-----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, Vt52By3JITf2mjETfPk2BIFJTiLi5eDPo56ruaTavI+2dXYkifDAuyVwpHm2+lrO Yapg6vO3iOZhIPxwAnSSxA== 0000052485-96-000012.txt : 19960816 0000052485-96-000012.hdr.sgml : 19960816 ACCESSION NUMBER: 0000052485-96-000012 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19960630 FILED AS OF DATE: 19960814 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: IES UTILITIES INC CENTRAL INDEX KEY: 0000052485 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 420331370 STATE OF INCORPORATION: IA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-04117 FILM NUMBER: 96612449 BUSINESS ADDRESS: STREET 1: 200 FIRST ST SE STREET 2: IES TOWER CITY: CEDAR RAPIDS STATE: IA ZIP: 52401 BUSINESS PHONE: 3193984411 FORMER COMPANY: FORMER CONFORMED NAME: IOWA ELECTRIC LIGHT & POWER CO DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: IOWA RAILWAY & LIGHT CORP DATE OF NAME CHANGE: 19670629 10-Q 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark one) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 0-4117-1 IES UTILITIES INC. (Exact name of registrant as specified in its charter) Iowa 42-0331370 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) IES Tower, Cedar Rapids, Iowa 52401 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (319) 398-4411 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___ Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Class Outstanding at July 31, 1996 Common Stock, $2.50 par value 13,370,788 shares IES UTILITIES INC. INDEX Page No. Part I. Financial Information. Item 1. Consolidated Financial Statements. Consolidated Balance Sheets - June 30, 1996 and December 31, 1995 3 - 4 Consolidated Statements of Income - Three, Six and Twelve Months Ended June 30, 1996 and 1995 5 Consolidated Statements of Cash Flows - Three, Six and Twelve Months Ended June 30, 1996 and 1995 6 Notes to Consolidated Financial Statements 7 - 19 Item 2. Management's Discussion and Analysis of the Results of Operations and Financial Condition. 20 - 42 Part II. Other Information. 43 - 45 Signatures. 46 PART 1. - FINANCIAL INFORMATION ITEM 1. - CONSOLIDATED FINANCIAL STATEMENTS CONSOLIDATED BALANCE SHEETS June 30, 1996 December 31, ASSETS (Unaudited) 1995 (in thousands) Property, plant and equipment: Utility - Plant in service - Electric $ 1,921,426 $ 1,900,157 Gas 167,760 165,825 Other 109,088 106,396 2,198,274 2,172,378 Less - Accumulated depreciation 996,595 950,324 1,201,679 1,222,054 Leased nuclear fuel, net of amortization 40,532 36,935 Construction work in progress 82,070 52,772 1,324,281 1,311,761 Other, net of accumulated depreciation and amortization of $1,356,000 and $1,166,000, respectively 5,123 5,477 1,329,404 1,317,238 Current assets: Cash and temporary cash investments 118 2,734 Accounts receivable - Customer, less reserve 11,497 18,619 Other 8,059 8,912 Income tax refunds receivable 8,572 846 Production fuel, at average cost 12,821 12,155 Materials and supplies, at average cost 22,399 27,229 Regulatory assets 24,772 22,791 Prepayments and other 10,266 18,556 98,504 111,842 Investments: Nuclear decommissioning trust funds 52,084 47,028 Cash surrender value of life insurance policies 3,920 3,582 Other 454 475 56,458 51,085 Other assets: Regulatory assets 211,776 207,202 Deferred charges and other 21,697 21,268 233,473 228,470 $ 1,717,839 $ 1,708,635 CONSOLIDATED BALANCE SHEETS (CONTINUED) June 30, 1996 December 31, CAPITALIZATION AND LIABILITIES (Unaudited) 1995 (in thousands) Capitalization: Common stock - par value $2.50 per share - authorized 24,000,000 shares; 13,370,788 shares outstanding $ 33,427 $ 33,427 Paid-in surplus 279,042 279,042 Retained earnings 211,422 212,522 Total common equity 523,891 524,991 Cumulative preferred stock - par value $50 per share - authorized 466,406 shares; 366,354 shares outstanding 18,320 18,320 Long-term debt (excluding current portion) 457,422 465,463 999,633 1,008,774 Current liabilities: Notes payable to associated companies 4,575 8,888 Other short-term borrowings 125,000 101,000 Capital lease obligations 13,883 15,717 Maturities and sinking funds 23,140 15,140 Accounts payable 48,332 64,564 Accrued interest 9,014 8,038 Accrued taxes 45,137 50,369 Accumulated refueling outage provision 12,610 7,690 Adjustment clause balances 2,809 3,148 Environmental liabilities 5,421 5,521 Other 19,726 17,300 309,647 297,375 Long-term liabilities: Pension and other benefit obligations 46,229 41,866 Capital lease obligations 26,649 21,218 Environmental liabilities 40,668 40,905 Other 6,881 8,719 120,427 112,708 Deferred credits: Accumulated deferred income taxes 252,339 252,663 Accumulated deferred investment tax credits 35,793 37,115 288,132 289,778 Commitments and contingencies (Note 6) $ 1,717,839 $ 1,708,635 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the For the For the Three Months Ended Six Months Ended Twelve Months Ended June 30 June 30 June 30 1996 1995 1996 1995 1996 1995 (in thousands) Operating revenues: Electric $ 137,032 $ 133,048 $ 262,400 $ 249,626 $ 573,246 $ 539,964 Gas 22,445 21,852 91,686 75,027 153,951 125,762 Other 4,763 2,771 8,922 5,858 15,126 10,118 164,240 157,671 363,008 330,511 742,323 675,844 Operating expenses: Fuel for production 22,728 20,304 43,021 39,746 99,530 87,050 Purchased power 22,000 17,130 36,469 33,444 69,899 71,412 Gas purchased for resale 12,042 13,454 59,411 51,587 99,021 82,929 Other operating expenses 36,555 32,644 74,912 67,056 153,106 137,385 Maintenance 14,333 10,611 24,325 22,290 45,621 47,637 Depreciation and amortization 22,024 20,728 44,049 41,317 82,116 78,313 Taxes other than income taxes 11,549 12,356 23,609 24,731 43,892 44,215 141,231 127,227 305,796 280,171 593,185 548,941 Operating income 23,009 30,444 57,212 50,340 149,138 126,903 Interest expense and other: Interest expense 10,988 11,731 21,880 22,190 44,151 43,001 Allowance for funds used during construction -691 -785 -1,380 -1,900 -2,904 -3,934 Miscellaneous, net -176 588 -1,139 595 -880 -406 10,121 11,534 19,361 20,885 40,367 38,661 Income before income taxes 12,888 18,910 37,851 29,455 108,771 88,242 Income taxes: Current 4,994 4,959 18,355 2,975 48,847 27,143 Deferred 1,325 3,556 -538 10,597 -821 9,527 Amortization of investment tax credits -661 -672 -1,323 -1,345 -2,663 -2,668 5,658 7,843 16,494 12,227 45,363 34,002 Net income 7,230 11,067 21,357 17,228 63,408 54,240 Preferred dividend requirements 229 229 457 457 914 914 Net income available for common stock $ 7,001 $ 10,838 $ 20,900 $ 16,771 $ 62,494 $ 53,326 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Three For the Six For the Twelve Months Ended Months Ended Months Ended June 30 June 30 June 30 1996 1995 1996 1995 1996 1995 (in thousands) Cash flows from operating activities: Net income $ 7,230 $ 11,067 $ 21,357 $ 17,228 $ 63,408 $ 54,240 Adjustments to reconcile net income to net cash flows from operating activities - Depreciation and amortization 22,024 20,728 44,049 41,317 82,116 78,313 Amortization of principal under capital lease obligations 4,626 3,311 9,250 5,867 19,096 13,608 Deferred taxes and investment tax credits 664 2,884 -1,861 9,252 -3,484 6,859 Refueling outage provision 2,373 -4,432 4,920 -12,960 10,374 -6,475 Amortization of other assets 2,194 1,587 5,104 2,643 9,853 3,776 Other 65 -60 61 -323 586 -618 Other changes in assets and liabilities - Accounts receivable 8,434 4,419 975 4,545 -13,287 2,226 Production fuel, materials and supplies 26 -2,879 928 -2,931 5,517 -5,409 Accounts payable -3,068 -14,178 -13,365 -18,959 1,200 10,071 Accrued taxes -30,028 -12,237 -12,958 -6,020 -1,153 573 Provision for rate refunds -229 2,207 -63 10,207 -10,164 10,207 Adjustment clause balances -3,726 -2,325 -339 1,910 2,332 -2,599 Gas in storage 1,501 1,948 9,245 9,324 2,350 2,285 Other 2,865 -1,493 4,372 4,922 -1,703 7,810 Net cash flows from