) as the nation's first regional transmission organization. Regional transmission organizations place public utility transmission facilities in a region under common control. The MISO is committed to reliability, the nondiscriminatory operation of the bulk power transmission system, and to working with all stakeholders to create cost-effective and innovative solutions. The Carmel, Indiana, based MISO began operations in December 2001 and serves the electrical transmission needs of much of the Midwest. In December 2001, the IURC approved the Company's request for authority to transfer operational control over its electric transmission facilities to the MISO. That transfer occurred on February 1, 2002. Pursuant to an order from the IURC, certain MISO costs have been deferred for future recovery. During 2004, SIGECO together with three other Indiana electric utilities filed a proceeding with the IURC seeking to recover the anticipated costs associated with MISO's implementation of the "Day 2 energy market" on April 1, 2005. A hearing considering this request occurred in February, 2005. As a result of MISO's operational control over much of the Midwestern electric transmission grid, including SIGECO's transmission facilities, SIGECO's continued ability to import power, when necessary, and export power to the wholesale market has been, and may continue to be, impacted. Given the nature of MISO's policies regarding use of transmission facilities, as well as ongoing FERC initiatives and uncertainties around the "Day 2 energy market" operations, it is difficult to predict near term operational impacts. However, as stated above, it is believed that MISO's regional operation of the transmission system will ultimately lead to reliability improvements. The potential need to expend capital for improvements to the transmission system, both to SIGECO's facilities as well as to those facilities of adjacent utilities, over the next several years will become more predictable as MISO completes studies related to regional transmission planning and improvements. Such expenditures may be significant. SELECTED ELECTRIC OPERATING STATISTICS: - ------------------------------------------------------------------------------ For the Year Ended December 31, ------------------------------ 2004 2003 - ------------------------------------------------------------------------------ OPERATING REVENUES (In thousands): Residential $ 119,753 $ 105,381 Commercial 92,867 82,268 Industrial 107,568 92,746 Misc. Revenue 3,694 7,185 ------------------------------ Total System 323,882 287,580 ------------------------------ Municipals 23,561 21,534 Other Wholesale 23,836 26,580 ------------------------------ $ 371,279 $ 335,694 ============================== MARGIN (In thousands): Residential $ 93,459 $ 81,950 Commercial 66,257 59,110 Industrial 62,398 53,533 Misc. Revenue 3,563 7,060 ------------------------------ Total System 225,677 201,653 ------------------------------ Municipals 13,861 13,115 Other Wholesale 14,954 18,277 ------------------------------ $ 254,492 $ 233,045 ============================== ELECTRIC SALES (In MWh): Residential 1,501,707 1,441,706 Commercial 1,501,513 1,422,127 Industrial 2,543,534 2,416,885 Misc. Sales 13,481 17,210 ------------------------------ Total System 5,560,235 5,297,928 ------------------------------ Municipals 625,925 600,924 Other Wholesale 3,526,005 4,305,190 ------------------------------ 9,712,165 10,204,042 ============================== YEAR END CUSTOMERS: Residential 118,998 117,868 Commercial 17,096 17,054 Industrial 152 155 All others 21 21 ------------------------------ 136,267 135,098 ============================== WEATHER AS A % OF NORMAL: Cooling Degree Days 90% 80% SELECTED GAS OPERATING STATISTICS: - ------------------------------------------------------------------------------ For the Year Ended December 31, ----------------------------- 2004 2003 - ------------------------------------------------------------------------------ OPERATING REVENUES (In thousands): Residential $ 71,713 $ 67,846 Commercial 29,933 28,468 Contract 7,361 5,545 Misc. Revenue 1,366 877 ----------------------------- $110,373 $102,736 ============================= MARGIN (In thousands): Residential $ 20,296 $ 18,989 Commercial 5,734 5,367 Contract 4,625 4,024 Misc. Revenue 1,404 930 ----------------------------- $ 32,059 $ 29,310 ============================= GAS SOLD & TRANSPORTED (In MDth): Residential 7,938 8,455 Commercial 3,610 4,040 Contract 18,701 19,052 ----------------------------- 30,249 31,547 ============================= YEAR END CUSTOMERS: Residential 101,611 101,204 Commercial 10,214 10,115 Contract 157 159 ----------------------------- 111,982 111,478 ============================= WEATHER AS A % OF NORMAL: Heating Degree Days 92% 98% EX-99.2 3 igc_dec04-reporting02.txt IGC FINANCIAL REPORT Ex. 99.2 INDIANA GAS COMPANY, INC. REPORTING PACKAGE For the year ended December 31, 2004 Contents Page Number Audited Financial Statements Report of Independent Registered Public Accounting Firm 1 Balance Sheets 2-3 Statements of Income 4 Statements of Cash Flows 5 Statements of Common Shareholder's Equity 6 Notes to Financial Statements 7 Results of Operations 20 Selected Operating Statistics 22 Basis of Presentation These annual financial statements should be read in conjunction with the audited annual consolidated financial statements and the notes thereto of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (VUHI), the parent companies of Indiana Gas, filed on Form 10-K for the year ended December 31, 2004. Vectren and VUHI make available their Securities and Exchange Commission filings and recent annual reports free of charge through its website at www.vectren.com. Frequently Used Terms AFUDC: allowance for funds used during MCF/MMCF/BCF: thousands/millions/ construction billions of cubic feet APB: Accounting Principles Board MDth/MMDth: thousands/millions of dekatherms EITF: Emerging Issues Task Force OUCC: Indiana Office of the Utility Consumer Counselor FASB: Financial Accounting Standards SFAS: Statement of Financial Board Accounting Standards FERC: Federal Energy Regulatory USEPA: United States Environmental Commission Protection Agency IDEM: Indiana Department of Throughput: combined gas sales and gas Environmental Management transportation volumes IURC: Indiana Utility Regulatory Commission INDEPENDENT AUDITORS'REPORT To the Shareholder and Board of Directors of Indiana Gas Company, Inc.: We have audited the accompanying balance sheets of Indiana Gas Company, Inc. (the "Company") as of December 31, 2004 and 2003, and the related statements of income, common shareholder's equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, such financial statements present fairly, in all material respects, the financial position of Indiana Gas Company, Inc. as of December 31, 2004 and 2003, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. /s/ DELOITTE & TOUCHE LLP - ----------------------------------------------- DELOITTE & TOUCHE LLP Indianapolis, Indiana February 23, 2005 FINANCIAL STATEMENTS INDIANA GAS COMPANY, INC. BALANCE SHEETS (In thousands) - -------------------------------------------------------------------------------- December 31, 2004 2003 - -------------------------------------------------------------------------------- ASSETS Utility Plant Original cost $ 1,251,508 $ 1,200,665 Less: accumulated depreciation & amortization 424,118 404,680 - -------------------------------------------------------------------------------- Net utility plant 827,390 795,985 - -------------------------------------------------------------------------------- Current Assets Cash & cash equivalents 1,624 2,856 Accounts receivable - less reserves of $447 & $1,940, respectively 58,554 45,079 Receivables due from other Vectren companies 234 5 Accrued unbilled revenues 86,334 63,582 Inventories 14,074 15,631 Recoverable fuel & natural gas costs 13,728 16,140 Prepayments & other current assets 66,442 70,157 - -------------------------------------------------------------------------------- Total current assets 240,990 213,450 - -------------------------------------------------------------------------------- Investment in the Ohio operations 220,779 222,020 Other investments 3,050 2,930 Non-utility property - net 152 202 Regulatory assets 19,890 21,237 Other assets 3,123 3,158 - -------------------------------------------------------------------------------- TOTAL ASSETS $ 1,315,374 $ 1,258,982 ================================================================================ The accompanying notes are an integral part of these financial statements. INDIANA GAS COMPANY, INC. BALANCE SHEETS (In thousands) December 31, 2004 2003 - -------------------------------------------------------------------------------- LIABILITIES & SHAREHOLDER'S EQUITY Capitalization Common Shareholder's Equity Common stock (no par value) $ 367,995 $ 367,995 Retained earnings 86,582 88,650 - -------------------------------------------------------------------------------- Total common shareholder's equity 454,577 456,645 - -------------------------------------------------------------------------------- Long-term debt payable to third parties - net of current maturities & debt subject to tender 167,417 196,417 Long-term debt payable to VUHI 184,448 184,448 - -------------------------------------------------------------------------------- Total capitalization 806,442 837,510 - -------------------------------------------------------------------------------- Commitments & Contingencies (Notes 3, 4, 7, 8 & 9) Current Liabilities Accounts payable 32,111 22,973 Accounts payable to affiliated companies 62,549 51,005 Payables to other Vectren companies 6,957 5,389 Accrued liabilities 48,072 36,530 Short-term borrowings payable to VUHI 109,211 63,974 Current maturities of long-term debt - 15,000 Long-term debt subject to tender 10,000 3,500 - -------------------------------------------------------------------------------- Total current liabilities 268,900 198,371 - -------------------------------------------------------------------------------- Deferred Income Taxes & Other Liabilities Deferred income taxes 75,576 63,890 Regulatory liabilities 132,825 123,646 Deferred credits & other liabilities 31,631 35,565 - -------------------------------------------------------------------------------- Total deferred credits & other liabilities 240,032 223,101 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- TOTAL LIABILITIES & SHAREHOLDER'S EQUITY $ 1,315,374 $1,258,982 ================================================================================ The accompanying notes are an integral part of these financial statements. INDIANA GAS COMPANY, INC. STATEMENTS OF INCOME (In thousands) For the Years Ended December 31, - -------------------------------------------------------------------------------- 2004 2003 - -------------------------------------------------------------------------------- OPERATING REVENUES $ 686,103 $ 668,214 COST OF GAS 474,452 450,674 - -------------------------------------------------------------------------------- GAS OPERATING MARGIN 211,651 217,540 - -------------------------------------------------------------------------------- OPERATING EXPENSES Other operating 89,820 85,814 Depreciation & amortization 45,049 43,250 Income taxes 10,915 16,054 Taxes other than income taxes 18,453 16,899 - -------------------------------------------------------------------------------- Total operating expenses 164,237 162,017 - -------------------------------------------------------------------------------- OPERATING INCOME (LOSS) 47,414 55,523 OTHER INCOME (EXPENSE) Equity in earnings (losses) of the Ohio operations - net of tax 7,207 5,817 Other income (expense) - net (832) (728) - -------------------------------------------------------------------------------- Total other income (expense) 6,375 5,089 - -------------------------------------------------------------------------------- Interest expense 29,353 29,081 - -------------------------------------------------------------------------------- NET INCOME (LOSS) $ 24,436 $ 31,531 ================================================================================ The accompanying notes are an integral part of these financial statements. INDIANA GAS COMPANY, INC. STATEMENTS OF CASH FLOWS (In thousands) For the Years Ended December 31, - -------------------------------------------------------------------------------- 2004 2003 - -------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 24,436 $ 31,531 Adjustments to reconcile net income to cash from operating activities: Depreciation & amortization 45,049 43,250 Deferred income taxes & investment tax credits 11,252 15,483 Pension & postretirement periodic benefit cost 1,588 1,549 Equity in earnings of the Ohio operations - net of tax (7,207) (5,817) Other non-cash charges - net 6,696 6,531 Changes in working capital accounts: Accounts receivable, including due from Vectren companies & accrued unbilled revenue (42,059) (2,347) Inventories 1,104 (2,345) Recoverable fuel & natural gas costs 2,412 (5,899) Prepayments & other current assets 3,827 (33,179) Accounts payable, including to Vectren companies & affiliated companies 22,250 (40,434) Accrued liabilities 10,868 5,605 Changes in noncurrent assets (362) 1,049 Changes in noncurrent liabilities (5,822) (4,830) - -------------------------------------------------------------------------------- Net cash flows from operating activities 74,032 10,147 - -------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from: Additional capital contribution - 125,000 Long-term term debt payable to VUHI - 37,140 Requirements for: Retirement of long-term debt, including premiums paid (37,500) (53,432) Dividend to parent (26,504) (21,942) Net change in short-term borrowings, including from VUHI 45,237 (44,208) - -------------------------------------------------------------------------------- Net cash flows from financing activities (18,767) 42,558 - -------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from: Distributions from Ohio operations 8,448 4,214 Requirements for : Capital expenditures (64,945) (57,792) - -------------------------------------------------------------------------------- Net cash flows from investing activities (56,497) (53,578) - -------------------------------------------------------------------------------- Cash, cash equivalents, & invested cash with other Vectren companies: Net increase (decrease) (1,232) (873) At beginning of period 2,856 3,729 - -------------------------------------------------------------------------------- At end of period $ 1,624 $ 2,856 ================================================================================ Cash paid during the year for: Interest $ 28,087 $ 29,591 Income taxes 17,342 23,120 The accompanying notes are an integral part of these financial statements. INDIANA GAS COMPANY, INC. STATEMENTS OF COMMON SHAREHOLDER'S EQUITY (In thousands) Common Retained Stock Earnings Total - -------------------------------------------------------------------------------- Balance at January 1, 2003 $ 242,995 $ 79,061 $ 322,056 