operating activities 14,951 10,547 71,675 66,022 167,041 174,867 Cash flows from financing activities: Dividends declared on common stock -12,000 -10,000 -22,000 -23,000 -42,000 -53,000 Dividends declared on preferred stock -229 -229 -457 -457 -914 -914 Proceeds from issuance of long-term debt 0 0 0 50,000 50,000 50,000 Reductions in long-term debt -140 -140 -140 -50,140 -50,140 -50,140 Net change in short-term borrowings 34,334 49,237 19,687 37,286 36,794 75,515 Principal payments under capital lease obligations -4,624 -2,556 -9,536 -6,218 -17,781 -14,375 Sale of utility accounts receivable 7,000 -8,000 7,000 2,000 9,000 3,000 Other -86 0 -172 0 -1,936 0 Net cash flows from financing activities 24,255 28,312 -5,618 9,471 -16,977 10,086 Cash flows from investing activities: Construction and acquisition expenditures - Utility -34,009 -30,351 -57,383 -57,995 -125,492 -155,901 Other -146 -1,405 -342 -1,977 -1,705 -3,840 Deferred energy efficiency expenditures -5,090 -4,441 -8,757 -7,978 -18,808 -16,964 Nuclear decommissioning trust funds -1,502 -1,383 -3,004 -2,766 -6,338 -5,532 Other 1,225 -2,288 813 -5,431 916 -1,926 Net cash flows from investing activities -39,522 -39,868 -68,673 -76,147 -151,427 -184,163 Net increase (decrease) in cash and temporary cash investments -316 -1,009 -2,616 -654 -1,363 790 Cash and temporary cash investments at beginning of period 434 2,490 2,734 2,135 1,481 691 Cash and temporary cash investments at end of period $ 118 $ 1,481 $ 118 $ 1,481 $ 118 $ 1,481 Supplemental cash flow information: Cash paid during the period for - Interest $ 11,046 $ 13,819 $ 19,576 $ 22,073 $ 42,072 $ 41,132 Income taxes $ 24,430 $ 8,533 $ 31,568 $ 11,383 $ 49,268 $ 29,256 Noncash investing and financing activities - Capital lease obligations incurred $ 10,243 $ 1,542 $ 12,846 $ 2,658 $ 13,106 $ 16,531 The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) June 30, 1996 (1) GENERAL: The interim Consolidated Financial Statements have been prepared by IES Utilities Inc. (Utilities) and its consolidated subsidiaries (collectively the Company), without audit, pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Utilities is a wholly-owned subsidiary of IES Industries Inc. (Industries). Utilities' wholly-owned subsidiary is IES Ventures Inc. (Ventures), which is a holding company for unregulated investments. Utilities is engaged principally in the generation, transmission, distribution and sale of electric energy and the purchase, distribution, transportation and sale of natural gas. The Company's principal markets are located in the state of Iowa. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. In the opinion of the Company, the Consolidated Financial Statements include all adjustments, which are normal and recurring in nature, necessary for the fair presentation of the results of operations and financial position. Certain prior period amounts have been reclassified on a basis consistent with the 1996 presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect: 1) the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and 2) the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. It is suggested that these Consolidated Financial Statements be read in conjunction with the Consolidated Financial Statements and the notes thereto included in the Company's Form 10-K for the year ended December 31, 1995. The accounting and financial policies relative to the following items have been described in those notes and have been omitted herein because they have not changed materially through the date of this report: Summary of significant accounting policies Leases Utility accounts receivable (other than discussed in Note 4) Income taxes Benefit plans Preferred and preference stock Debt (other than discussed in Note 5) Estimated fair value of financial instruments Commitments and contingencies (other than discussed in Note 6) Jointly-owned electric utility plant Segments of business (2) POTENTIAL BUSINESS COMBINATIONS: (a) Proposed Merger of Industries - Industries, WPL Holdings, Inc. (WPLH) and Interstate Power Company (IPC) have entered into an Agreement and Plan of Merger (Merger Agreement), dated November 10, 1995, as amended, providing for: a) IPC becoming a wholly-owned subsidiary of WPLH, and b) the merger of Industries with and into WPLH, which merger will result in the combination of Industries and WPLH as a single holding company (collectively, the Proposed Merger). The new holding company will be named Interstate Energy Corporation (Interstate Energy), and Industries will cease to exist. Each holder of Industries' common stock will receive 1.01 shares of Interstate Energy common stock for each share of Industries' common stock. The Proposed Merger, which will be accounted for as a pooling of interests, has been approved by the respective Boards of Directors. It is still subject to approval by the shareholders of each company as well as several federal and state regulatory agencies. The companies mailed the joint proxy statement to their shareholders the week of July 23, 1996. The companies expect to receive the shareholder approvals in the third quarter of 1996 and regulatory approvals by the summer of 1997. The corporate headquarters of Interstate Energy will be in Madison, Wisconsin. The business of Interstate Energy will consist of utility operations and various non-utility enterprises. The utility subsidiaries currently serve approximately 870,000 electric customers and 360,000 natural gas customers in Iowa, Wisconsin, Illinois and Minnesota. (b) Unsolicited Acquisition Proposal - On August 5, 1996, MidAmerican Energy Company (MAEC), an electric and natural gas utility company based in Des Moines, Iowa, announced that it had made an unsolicited offer to acquire Industries in a cash and stock transaction. Under the terms of the offer, Industries would merge with and into MAEC in a transaction in which Industries' shareholders would receive up to 40% in cash and the remainder in shares of MAEC common stock. Industries' shareholders receiving cash would receive $39 for each Industries' share and shareholders receiving shares would receive 2.346 shares of MAEC stock for each Industries' share. On August 12, 1996, the closing price for MAEC stock on the NYSE was $15.75 per share. MAEC has stated that, if Industries and MAEC do not promptly reach agreement with respect to a business combination between the two companies, MAEC will solicit proxies against the Proposed Merger for use at the upcoming Industries' shareholder meeting. Industries cannot currently determine what, if any, impact the unsolicited offer of MAEC may have on the Proposed Merger. The proposal will be given full consideration by Industries' Board of Directors. (3) RATE MATTERS: (a) 1995 Gas Rate Case - On August 4, 1995, Utilities applied to the Iowa Utilities Board (IUB) for an annual increase in gas rates of $8.8 million, or 6.2%. An interim increase of $8.6 million was requested and the IUB, subsequently, approved an interim increase of $7.1 million annually, effective October 11, 1995, subject to refund. On April 4, 1996, the IUB issued an order approving a settlement agreement entered into by Utilities, the Office of Consumer Advocate and all three industrial intervenor groups, which allows Utilities a $6.3 million annual increase. Utilities subsequently filed final compliance tariffs which became effective on May 30, 1996. Primarily because of changes in rate design, there is a refund obligation of approximately $43,000 which will be made in the third quarter of 1996. (b) Electric Price Announcements - Utilities and its Iowa-based proposed merger partner, IPC, announced in April their intentions to hold retail electric prices to their current levels until at least January 1, 2000. The companies made the proposal as part of their testimony in the merger-related application filed with the IUB, which was later withdrawn and will be resubmitted at a future date. (The companies intend to include the same proposal in the resubmittal of the filing.) The companies did specify that the proposal excludes price changes due to government-mandated programs, such as energy efficiency cost recovery, or unforeseen dramatic changes in operations. Utilities, Wisconsin Power and Light Company (the utility subsidiary of WPLH) and IPC also agreed to freeze their wholesale electric prices for four years from the effective date of the merger as part of their merger filing with the Federal Energy Regulatory Commission (FERC). The Company does not expect the merger-related electric price proposals to have a material adverse effect on its financial position or results of operations. (c) Energy Efficiency Cost Recovery - Current IUB rules mandate Utilities to spend 2% of electric and 1.5% of gas gross retail operating revenues for energy efficiency programs. Under provisions of the IUB rules, Utilities is currently recovering the energy efficiency costs incurred through 1993 for such programs, including its direct expenditures, carrying costs, a return on its expenditures and a reward. Recovery of the costs will be over a four-year period and began on June 1, 1995. In October 1996, under provisions of the IUB rules, the Company will file for recovery of the costs relating to its 1994 and 1995 programs ($31.9 million as of June 30, 1996). Iowa statutory changes enacted recently have eliminated both: 1) the 2% and 1.5% spending requirements described above in favor of IUB- determined energy savings targets and 2) the delay in recovery of energy efficiency costs by allowing recovery which is concurrent with spending. This will eventually eliminate the regulatory asset which exists under the current rate making mechanism. (4) UTILITY ACCOUNTS RECEIVABLE: Utilities has entered into an agreement, which expires in 1999, with a financial institution to sell, with limited recourse, an undivided fractional interest of up to $65 million in its pool of utility accounts receivable. At June 30, 1996, $65 million was sold under the agreement. (5) DEBT: At June 30, 1996, the Company had bank lines of credit aggregating $121.1 million, of which $108 million was being used to support commercial paper (weighted average interest rate of 5.40%) and $11.1 million to support certain pollution control obligations. Commitment fees are paid to maintain these lines and there are no conditions which restrict the unused lines of credit. In addition to the above, Utilities has an uncommitted credit facility with a financial institution whereby it can borrow up to $40 million. Rates are set at the time of borrowing and no fees are paid to maintain this facility. At June 30, 1996, there was $17 million outstanding under this facility (weighted average interest rate of 5.57%). (6) CONTINGENCIES: (a) Environmental Liabilities - The Company has recorded environmental liabilities of approximately $46 million in its Consolidated Balance Sheets at June 30, 1996. The significant items are discussed below. Former Manufactured Gas Plant (FMGP) Sites Utilities has been named as a Potentially Responsible Party (PRP) by various federal and state environmental agencies for 28 FMGP sites, but believes it is not responsible for two of these sites based on extensive reviews of the ownership records and historical information available for the two sites. Utilities has notified the appropriate regulatory agency that it believes it does not have any responsibility as relates to these two sites, but no response has been received from the agency on this issue. Utilities is also aware of six other sites that it may have owned or operated in the past and for which, as a result, it may be designated as a PRP in the future in the event that environmental concerns arise at these sites. Utilities is working pursuant to the requirements of the various agencies to investigate, mitigate, prevent and remediate, where necessary, damage to property, including damage to natural resources, at and around the sites in order to protect public health and the environment. Utilities believes it has completed the remediation of seven sites although it is in the process of obtaining final approval from the applicable environmental agencies on this issue for each site. Utilities is in various stages of the investigation and/or remediation processes for the remaining 19 sites and estimates the range of additional costs to be incurred for investigation and/or remediation of the sites to be approximately $24 million to $57 million. Utilities has recorded environmental liabilities related to the FMGP sites of approximately $35 million (including $4.6 million as current liabilities) at June 30, 1996. These amounts are based upon Utilities' best current estimate of the amount to be incurred for investigation and remediation costs for those sites where the investigation process has been or is substantially completed, and the minimum of the estimated cost range for those sites where the investigation is in its earlier stages. It is possible that future cost estimates will be greater than the current estimates as the investigation process proceeds and as additional facts become known; in addition, Utilities may be required to monitor these sites for a number of years upon completion of remediation, as is the case with several of the sites for which remediation has been completed. In April 1996, Utilities filed a lawsuit against certain of its insurance carriers seeking reimbursement for investigation, mitigation, prevention, remediation and monitoring costs associated with the FMGP sites. Settlement discussions are proceeding between Utilities and its insurance carriers regarding the recovery of these FMGP-related costs. The amount of aggregate potential recovery, or the regulatory treatment of any such recoveries, cannot be reasonably determined at this time and, accordingly, no estimated amounts have been recorded at June 30, 1996. Regulatory assets of approximately $35 million, which reflect the future recovery that is being provided through Utilities' rates, have been recorded in the Consolidated Balance Sheets. Considering the current rate treatment allowed by the IUB, management believes that the clean-up costs incurred by Utilities for these FMGP sites will not have a material adverse effect on its financial position or results of operations. National Energy Policy Act of 1992 The National Energy Policy Act of 1992 requires owners of nuclear power plants to pay a special assessment into a "Uranium Enrichment Decontamination and Decommissioning Fund." The assessment is based upon prior nuclear fuel purchases and, for the Duane Arnold Energy Center (DAEC), averages $1.4 million annually through 2007, of which Utilities' 70% share is $1.0 million. Utilities is recovering the costs associated with this assessment through its electric fuel adjustment clauses over the period the costs are assessed. Utilities' 70% share of the future assessment, $10.9 million payable through 2007, has been recorded as a liability in the Consolidated Balance Sheets, including $0.8 million included in "Current liabilities - Environmental liabilities," with a related regulatory asset for the unrecovered amount. (b) Air Quality Issues - The Clean Air Act Amendments of 1990 (Act) requires emission reductions of sulfur dioxide (SO2) and nitrogen oxides (NOx) to achieve reductions of atmospheric chemicals believed to cause acid rain. The provisions of the Act are being implemented in two phases; the Phase I requirements have been met and the Phase II requirements affect eleven other fossil units beginning in the year 2000. Utilities expects to meet the requirements of Phase II by switching to lower