Net income & comprehensive income 31,531 31,531 Common stock: Additional capital contribution 125,000 125,000 Dividends to parent (21,942) (21,942) - -------------------------------------------------------------------------------- Balance at December 31, 2003 $ 367,995 $ 88,650 $ 456,645 Net income & comprehensive income 24,436 24,436 Common stock: Dividends to parent (26,504) (26,504) - -------------------------------------------------------------------------------- Balance at December 31, 2004 $ 367,995 $ 86,582 $ 454,577 ================================================================================ The accompanying notes are an integral part of these financial statements. INDIANA GAS COMPANY, INC. NOTES TO THE FINANCIAL STATEMENTS 1. Organization and Nature of Operations Indiana Gas Company, Inc. (the Company or Indiana Gas), an Indiana corporation, provides energy delivery services to approximately 555,000 natural gas customers located in central and southern Indiana. Indiana Gas is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (VUHI). VUHI is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). Indiana Gas generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy and applied technology holding company headquartered in Evansville, Indiana. Investment in the Ohio Operations The Company holds a 47% interest in the Ohio operations and the remaining 53% is held by Vectren Energy Delivery of Ohio, Inc. (VEDO). VEDO is also a wholly owned subsidiary of Vectren. The Ohio operations provide energy delivery services to approximately 315,000 natural gas customers located near Dayton in west central Ohio. VEDO is the operator of the assets. Indiana Gas' ownership is accounted for using the equity method in accordance with APB Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock" and is included in investment in the Ohio operations, and its interest in the results of operations is included in equity in earnings of the Ohio operations. Additional information on the Company's investment in the Ohio operations is included in Note 3. 2. Summary of Significant Accounting Policies A. Cash & Cash Equivalents All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents. B. Inventories Inventories consist of the following: At December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Gas in storage - at LIFO cost $ 11,138 $ 13,335 Materials & supplies 1,914 - Other 1,022 2,296 - -------------------------------------------------------------------------------- Total inventories $ 14,074 $ 15,631 ================================================================================ Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2004, and 2003, by approximately $26 million and $22 million, respectively. All other inventories are carried at average cost. C. Utility Plant & Depreciation Utility plant is stated at historical cost, including AFUDC. Depreciation of utility property is provided using the straight-line method over the estimated service lives of the depreciable assets. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows: At & For the Year Ended December 31, - ------------------------------------------------------------------------------------------- (In thousands) 2004 2003 - ------------------------------------------------------------------------------------------- Depreciation Depreciation Percent of Percent of Original Original Original Original Cost Cost Cost Cost - ------------------------------------------------------------------------------------------- Utility plant $ 1,214,245 3.7% $ 1,164,699 3.9% Construction work in progress 37,263 - 35,966 - - ------------------------------------------------------------------------------------------- Total original cost $ 1,251,508 $ 1,200,665 ===========================================================================================
AFUDC represents the cost of borrowed and equity funds used for construction purposes and is charged to construction work in progress during the construction period and is included in Other - net in the Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows: Year Ended December 31, - ------------------------------------------------------------------------- (In thousands) 2004 2003 - ------------------------------------------------------------------------- AFUDC - borrowed funds $ 230 $ 106 AFUDC - equity funds 125 19 - ------------------------------------------------------------------------- Total AFUDC capitalized $ 355 $ 125 ========================================================================= Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred unless deferral is authorized by a rate order. When property that represents a retirement unit is replaced or removed, the cost of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation, and Regulatory liabilities for the cost of removal. D. Impairment Review of Long-Lived Assets Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires the evaluation for impairment involve the comparison of an asset's carrying value to the estimated 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 based on the difference between the asset's carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations. E. Regulation SFAS 71 Retail public utility operations affecting Indiana customers are subject to regulation by the IURC. The Company's accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS 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 rate-making process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the rate-making process. The Company assesses the recoverability of costs recognized as regulatory assets and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets. Regulatory assets consist of the following: At December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Future amounts recoverable from ratepayers: Income taxes $ 8,176 $ 8,915 Rate case expenses 548 - Other - 113 - -------------------------------------------------------------------------------- 8,724 9,028 Amounts deferred for future recovery: Other 290 - Amounts currently recovered through base rates: Unamortized debt issue costs & premiums paid to reacquire debt 10,876 12,209 - -------------------------------------------------------------------------------- Total regulatory assets $ 19,890 $ 21,237 ================================================================================ The $10.9 million currently being recovered through base rates is earning a return with a weighted average recovery period of 10.5 years. The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable. Cost of Removal and SFAS 143 The Company collects an estimated cost of removal of its utility plant through depreciation rates established by regulatory proceedings. The Company records amounts expensed in advance of payments as a regulatory liability because the liability does not meet the threshold of a legal asset retirement obligation (ARO) as defined by SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). At December 31, 2004, and 2003, such removal costs approximated $133 million and $124 million, respectively. SFAS 143 requires entities to record the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred. The Company adopted this statement on January 1, 2003. The adoption was not material to the Company's results of operations. Refundable or Recoverable Gas Costs All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. The Company records any under-or-over-recovery resulting from gas adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under-or- over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers. F. Revenues Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas delivered to customers but not billed at the end of the accounting period. G. Utility Receipts Taxes A portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of Operating revenues. Utility receipts taxes paid are recorded as a component of Taxes other than income taxes. H. Earnings Per Share Earnings per share are not presented as Indiana Gas' common stock is wholly owned by Vectren Utility Holdings, Inc. I. Other Significant Policies Included elsewhere in these notes are significant accounting policies related to the investment in the Ohio operations (Note 3), intercompany allocations and income taxes (Note 4) and derivatives (Note 10). 