sulfur fuels, capital expenditures primarily related to fuel burning equipment and boiler modifications, and the possible purchase of SO2 allowances. Utilities estimates capital expenditures at approximately $20 million, including $4 million in 1996, in order to meet the acid rain requirements of the Act. The acid rain program under the Act also governs SO2 allowances. An allowance is defined as an authorization for an owner to emit one ton of SO2 into the atmosphere. Currently, Utilities receives a sufficient number of allowances annually to offset its emissions of SO2 from its Phase I units. It is anticipated that in the year 2000, Utilities may have an insufficient number of allowances annually to offset its estimated emissions and may have to purchase additional allowances, or make modifications to the plants or limit operations to reduce emissions. Utilities is reviewing its options to ensure that it will have sufficient allowances to offset its emissions in the future. Utilities believes that the potential cost of ensuring sufficient allowances will not have a material adverse effect on its financial position or results of operations. The Act and other federal laws also require the United States Environmental Protection Agency (EPA) to study and regulate, if necessary, additional issues that potentially affect the electric utility industry, including emissions relating to NOx, ozone transport, mercury and particulate control; toxic release inventories and modifications to the PCB rules. Currently, the impacts of these potential regulations are too speculative to quantify. In 1995, the EPA published the Sulfur Dioxide Network Design Review for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst- case modeling method suggests that the Cedar Rapids area could be classified as "nonattainment" for the National Ambient Air Quality Standard (NAAQS) established for SO2. The worst-case modeling study suggested that two of Utilities' generating facilities contribute to the modeled exceedences and recommended that additional monitors be located near Utilities' sources to assess actual ambient air quality. In the event that Utilities' facilities contribute excessive emissions, Utilities would be required to reduce emissions, which would primarily entail capital expenditures for modifications to the facilities. Utilities is planning to convert one of its fossil generating facilities to a natural gas-fired cogeneration facility. Such facility was contributing to the modeled exceedences thus the conversion will have the added inherent benefit of reducing SO2 emissions. Utilities is proposing to resolve the remainder of EPA's nonattainment concerns by installing a new stack at the other generating facility contributing to the modeled exceedences at a potential capital cost of up to $4.5 million over the next four years. (c) FERC Order No. 636 - Pursuant to FERC Order No. 636 (Order 636), which transitions the natural gas supply business to a less regulated environment, Utilities has enhanced access to competitively priced gas supply and more flexible transportation services. However, under Order 636, Utilities is required to pay certain transition costs incurred and billed by its pipeline suppliers. Utilities began paying the transition costs in 1993 and at June 30, 1996, has recorded a liability of $4.2 million for those transition costs that have been incurred, but not yet billed, by the pipelines to date, including $1.9 million expected to be billed through June 1997. Utilities is currently recovering the transition costs from its customers through its Purchased Gas Adjustment Clauses as such costs are billed by the pipelines. Transition costs, in addition to the recorded liability, that may ultimately be charged to Utilities could approximate $4.6 million. The ultimate level of costs to be billed to Utilities depends on the pipelines' future filings with the FERC and other future events, including the market price of natural gas. However, Utilities believes any transition costs that the FERC would allow the pipelines to collect from Utilities would be recovered from its customers, based upon regulatory treatment of these costs currently and similar past costs by the IUB. Accordingly, regulatory assets, in amounts corresponding to the recorded liabilities, have been recorded to reflect the anticipated recovery. (d) Nuclear Insurance Programs - Public liability for nuclear accidents is governed by the Price Anderson Act of 1988 which sets a statutory limit of $8.9 billion for liability to the public for a single nuclear power plant incident and requires nuclear power plant operators to provide financial protection for this amount. As required, Utilities provides this financial protection for a nuclear incident at the DAEC through a combination of liability insurance ($200 million) and industry-wide retrospective payment plans ($8.7 billion). Under the industry-wide plan, each operating licensed nuclear reactor in the United States is subject to an assessment in the event of a nuclear incident at any nuclear plant in the United States. Based on its ownership of the DAEC, Utilities could be assessed a maximum of $79.3 million per nuclear incident, with a maximum of $10 million per incident per year (of which Utilities' 70% ownership portion would be approximately $55 million and $7 million, respectively) if losses relating to the incident exceeded $200 million. These limits are subject to adjustments for changes in the number of participants and inflation in future years. Utilities is a member of Nuclear Mutual Limited (NML) and Nuclear Electric Insurance Limited (NEIL). These companies provide $1.9 billion of insurance coverage on certain property losses at DAEC for property damage, decontamination and premature decommissioning. The proceeds from such insurance, however, must first be used for reactor stabilization and site decontamination before they can be used for plant repair and premature decommissioning. NEIL also provides separate coverage for the cost of replacement power during certain outages. Owners of nuclear generating stations insured through NML and NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. NML and NEIL's accumulated reserve funds are currently sufficient to more than cover its exposure in the event of a single incident under the primary and excess property damage or replacement power coverages. However, Utilities could be assessed annually a maximum of $3.0 million under NML, $9.8 million for NEIL property and $0.7 million for NEIL replacement power if losses exceed the accumulated reserve funds. Utilities is not aware of any losses that it believes are likely to result in an assessment. In the unlikely event of a catastrophic loss at DAEC, the amount of insurance available may not be adequate to cover property damage, decontamination and premature decommissioning. Uninsured losses, to the extent not recovered through rates, would be borne by Utilities and could have a material adverse effect on Utilities' financial position and results of operations. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION The Consolidated Financial Statements include the accounts of IES Utilities Inc. (Utilities) and its consolidated subsidiaries (collectively the Company). Utilities is a wholly-owned subsidiary of IES Industries Inc. (Industries). Utilities' wholly-owned subsidiary is IES Ventures Inc. (Ventures), which is a holding company for unregulated investments. POTENTIAL BUSINESS COMBINATIONS (a) Proposed Merger of Industries - Industries, WPL Holdings, Inc. (WPLH) and Interstate Power Company (IPC) have entered into an Agreement and Plan of Merger (Merger Agreement), dated November 10, 1995, as amended, providing for: a) IPC becoming a wholly-owned subsidiary of WPLH, and b) the merger of Industries with and into WPLH, which merger will result in the combination of Industries and WPLH as a single holding company (collectively, the Proposed Merger). The new holding company will be named Interstate Energy Corporation (Interstate Energy), and Industries will cease to exist. Each holder of Industries' common stock will receive 1.01 shares of Interstate Energy common stock for each share of Industries' common stock. The Proposed Merger, which will be accounted for as a pooling of interests, has been approved by the respective Boards of Directors. It is still subject to approval by the shareholders of each company as well as several federal and state regulatory agencies. The companies mailed the joint proxy statement to their shareholders the week of July 23, 1996. The companies expect to receive the shareholder approvals in the third quarter of 1996 and regulatory approvals by the summer of 1997. The corporate headquarters of Interstate Energy will be in Madison, Wisconsin. The business of Interstate Energy will consist of utility operations and various non-utility enterprises. The utility subsidiaries currently serve approximately 870,000 electric customers and 360,000 natural gas customers in Iowa, Wisconsin, Illinois and Minnesota. (b) Unsolicited Acquisition Proposal - On August 5, 1996, MidAmerican Energy Company (MAEC), an electric and natural gas utility company based in Des Moines, Iowa, announced that it had made an unsolicited offer to acquire Industries in a cash and stock transaction. Under the terms of the offer, Industries would merge with and into MAEC in a transaction in which Industries' shareholders would receive up to 40% in cash and the remainder in shares of MAEC common stock. Industries' shareholders receiving cash would receive $39 for each Industries' share and shareholders receiving shares would receive 2.346 shares of MAEC stock for each Industries' share. On August 12, 1996, the closing price for MAEC stock on the NYSE was $15.75 per share. MAEC has stated that, if Industries and MAEC do not promptly reach agreement with respect to a business combination between the two companies, MAEC will solicit proxies against the Proposed Merger for use at the upcoming Industries' shareholder meeting. Industries cannot currently determine what, if any, impact the unsolicited offer of MAEC may have on the Proposed Merger. The proposal will be given full consideration by Industries' Board of Directors. RESULTS OF OPERATIONS The following discussion analyzes significant changes in the components of net income available for common stock and financial condition from the prior periods for the Company: The Company's net income available for common stock increased or (decreased) ($3.8) million, $4.1 million and $9.2 million during the three, six and twelve month periods, respectively. The three month period decrease was primarily due to increased operating expenses. The increase in earnings for the six month period was primarily due to increased electric and gas sales, the impact of a natural gas pricing increase implemented in the fourth quarter of 1995 and a reserve for electric rate refund recorded in the first quarter of 1995 which included $3.5 million relating to revenues collected in 1994. The twelve month increase was primarily due to increased electric and gas sales, the natural gas pricing increase and lower purchased power capacity costs, partially offset by lower electric prices. Increased operating expenses also partially offset the six and twelve month increases in earnings. The Company's operating income increased or (decreased) ($7.4) million, $6.9 million and $22.2 million during the three, six and twelve month periods, respectively. Reasons for the changes in the results of operations are explained in the following discussion. Electric Revenues Electric revenues and Kwh sales (before off-system sales) for Utilities increased or (decreased) as compared with the prior year as follows: Changes vs. Prior Period Three Six Twelve Months Months Months ($ in millions) Total electric revenues $ 4.0 $ 12.8 $ 33.3 Off-system sales revenues 3.5 4.1 6.2 Electric revenues (excluding off-system sales) $ 0.5 $ 8.7 $ 27.1 Electric sales (excluding off-system sales): Residential and Rural 1.4% 3.8% 9.7% General Service (5.3) (0.2) 4.7 Large General Service (0.1) 2.5 4.1 Total (0.4) 2.6 5.1 Weather had a significant impact on sales during the six and twelve month periods. The largest effect of weather for the periods was on sales to residential and rural customers. Under historically normal weather conditions, total sales (excluding off-system sales) during the three, six and twelve month periods would have increased or (decreased) (0.5%), 1.5% and 1.7%, respectively. The sales comparisons for all three periods were impacted by a true-up adjustment to Utilities' unbilled sales recorded in the second quarter of 1995. The sales increases to the large general service customers (which are not significantly impacted by weather) during the six and twelve month periods reflect the underlying strength of the economy as industrial expansions in Utilities' service territory continued during these periods. Utilities' electric tariffs include energy adjustment clauses (EAC) that are designed to currently recover the costs of fuel and the energy portion of purchased power billings to customers. The increase in the electric revenues during all periods was primarily due to increased sales (excluding the impact of the 1995 true- up adjustment to unbilled sales), the recovery of expenditures for energy efficiency programs pursuant to an Iowa Utilities Board (IUB) order and higher fuel costs collected through the EAC. The impact of these items was partially offset by the 1995 unbilled revenue adjustment. The twelve month period increase was also partially offset by lower electric prices resulting from the IUB price reduction order received in 1995. Refer to note 3(b) of the Notes to Consolidated Financial Statements for a discussion of merger-related retail and wholesale electric price proposals that Utilities has announced. Gas Revenues Gas revenues increased $0.6 million, $16.7 million and $28.2 million for the three, six and twelve month periods, respectively. Utilities' gas sales and transported volumes increased or (decreased) for the periods ended June 30, 1996, as compared with the prior periods, as follows: Three Months Six Months Twelve Months Residential 1.8% 14.0% 16.5% Commercial (0.3) 11.5 13.4 Industrial 18.4 4.9 (9.3) Sales to consumers 3.0 12.4 12.2 Transported volumes (5.2) (1.8) 5.4 Total (0.1) 8.9 10.4 Under historically normal weather conditions, Utilities' gas sales and transported volumes would have increased or (decreased) (0.8%), 2.9% and 3.5% during the three, six and twelve month periods, respectively. Utilities' gas tariffs include purchased gas adjustment clauses (PGA) that are designed to currently recover the cost of gas sold. On August 4, 1995, Utilities applied to the IUB for an annual increase in gas rates of $8.8 million, or 6.2%. An interim increase of $8.6 million was requested and the IUB, subsequently, approved an interim increase of $7.1 million annually, effective October 11, 1995, subject to refund. On April 4, 1996, the IUB issued an order approving a settlement agreement entered into by Utilities, the Office of Consumer Advocate and all three industrial intervenor groups, which allows Utilities a $6.3 million annual increase. Utilities subsequently filed final compliance tariffs which became effective on May 30, 1996. Primarily because of changes in rate design, there is a refund obligation of approximately $43,000 which will be made in the third quarter of 1996. Utilities' gas revenues increased during both the six and twelve month periods primarily because of higher gas costs recovered through the PGA, the gas pricing increase, recovery of expenditures for the energy efficiency programs and increased sales to ultimate consumers (largely on account of the weather). Other Revenues Other revenues increased $2.0 million, $3.1 million and $5.0 million during the three, six and twelve month periods, respectively, primarily due to new industrial steam customers. Operating Expenses Fuel for production increased $2.4 million, $3.3 million and $12.5 million during the three, six and twelve month periods, respectively. The three month increase was primarily due to higher fuel costs recovered through the EAC which are included in fuel for production expense. The increases during the six and twelve month periods were substantially related to increased Kwh generation, primarily the result of a refueling outage during early 1995 at Utilities' nuclear generating station, the Duane Arnold Energy Center (DAEC). Purchased power increased or (decreased) $4.9 million, $3.0 million and ($1.5) million during the three, six and twelve month periods, respectively. The three and six month increases were primarily due to increased energy purchases, as a result of the increased electric sales (excluding the 1995 unbilled adjustment), partially offset by lower capacity costs. The twelve month decrease was due to a ($4.2) million decrease in capacity costs, partially offset by higher energy purchases due to the increased sales. Gas purchased for resale increased $7.8 million and $16.1 million during the six and twelve month periods, respectively. The increases were primarily due to higher natural gas costs and increased gas sales to consumers. Other operating expenses increased $3.9 million, $7.9 million and $15.7 million during the three, six and twelve month periods, respectively. Increased labor and benefits costs, the amortization of previously deferred energy efficiency expenditures (which are currently being recovered through rates) and costs incurred in the Company's efforts to prepare for an increasingly competitive utility industry contributed to the increases in all periods. The costs to prepare for a competitive utility industry included costs associated with items such as: 1) a project to review and redesign Utilities' major business processes, 2) the Proposed Merger and 3) an early retirement program. These increases were partially offset by lower former manufactured gas plant (FMGP) clean-up costs. Maintenance expenses increased or (decreased) $3.7 million, $2.0 million and ($2.0) million during the three, six and twelve month periods, respectively. The three and six month increases are primarily due to increased maintenance activities at Utilities' generating stations. The twelve month decrease was primarily caused by less required maintenance at the DAEC and lower tree trimming costs. Depreciation and amortization increased during all periods because of increases in utility plant in service. These increases were partially offset by lower depreciation rates implemented at Utilities as a result of the IUB electric price reduction order. Depreciation and amortization expenses for all periods included a provision for decommissioning the DAEC, which is collected through rates. The annual recovery level was increased to $6.0 million in 1995 from $5.5 million, as a result of Utilities' most recent electric rate case. During the first quarter of 1996, the Financial Accounting Standards Board (FASB) issued an Exposure Draft on Accounting for Liabilities Related to Closure and Removal of Long-Lived Assets which deals with, among other issues, the accounting for decommissioning costs. If current electric utility industry accounting practices for such decommissioning are changed: 1) annual provisions for decommissioning could increase and 2) the estimated cost for decommissioning could be recorded as a liability, rather than as accumulated depreciation, with recognition of an increase in the recorded amount of the related DAEC plant. If such changes are required, Utilities believes that there would not be an adverse effect on its financial position or results of operations based on current rate making practices. Income taxes increased or (decreased) ($2.2) million, $4.3 million and $11.4 million for the three, six and twelve month periods, respectively. The variances for all periods were due to changes in pre- tax income and a higher effective tax rate. The higher effective tax rate for each period is due to: 1) the effect of property related temporary differences for which deferred taxes had not been provided, pursuant to rate making principles, that are now becoming payable and are being recovered from ratepayers, and 2) the effect of prior period audit adjustments. LIQUIDITY AND CAPITAL RESOURCES The Company's capital requirements are primarily attributable to its construction programs and debt maturities. The Company's pre-tax ratio of times interest earned was 3.46 and 3.05 for the twelve months ended June 30, 1996 and June 30, 1995, respectively. Cash flows from operating activities for the twelve months ended June 30, 1996 and June 30, 1995 were $167 million and $175 million, respectively. The decrease was primarily due to the electric rate case refund paid to customers in the fourth quarter of 1995. Cash paid for income taxes increased significantly during all three periods primarily because of the timing of estimated tax payments computed under the annualized income approach. The Company anticipates that future capital requirements will be met by cash generated from operations and external financing. The level of cash generated from operations is partially dependent upon economic conditions, legislative activities, environmental matters and timely rate relief for Utilities. See Notes 3 and 6 of the Notes to Consolidated Financial Statements. Access to the long-term and short-term capital and credit markets is necessary for obtaining funds externally. The Company's debt ratings are as follows: Moody's Standard & Poor's Long-term debt A2 A Short-term debt P1 A1 Both Moody's and Standard & Poor's have indicated that Utilities' credit ratings are under review as the result of the unsolicited acquisition proposal Industries received from MidAmerican Energy Co. It is not certain if, and how, such proposal or the Proposed Merger may affect the Company's debt ratings. The Company's liquidity and capital resources will be affected by environmental and legislative issues, including the ultimate disposition of remediation issues surrounding the Company's environmental liabilities and the Clean Air Act as amended, as discussed in Note 6 of the Notes to Consolidated Financial Statements, and the National Energy Policy Act of 1992 as discussed in the Other Matters section. Consistent with rate making principles of the IUB, management believes that the costs incurred for the above matters will not have a material adverse effect on the financial position or results of operations of the Company. Current IUB rules require Utilities to spend 2% of electric and 1.5% of gas gross retail operating revenues annually for energy efficiency programs. Energy efficiency costs in excess of the amount in the most recent electric and gas rate cases are being recorded as regulatory assets by Utilities. At June 30, 1996, Utilities had approximately $55 million of such costs recorded as regulatory assets. On June 1, 1995, Utilities began recovery of those costs incurred through 1993. See Note 3(c) of the Notes to Consolidated Financial Statements for a discussion of the timing of the filings for the recovery of these costs under IUB rules and Iowa statutory changes recently enacted relating to these programs. Under provisions of the Merger Agreement, there are restrictions on the amount of long-term debt the Company can issue pending the merger. The Company does not expect the