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. 3. Investment in the Ohio Operations The Company's investment in the Ohio operations is accounted for using the equity method of accounting, and the investment is periodically examined for other than temporary declines in value. The Company's share of the Ohio operations after tax earnings is recorded in equity in earnings of the Ohio operations. Because the Ohio operations is responsible for its income taxes and is also within Vectren's consolidated tax group, no additional tax provision for these earnings is included in these financial statements. Dividends are recorded as a reduction of the carrying value of the investment when received. Goodwill which is a component of the Company's net investment is accounted for in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). SFAS 142 uses an impairment-only approach to account for the effect of goodwill on the operating results. Following is summarized financial data of the Ohio operations: Year Ended December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Operating revenues $ 329,729 $ 341,362 Gas operating margin 104,020 102,998 Operating income 15,600 11,759 Net income 15,334 12,376 At December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Net utility plant $ 285,244 $ 267,968 Current assets 142,341 130,708 Goodwill - net 199,457 199,457 Other non-current assets 9,826 9,970 - -------------------------------------------------------------------------------- Total assets $ 636,868 $ 608,103 ================================================================================ Owners' net investment $ 431,619 $ 434,401 Current liabilities 110,263 93,049 Noncurrent liabilities 94,986 80,653 - -------------------------------------------------------------------------------- Total liabilities & owners' net investment $ 636,868 $ 608,103 ================================================================================ Gas Cost Recovery (GCR) Audit Proceedings There is an Ohio requirement that Ohio gas utilities undergo a biannual audit of their gas acquisition practices in connection with the gas cost recovery (GCR) mechanism. In the case of VEDO, a two-year audit period ended in November 2002. That audit period provided the PUCO staff its initial review of the portfolio administration arrangement between VEDO and ProLiance. The external auditor retained by the PUCO staff submitted an audit report in the fall of 2003 wherein it recommended a disallowance of approximately $7 million of previously recovered gas costs. The Company believes a large portion of the third party auditor recommendations is without merit. A hearing has been held, and the PUCO staff has recommended a $6.1 million disallowance. The Ohio Consumer Counselor has recommended an $11.5 million disallowance. For this PUCO audit period, any disallowance relating to the Company's ProLiance arrangement will be shared by the Company's joint venture partner. Based on a review of the matters, the Company has recorded $1.1 million for its estimated share of a potential disallowance. A PUCO decision on this matter is yet to be issued. The Company is also unable to determine the effects that a PUCO decision for the audit period ended in November 2002 may have on results in audit periods beginning after November 2002. VEDO Pending Base Rate Increase Settlement On February 4, 2005, the Company filed with the PUCO a settlement agreement that had been entered into with several parties, including the PUCO staff, in its base rate case. The Ohio Office of the Consumer Counselor (OCC) is opposing the settlement. Earlier in 2004 VEDO had filed with the PUCO a request to adjust its base rates and charges for its gas distribution business serving more than 315,000 customers located in west central Ohio. The settlement provides for a $15.7 million increase in VEDO's base distribution rates to cover the ongoing costs of operating, maintaining, and expanding the approximately 5,200-mile distribution system. The settlement increase includes $1.1 million of funding for weatherization and conservation programs for low income customers. Evidentiary hearings were completed in the case on February 9, 2005. Review and approval by the PUCO is necessary before the settlement is effective. The proposed new rate design includes a larger service charge, which will address, to some extent, earnings volatility related to weather. The settlement also permits VEDO the annual recovery of on-going costs associated with the Pipeline Safety Improvement Act of 2002. Based upon the PUCO's actions in other proceedings, the Company would expect an order near the end of the first quarter of 2005. Ohio Uncollectible Accounts Expense Tracker On December 17, 2003, the PUCO approved a request by VEDO and several other regulated Ohio gas utilities to establish a mechanism to recover uncollectible account expense outside of base rates. The tariff mechanism establishes an automatic adjustment procedure to track and recover these costs instead of providing the recovery of the historic amount in base rates. Through this order, VEDO received authority to defer its 2003 uncollectible accounts expense to the extent it differs from the level included in base rates. The Company estimated the difference to approximate $4 million in excess of that included in base rates, and reversed and deferred that amount for future recovery. In 2004, the Company recorded revenues of $3.3 million which is equal to the level of uncollectible accounts expense recognized for Ohio residential customers. 4. Transactions with Other Vectren Companies Support Services and Purchases Vectren and certain subsidiaries of Vectren provided corporate and general and administrative services to the Company including legal, technology, finance, tax, risk management, human resources, which includes charges for restricted stock compensation and for pension and other postretirement benefits not directly charged to subsidiaries. These costs have been allocated using various allocators, primarily number of employees, number of customers and/or revenues. Allocations are based on cost. Indiana Gas received corporate allocations totaling $56.7 million and $58.0 million for the years ended December 31, 2004, and 2003, respectively. Retirement Plans and Other Postretirement Benefits Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 87 "Employers' Accounting for Pensions" and SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions," respectively. An allocation of expense is determined by Vectren's actuaries, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the FAS 87/106 liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with "multiemployer" benefit accounting as described in SFAS 87 and 106. For the years ended December 31, 2004, and 2003, periodic pension costs totaling $1.3 million