restrictions to have a material effect on its ability to meet its future capital requirements. CONSTRUCTION AND ACQUISITION PROGRAM The Company's construction and acquisition program anticipates expenditures of approximately $164 million for 1996, of which approximately 55% represents expenditures for electric, gas and steam transmission and distribution facilities, 19% represents fossil-fueled generation expenditures, 13% represents information technology expenditures and 5% represents nuclear generation expenditures. The remaining 8% represents miscellaneous electric and general expenditures. In addition to the $164 million, Utilities anticipates expenditures of $13 million in connection with mandated energy efficiency programs. The Company had construction and acquisition expenditures of approximately $58 million for the six months ended June 30, 1996. The Company's levels of construction and acquisition expenditures are projected to be $185 million in 1997, $176 million in 1998, $161 million in 1999 and $137 million in 2000. It is estimated that approximately 80% of these construction and acquisition expenditures will be provided by cash from operating activities (after payment of dividends) for the five-year period 1996-2000. Capital expenditure and investment and financing plans are subject to continual review and change. The capital expenditure and investment programs may be revised significantly as a result of many considerations including changes in economic conditions, variations in actual sales and load growth compared to forecasts, requirements of environmental, nuclear and other regulatory authorities, acquisition and business combination opportunities, the availability of alternate energy and purchased power sources, the ability to obtain adequate and timely rate relief, escalations in construction costs and conservation and energy efficiency programs. Under provisions of the Merger Agreement, there are restrictions on the amount of construction and acquisition expenditures the Company can make pending the merger. The Company does not expect the restrictions to have a material effect on its ability to implement its anticipated construction and acquisition program. LONG-TERM FINANCING Other than Utilities' periodic sinking fund requirements, which Utilities intends to meet by pledging additional property, approximately $140 million of long-term debt will mature prior to December 31, 2000. The Company intends to refinance the majority of the debt maturities with long-term securities. Utilities has entered into an Indenture of Mortgage and Deed of Trust dated September 1, 1993 (New Mortgage). The New Mortgage provides for, among other things, the issuance of Collateral Trust Bonds upon the basis of First Mortgage Bonds being issued by Utilities. The lien of the New Mortgage is subordinate to the lien of Utilities' first mortgages until such time as all bonds issued under the first mortgages have been retired and such mortgages satisfied. Accordingly, to the extent that Utilities issues Collateral Trust Bonds on the basis of First Mortgage Bonds, it must comply with the requirements for the issuance of First Mortgage Bonds under Utilities' first mortgages. Under the terms of the New Mortgage, Utilities has covenanted not to issue any additional First Mortgage Bonds under its first mortgages except to provide the basis for issuance of Collateral Trust Bonds. The indentures pursuant to which Utilities issues First Mortgage Bonds constitute direct first mortgage liens upon substantially all tangible public utility property and contain covenants which restrict the amount of additional bonds which may be issued. At June 30, 1996, such restrictions would have allowed Utilities to issue at least $266 million of additional First Mortgage Bonds. In order to provide an instrument for the issuance of unsecured subordinated debt securities, Utilities entered into an Indenture dated December 1, 1995 (Subordinated Indenture). The Subordinated Indenture provides for, among other things, the issuance of unsecured subordinated debt securities. Any debt securities issued under the Subordinated Indenture are subordinate to all senior indebtedness of Utilities, including First Mortgage Bonds and Collateral Trust Bonds. Utilities has received authority from the Federal Energy Regulatory Commission (FERC) and the SEC to issue up to $250 million of long-term debt, and has $250 million of remaining authority under the current FERC docket through April 1998, and $200 million of remaining authority under the current SEC shelf registration. Utilities expects to initially replace $15 million of First Mortgage Bonds that mature in September 1996 with short-term borrowings pending the issuance of long-term debt. The Articles of Incorporation of Utilities authorize and limit the aggregate amount of additional shares of Cumulative Preference Stock and Cumulative Preferred Stock that may be issued. At June 30, 1996, Utilities could have issued an additional 700,000 shares of Cumulative Preference Stock and 100,000 additional shares of Cumulative Preferred Stock. The Company's capitalization ratios at June 30, were as follows: 1996 1995 Long-term debt 46% 48% Preferred stock 2 2 Common equity 52 50 100% 100% The 1995 ratios included $50 million of long-term debt due in less than one year because it was the Company's intention to refinance the debt with long-term securities. Under provisions of the Merger Agreement, there are restrictions on the amount of long-term debt the Company can issue pending the merger. The Company does not expect the restrictions to have a material effect on its ability to meet its future capital requirements. SHORT-TERM FINANCING For interim financing, Utilities is authorized by the FERC to issue, through 1996, up to $200 million of short-term notes. In addition to providing for ongoing working capital needs, this availability of short-term financing provides Utilities flexibility in the issuance of long-term securities. At June 30, 1996, Utilities had outstanding short-term borrowings of $129.6 million, including $4.6 million of notes payable to associated companies. Utilities has entered into an agreement, which expires in 1999, with a financial institution to sell, with limited recourse, an undivided fractional interest of up to $65 million in its pool of utility accounts receivable. At June 30, 1996, $65 million was sold under the agreement. At June 30, 1996, the Company had bank lines of credit aggregating $121.1 million, of which $108 million was being used to support commercial paper (weighted average interest rate of 5.40%) and $11.1 million to support certain pollution control obligations. Commitment fees are paid to maintain these lines and there are no conditions which restrict the unused lines of credit. In addition to the above, Utilities has an uncommitted credit facility with a financial institution whereby it can borrow up to $40 million. Rates are set at the time of borrowing and no fees are paid to maintain this facility. At June 30, 1996, there was $17 million outstanding under this facility (weighted average interest rate of 5.57%). ENVIRONMENTAL MATTERS Utilities has been named as a Potentially Responsible Party (PRP) by various federal and state environmental agencies for 28 FMGP sites, but believes it is not responsible for two of these sites based on extensive reviews of the ownership records and historical information available for the two sites. Utilities has notified the appropriate regulatory agency that it believes it does not have any responsibility as relates to these two sites, but no response has been received from the agency on this issue. Utilities is also aware of six other sites that it may have owned or operated in the past and for which, as a result, it may be designated as a PRP in the future