and $1.2 million, respectively, were directly charged by Vectren to the Company. For the years ended December 31, 2004, and 2003, other periodic postretirement benefit costs totaling $0.3 million and $0.3 million, respectively, were directly charged by Vectren to the Company. As of December 31, 2004, and 2003, $18.3 million and $22.2 million, respectively, is included in Deferred credits & other liabilities and represents expense directly charged to the Company that is yet to be funded to Vectren, and $2.4 million and $2.2 million, respectively, is included in Other assets for amounts funded in advance to Vectren. Cash Management and Borrowing Arrangements The Company participates in a centralized cash management program with Vectren, other wholly owned subsidiaries, and banks which permits funding of checks as they are presented. See Note 6 regarding long-term and short-term intercompany borrowing arrangements. Share-Based Incentive Plans In December 2004, the FASB issued Statement 123 (revised 2004), "Share-Based Payments" (SFAS 123R) that will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) replaces FASB Statement No. 123, "Accounting for Stock-Based Compensation" and supersedes APB Opinion No. 25, "Accounting for Stock Issued to Employees." The effective date of SFAS 123R for the Company is July 1, 2005. SFAS 123R provides for multiple transition methods, and the Company is still evaluating potential methods for adoption. Indiana Gas does not have share-based compensation plans separate from Vectren. An insignificant number of the Company's employees participate in Vectren's share- based compensation plans. The adoption of this standard is not expected to have any material effect on the Company's operating results or financial condition. Guarantees of Parent Company Debt Vectren's three operating utility companies, Indiana Gas, Southern Indiana Gas and Electric Company, Inc. (SIGECO) and VEDO are guarantors of VUHI's $350 million in short-term credit facilities, of which approximately $308.0 million is outstanding at December 31, 2004, and VUHI's $550 million unsecured senior notes outstanding at December 31, 2004. The guarantees are full and unconditional and joint and several, and VUHI has no subsidiaries other than the subsidiary guarantors. Income Taxes Vectren and subsidiary companies file a consolidated federal income tax return. For financial reporting purposes, Indiana Gas' current and deferred tax expense is computed on a separate company basis. A reconciliation of the federal statutory rate to the effective income tax rate follows: Year Ended December 31, - -------------------------------------------------------------------------------- 2004 2003 - -------------------------------------------------------------------------------- Statutory rate 35.0 % 35.0 % State & local taxes, net of federal benefit 7.4 6.4 Amortization of investment tax credit (3.2) (2.2) All other - net (0.4) (0.8) - -------------------------------------------------------------------------------- Effective tax rate 38.8 % 38.4 % ================================================================================ The components of income tax expense and utilization of investment tax credits follow: Year Ended December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Current: Federal $ (1,800) $ (3,127) State 1,463 3,698 - -------------------------------------------------------------------------------- Total current taxes (337) 571 - -------------------------------------------------------------------------------- Deferred: Federal 10,422 15,981 State 1,744 423 - -------------------------------------------------------------------------------- Total deferred taxes 12,166 16,404 - -------------------------------------------------------------------------------- Amortization of investment tax credits (914) (921) - -------------------------------------------------------------------------------- Total income taxes $ 10,915 $ 16,054 ================================================================================ The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow: At December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Non-current deferred tax liabilities (assets): Depreciation & cost recovery timing differences $ 78,826 $ 66,655 Regulatory assets recoverable through future rates 10,080 11,311 Regulatory liabilities to be settled through future rates (1,904) (2,396) Employee benefit obligations (9,982) (11,695) Other - net (1,444) 15 - -------------------------------------------------------------------------------- Net non-current deferred tax liability 75,576 63,890 - -------------------------------------------------------------------------------- Current deferred tax liability: Deferred fuel costs - net 2,729 3,118 - -------------------------------------------------------------------------------- Net deferred tax liability $ 78,305 $ 67,008 ================================================================================ At December 31, 2004, and 2003, investment tax credits totaling $3.5 million and $4.4 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments. The Company has no tax credit carryforwards at December 31, 2004. 5. Transactions with Vectren Affiliates ProLiance Energy, LLC ProLiance Energy, LLC (ProLiance), a nonregulated energy marketing affiliate of Vectren and Citizens Gas and Coke Utility (Citizens Gas), provides natural gas and related services to Indiana Gas, SIGECO, the Ohio operations, Citizens Gas and others. ProLiance's primary business is optimizing the gas portfolios of utilities and providing services to large end use customers. Transactions with ProLiance Purchases from ProLiance for resale and for injections into storage for the years ended December 31, 2004, and 2003, totaled $479.5 million and $451.8 million, respectively. Amounts owed to ProLiance at December 31, 2004, and 2003, for those purchases were $61.8 million and $50.7 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with each utility. Other Affiliate Transactions Vectren has ownership interests in other affiliated companies accounted for using the equity method of accounting that perform underground construction and repair, facilities locating, and meter reading services to the Company. For the years ended December 31, 2004, and 2003, fees for these services and construction-related expenditures paid by the Company to Vectren affiliates totaled $20.9 million and $25.4 million, respectively. Amounts charged by these affiliates are market based. Amounts owed to unconsolidated affiliates other than ProLiance totaled $0.8 million and $0.3 million at December 31, 2004, and 2003, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. 6. Borrowing Arrangements & Other Financing Transactions Long-Term Debt Senior unsecured obligations outstanding and classified as long-term follow: At December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Fixed Rate Senior Unsecured Notes Payable to VUHI: 2011, 6.625% $ 98,953 $ 98,953 2018, 5.75% 37,140 37,140 2031, 7.25% 48,355 48,355 - -------------------------------------------------------------------------------- Total long-term debt payable to VUHI $ 184,448 $ 184,448 ================================================================================ Fixed Rate Senior Unsecured Notes Payable to Third Parties: 2004, Series F, 6.36% $ - $ 15,000 2007, Series E, 6.54% 6,500 6,500 2013, Series E, 6.69% 5,000 5,000 2015, Series E, 7.15% 5,000 5,000 2015, Insured Quarterly, 7.15% - 20,000 2015, Series E, 6.69% 5,000 5,000 2015, Series E, 6.69% 10,000 10,000 2025, Series E, 6.53% 10,000 10,000 2027, Series E, 6.42% 5,000 5,000 2027, Series E, 6.68% 1,000 3,500 2027, Series F, 6.34% 20,000 20,000 2028, Series F, 6.36% 10,000 10,000 2028, Series F, 6.55% 20,000 20,000 2029, Series G, 7.08% 30,000 30,000 2030, Insured Quarterly, 7.45% 49,917 49,917 - -------------------------------------------------------------------------------- Total long-term debt outstanding payable to third parties 177,417 214,917 Current maturities - (15,000) Debt subject to tender (10,000) (3,500) - -------------------------------------------------------------------------------- Long-term debt payable to third parties - net of current maturities & debt subject to tender $ 167,417 $ 196,417 ================================================================================ Issuances Payable to VUHI in 2003 In 2003, the Company issued $37.1 million of long-term debt payable to VUHI. The note has terms identical to the terms of notes issued by VUHI in July 2003 through a public offering. Those notes have an interest rate of 5.75% priced at 99.177% to yield 5.80% to maturity and are due August 2018. They have no sinking fund requirements, and interest payments are due semi-annually. The notes may be called by VUHI, in whole or in part, at any time for an amount equal to accrued and unpaid interest, plus the greater of 100% of the principal amount or the sum of the present values of the remaining payments of principal and interest, discounted to the redemption date on a semi-annual basis at the Treasury Rate, as defined in VUHI's indenture, plus 25 basis points. At present, VUHI has no intent to call the notes; therefore the notes are classified as long term on the accompanying Balance Sheets. Debt Call During 2004, the Company called $20.0 million of insured quarterly senior unsecured notes. The notes, originally due in 2015, were called at par. During 2003, the Company called two senior unsecured notes. The first note had a remaining principal amount of $21.3 million, an interest rate of 9.375%, was originally due in 2021, and was redeemed at 105.525% of the stated principal amount. The second note had a principal amount of $13.5 million, an interest rate of 6.75%, was originally due in 2028, and was redeemed at the principal amount. Pursuant to regulatory authority, the premiums paid to retire the net carrying value of these notes totaling $1.1 million were deferred as a regulatory asset. The proceeds to fund the early redemption were received from VUHI in the form of new long-term debt discussed above and $125 million in additional equity. To generate the initial proceeds to fund these transactions, in July 2003, VUHI completed a public offering of long-term debt netting proceeds of approximately $203 million, and Vectren completed a public offering of common stock in August 2003 netting proceeds of approximately $163 million. Other Debt Payments Other Company debt totaling $17.5 million in 2003 was retired pursuant to normal terms. Long-Term Debt Sinking Fund Requirements & Maturities Maturities and sinking fund requirements on long-term debt during the five years following 2004 (in millions) are zero in 2005, zero in 2006, $6.5 in 2007, zero in 2008 and zero in 2009. Long-Term Debt Put & Call Provisions Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. The put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. Debt which may be put to the Company during the years following 2004 (in millions) is $10.0 in 2005, zero in 2006, $20.0 in 2007, zero in 2008, and $40.0 thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities. Short-Term Borrowings As of December 31, 2004, the Company has no short-term borrowing arrangements with third parties and relies entirely on the short-term borrowing arrangements of VUHI for short-term working capital needs. Borrowings outstanding at December 31, 2004, and 2003, were $109.2 million and $64.0 million, respectively. The intercompany credit line totals $325 million, but is limited to VUHI's available capacity ($42 million of additional capacity at December 31, 2004) and is subject to the same terms and conditions as VUHI's commercial paper program. Short-term borrowings bear interest at VUHI's weighted average daily cost of short-term funds. See the table below for interest rates and outstanding balances. Year ended December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Weighted average total outstanding during the year due from VUHI (in thousands) $ 31,151 $ 97,178 Weighted average interest rates during the year: VUHI 1.86% 1.35% Covenants Borrowing arrangements contain customary default provisions; restrictions on liens, sale leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2004, the Company was in compliance with all financial covenants. 7. Commitments & Contingencies Commitments Firm purchase commitments for commodities total $9.6 million in 2005. Legal Proceedings The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 8 regarding environmental matters. 8. Environmental Matters In the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, Indiana Gas and others may now be required to take remedial action if certain byproducts are found above the regulatory thresholds at these sites. Indiana Gas has identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas has completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Although Indiana Gas has not begun an RI/FS at additional sites, Indiana Gas has submitted several of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary. In conjunction with data compiled by environmental consultants, Indiana Gas has accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded costs that it reasonably expects to incur totaling approximately $20.4 million. The estimated accrued costs are limited to Indiana Gas' proportionate share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas' share of response costs at these 19 sites to between 20% and 50%. With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers in an aggregate amount approximating $20.4 million. Environmental matters related to manufactured gas plants have had no material impact on earnings since costs recorded to date approximate PRP and insurance settlement recoveries. While Indiana Gas has recorded all costs which it presently expects to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen. 9. Rate & Regulatory Matters Gas Base Rate Settlement On November 30, 2004, the IURC approved a $24 million base rate increase for Indiana Gas' gas distribution business. The new rate design includes a larger service charge, which is intended to address to some extent earnings volatility related to weather. The base rate change in Indiana Gas' service territory was implemented on December 1, 2004, resulting in additional 2004 revenues of $2.2 million. The order also permits Indiana Gas to recover the on-going costs to comply with the Pipeline Safety Improvement Act of 2002. The Pipeline Safety Improvement Tracker provides for the recovery of incremental non-capital dollars, capped at $750,000 the first year and $2.5 million per year thereafter. Any costs incurred in excess of these annual caps are to be deferred for future recovery. 10. Derivatives & Other Financial Instruments Accounting Policy for Derivatives The Company executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and managing risk. When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale, it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or non-current assets or liabilities depending on their value and on when the contracts are expected to be settled. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges or as an adjustment to the underlying's basis for fair value hedges. The ineffective portion of hedging arrangements is marked-to-market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for all derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company's use of mark-to-market accounting related to natural gas procurement. The Company's operations have limited exposure to commodity price risk for purchases and sales of natural gas for retail customers due to current Indiana regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas cost adjustment mechanisms. Although the Company's operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including unrecoverable interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price- sensitive reduction in volumes sold. The Company mitigates these risks by executing derivative contracts that manage the price of forecasted natural gas purchases. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. The market value of natural gas procurement derivative contracts at December 31, 2004 was not significant. Fair Value of Other Financial Instruments The carrying values and estimated fair values of the Company's other financial instruments follow: At December 31, - --------------------------------------------------------------------------------------------------- 2004 2003 --------------------------- ------------------------------ (In thousands) Carrying Est. Fair Carrying Est. Fair Amount Value Amount Value - ------------------------------------ ---------------------------- ------------------------------ Long-term debt due to third parties $ 177,417 $ 184,300 $ 214,917 $227,290 Long-term debt due to VUHI 184,448 202,406 184,448 200,823 Short-term debt due to VUHI 109,211 109,211 63,974 63,974 - ----------------------------------------------------------------------------------------------------
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's other financial instruments was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value. Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's financial position or results of operations. 11. Additional Operational & Balance Sheet Information Other - net in the Statements of Income consists of the following: Year Ended December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- AFUDC $ 355 $ 125 Other income 381 696 Interest income 197 - Other expense (1,765) (1,549) - -------------------------------------------------------------------------------- Total other - net $ (832) $ (728) ================================================================================ Prepayments and other current assets in the Balance Sheets consist of the following: At December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Prepaid gas delivery service $ 58,490 $ 45,820 Prepaid taxes 7,069 22,974 Other prepayments & current assets 883 1,363 - -------------------------------------------------------------------------------- Total prepayments & other current assets $ 66,442 $ 70,157 ================================================================================ Accrued liabilities in the Balance Sheets consist of the following: At December 31, - -------------------------------------------------------------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Accrued taxes $11,125 $10,443 Refunds to customers & customer deposits 13,618 10,362 Accrued interest 2,937 4,293 Deferred income taxes 2,729 3,118 Other 17,663 8,314 - -------------------------------------------------------------------------------- Total accrued liabilities $ 48,072 $ 36,530 ================================================================================ 12. Impact of Recently Issued Accounting Guidance FIN 46/46-R (Revised in December 2003) In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46 addresses consolidation by business enterprises of variable interest entities (VIE) and significantly changes the consolidation requirements for those entities. FIN 46 is intended to achieve more consistent application of consolidation policies related to VIE's and thus improves comparability between enterprises engaged in similar activities when those activities are conducted through VIE's. In December 2003, the FASB completed its deliberations of proposed modifications to FIN 46 and decided to codify both the proposed modifications and other decisions previously issued through certain FASB Staff Positions into one document that was issued as a revision to the original Interpretation (FIN 46R). FIN 46R currently applies to VIE's created after January 31, 2003, and to VIE's in which an enterprise obtains an interest after that date. For entities created prior to January 31, 2003, FIN 46R is to be adopted no later than the end of the first interim or annual reporting period ending after March 15, 2004. The Company has neither created nor obtained an interest in a VIE since January 31, 2003. Adoption of FIN 46R did not have a material impact on the Company's results of operations or financial position. 13. Quarterly Financial Data (Unaudited) Information in any one quarterly period is not indicative of annual results due to the seasonal variations common to the Company's utility operations. Summarized quarterly financial data for 2004 and 2003 follows: - -------------------------------------------------------------------------------- (In thousands) Q1 Q2 Q3 Q4 - -------------------------------------------------------------------------------- 2004 Results of Operations: Operating revenues 298,666 $98,607 $ 71,059 $ 217,771 Gas operating margin 83,892 36,182 27,786 63,791 Operating income (loss) 29,426 2,665 (3,025) 18,348 Net income (loss) 27,043 (5,113) (11,074) 13,580 2003 Results of Operations: Operating revenues $ 295,380 $ 104,846 $ 73,606 $ 194,382 Gas operating margin 86,396 40,312 27,698 63,134 Operating income (loss) 32,631 6,175 (2,125) 18,842 Net income (loss) 30,172 (3,134) (11,136) 15,629 The following discussion and analysis should be read in conjunction with the financial statements and notes thereto and the annual reports filed on Forms 10-K of both Vectren and VUHI. Executive Summary of Results of Operations Indiana Gas generates revenue primarily from the delivery of natural gas service to its customers. The primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas services. Results are impacted by weather patterns in its service territory and general economic conditions both in its service territory as well as nationally. In 2004, Earnings were $24.4 million as compared to $31.5 million in 2003. The $7.1 million decrease in earnings is due primarily to weather which decreased earnings an estimated $4.3 million after tax, and increased operating expenses. During 2004, the Company initiated a base rate case for gas service territory. An order was received in December 2004, and on an annual basis, will increase margins an estimated $24.0 million. During 2004 the rate increase provided additional margin of $2.2 million. The order also allows for the recovery of pipeline integrity management costs capped at $2.5 million beginning in 2006, with any costs greater than those amounts deferred for future recovery. Significant Fluctuations Gas Operating Margin Margin generated from the sale of natural gas to residential and commercial customers is seasonal and impacted by weather patterns in the Company's service territory. Margin generated from sales to large customers (generally industrial and other contract customers) is impacted primarily by overall economic conditions. Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas costs, and is also impacted by some level of price sensitivity in volumes sold. Following is a discussion and analysis of margin generated from regulated utility operations. - -------------------------------------------------------------------------------- For the year Ended December 31, ---------------------------- (In thousands) 2004 2003 - -------------------------------------------------------------------------------- Residential & commercial $ 183,382 $ 186,649 Contract 26,916 26,379 Other 1,353 4,512 - -------------------------------------------------------------------------------- Total gas utility margin $ 211,651 $ 217,540 ================================================================================ Volumes in MDth: Sold to residential & commercial customers 63,755 68,316 Sold & transported to contract customers 50,899 51,290 - -------------------------------------------------------------------------------- Total throughput 114,654 119,606 ================================================================================ Gas utility margins were $211.7 million for the year ended December 31, 2004. This represents a decrease in gas utility margin of $5.9 million compared to 2003. Heating weather for the year ended December 31, 2004, was 8% warmer than normal and 8% warmer than the prior year. The estimated unfavorable impact on gas utility margin caused by weather was approximately $7.2 million compared to 2003. Indiana base rate increases added $2.2 million compared to the prior year. Also offsetting the effects of weather were increased late and reconnect fees, and customer growth. Gas sold and transported volumes were 4% less in 2004, compared to the prior year. The decreased throughput was primarily attributable to weather. The average cost per dekatherm of gas purchased was $7.10 in 2004 and $6.53 in 2003. Operating Expenses Other Operating Other operating expenses increased $4.0 million for the year ended December 31, 2004, as compared to 2003. The increase is primarily attributable to increased charges for use of corporate assets, which increased $3.3 million. The remaining year over year increase was primarily attributable to increased labor and benefit costs. Depreciation & Amortization For the year ended December 31, 2004, depreciation expense increased $1.8 million compared to 2003. The increase resulted primarily from normal additions to utility plant. Income Taxes For the year ended December 31, 2004, income taxes were $5.1 million lower than 2003 primarily due to decreased earnings before taxes and equity in earnings from the Ohio operations. Taxes Other Than Income Taxes Taxes other than income taxes increased $1.6 million in 2004 compared to 2003. Almost all of the 2004 increase corresponds with increased collections of utility receipts taxes due to higher revenues. Other Income Equity in Earnings of the Ohio Operations Equity in earnings of the Ohio operations represents Indiana Gas' 47% interest in the Ohio operations' net income. The financing costs associated with VEDO's 53% ownership interest are not included in the Ohio operations' equity in earnings. Earnings in 2004 have increased over 2003 primarily due to lower depreciation in 2004 compared to 2003 due to a true-up of depreciation rates to existing regulatory orders and decreased operating expenses in 2004 due to the effects of regulatory orders associated with Ohio choice programs and uncollectible accounts expense. The Ohio operations' net income was $15.3 million in 2004 and $12.4 million in 2003. Indiana Gas' share of those earnings was $7.2 million and 5.8 million, respectively. Interest costs arising from financing arrangements utilized for the purchase of the Ohio operations are not reflected in the above-summarized financial information. Had the financing arrangements of Indiana Gas and VEDO used to facilitate the purchase of the Ohio operations been pushed down, the net income would have been $6.0 million and $2.9 million for the years ended December 31, 2004 and 2003, respectively. SELECTED GAS OPERATING STATISTICS: - -------------------------------------------------------------------------------- For the Year Ended December 31, ------------------------------- 2004 2003 - -------------------------------------------------------------------------------- OPERATING REVENUES (In thousands): Residential $ 462,507 $ 452,042 Commercial & Contract 216,942 210,047 Misc Revenue 6,654 6,125 ---------------------------- $ 686,103 $ 668,214 ============================ MARGIN (In thousands): Residential $ 141,875 $ 144,945 Commercial & Contract 68,423 68,081 Misc Revenue 1,353 4,514 ---------------------------- $ 211,651 $ 217,540 ============================ GAS SOLD & TRANSPORTED (In MDth): Residential 44,661 48,146 Commercial & Contract 69,993 71,460 ---------------------------- 114,654 119,606 ============================ YEAR END CUSTOMERS: Residential 506,713 498,340 Commercial & Contract 49,256 48,574 ---------------------------- 555,969 546,914 ============================ WEATHER AS A % OF NORMAL: Heating Degree Days 92% 100% EX-99.3 4 vvc8k_exh99-3.txt SAFE HARBO STATEMENT Ex. 99.3 Forward-Looking Information A "safe harbor" for forward-looking statements is provided by the Private Securities Litigation Reform Act of 1995 (Reform Act of 1995). The Reform Act of 1995 was adopted to encourage such forward-looking statements without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Certain matters described in Management's Discussion and Analysis of Results of Operations and Financial Condition are forward-looking statements. Such statements are based on management's beliefs, as well as assumptions made by and information currently available to management. When used in this filing, the words "believe," "anticipate," "endeavor," "estimate," "expect," "objective," "projection," "forecast," "goal," and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause Vectren Corporation and its subsidiaries' actual results to differ materially from those contemplated in any forward-looking statements include, 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 electric and natural gas transmission and distribution, natural gas gathering and processing, electric power supply; and similar entities with regulatory oversight. o Economic conditions including the effects of an economic downturn, inflation rates, commodity prices, 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 to, price, basis, credit, liquidity, volatility, capacity, interest rate, and warranty risks. o The performance of projects undertaken by the Company's nonregulated businesses and the success of efforts to invest in and develop new opportunities, including but not limited to, the realization of Section 29 income tax credits and the Company's coal mining, gas marketing, and broadband strategies. o Direct or indirect effects on our business, financial condition or liquidity resulting from a change in credit ratings, changes in interest rates, and/or changes in market perceptions of the utility industry and other energy-related industries. o Employee or contractor 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 Management's Discussion and Analysis of Results of Operations and Financial Condition. o Changes in Federal, state or local legislature requirements, such as changes in tax laws or rates, environmental laws and regulations. Vectren Corporation and its subsidiaries 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. -----END PRIVACY-ENHANCED MESSAGE-----