in the event that environmental concerns arise at these sites. Utilities is working pursuant to the requirements of the various agencies to investigate, mitigate, prevent and remediate, where necessary, damage to property, including damage to natural resources, at and around the sites in order to protect public health and the environment. Utilities believes it has completed the remediation of seven sites although it is in the process of obtaining final approval from the applicable environmental agencies on this issue for each site. Utilities is in various stages of the investigation and/or remediation processes for the remaining 19 sites and estimates the range of additional costs to be incurred for investigation and/or remediation of the sites to be approximately $24 million to $57 million. Utilities has recorded environmental liabilities related to the FMGP sites of approximately $35 million (including $4.6 million as current liabilities) at June 30, 1996. These amounts are based upon Utilities' best current estimate of the amount to be incurred for investigation and remediation costs for those sites where the investigation process has been or is substantially completed, and the minimum of the estimated cost range for those sites where the investigation is in its earlier stages. It is possible that future cost estimates will be greater than the current estimates as the investigation process proceeds and as additional facts become known; in addition, Utilities may be required to monitor these sites for a number of years upon completion of remediation, as is the case with several of the sites for which remediation has been completed. In April 1996, Utilities filed a lawsuit against certain of its insurance carriers seeking reimbursement for investigation, mitigation, prevention, remediation and monitoring costs associated with the FMGP sites. Settlement discussions are proceeding between Utilities and its insurance carriers regarding the recovery of these FMGP-related costs. The amount of aggregate potential recovery, or the regulatory treatment of any such recoveries, cannot be reasonably determined at this time and, accordingly, no estimated amounts have been recorded at June 30, 1996. Regulatory assets of approximately $35 million, which reflect the future recovery that is being provided through Utilities' rates, have been recorded in the Consolidated Balance Sheets. Considering the current rate treatment allowed by the IUB, management believes that the clean-up costs incurred by Utilities for these FMGP sites will not have a material adverse effect on its financial position or results of operations. The Clean Air Act Amendments of 1990 (Act) requires emission reductions of sulfur dioxide (SO2) and nitrogen oxides (NOx) to achieve reductions of atmospheric chemicals believed to cause acid rain. The provisions of the Act are being implemented in two phases; the Phase I requirements have been met and the Phase II requirements affect eleven other fossil units beginning in the year 2000. Utilities expects to meet the requirements of Phase II by switching to lower sulfur fuels, capital expenditures primarily related to fuel burning equipment and boiler modifications, and the possible purchase of SO2 allowances. Utilities estimates capital expenditures at approximately $20 million, including $4 million in 1996, in order to meet the acid rain requirements of the Act. The acid rain program under the Act also governs SO2 allowances. An allowance is defined as an authorization for an owner to emit one ton of SO2 into the atmosphere. Currently, Utilities receives a sufficient number of allowances annually to offset its emissions of SO2 from its Phase I units. It is anticipated that in the year 2000, Utilities may have an insufficient number of allowances annually to offset its estimated emissions and may have to purchase additional allowances, or make modifications to the plants or limit operations to reduce emissions. Utilities is reviewing its options to ensure that it will have sufficient allowances to offset its emissions in the future. Utilities believes that the potential cost of ensuring sufficient allowances will not have a material adverse effect on its financial position or results of operations. The Act and other federal laws also require the United States Environmental Protection Agency (EPA) to study and regulate, if necessary, additional issues that potentially affect the electric utility industry, including emissions relating to NOx, ozone transport, mercury and particulate control; toxic release inventories and modifications to the PCB rules. Currently, the impacts of these potential regulations are too speculative to quantify. In 1995, the EPA published the Sulfur Dioxide Network Design Review for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst- case modeling method suggests that the Cedar Rapids area could be classified as "nonattainment" for the National Ambient Air Quality Standard (NAAQS) established for SO2. The worst-case modeling study suggested that two of Utilities' generating facilities contribute to the modeled exceedences and recommended that additional monitors be located near Utilities' sources to assess actual ambient air quality. In the event that Utilities' facilities contribute excessive emissions, Utilities would be required to reduce emissions, which would primarily entail capital expenditures for modifications to the facilities. Utilities is planning to convert one of its fossil generating facilities to a natural gas-fired cogeneration facility. Such facility was contributing to the modeled exceedences thus the conversion will have the added inherent benefit of reducing SO2 emissions. Utilities is proposing to resolve the remainder of EPA's nonattainment concerns by installing a new stack at the other generating facility contributing to the modeled exceedences at a potential capital cost of up to $4.5 million over the next four years. The National Energy Policy Act of 1992 requires owners of nuclear power plants to pay a special assessment into a "Uranium Enrichment Decontamination and Decommissioning Fund." The assessment is based upon prior nuclear fuel purchases and, for the DAEC, averages $1.4 million annually through 2007, of which Utilities' 70% share is $1.0 million. Utilities is recovering the costs associated with this assessment through its electric fuel adjustment clauses over the period the costs are assessed. Utilities' 70% share of the future assessment, $10.9 million payable through 2007, has been recorded as a liability in the Consolidated Balance Sheets, including $0.8 million included in "Current liabilities - Environmental liabilities," with a related regulatory asset for the unrecovered amount. The Nuclear Waste Policy Act of 1982 assigned responsibility to the U.S. Department of Energy (DOE) to establish a facility for the ultimate disposition of high level waste and spent nuclear fuel and authorized the DOE to enter into contracts with parties for the disposal of such material beginning in January 1998. Utilities entered into such a contract and has made the agreed payments to DOE. The DOE, however, has experienced significant delays in its efforts and material acceptance is now expected to occur no earlier than 2010 with the possibility of further delay being likely. Utilities has been storing spent nuclear fuel on-site since plant operations began in 1974 and has current on- site capability to store spent fuel until 2002. Utilities is aggressively reviewing options for additional spent nuclear fuel storage capability, including expanding on-site storage and supporting legislation currently before the U.S. Congress, to resolve the lack of progress by the DOE. The Low-Level Radioactive Waste Policy Amendments Act of 1985 mandated that each state must take responsibility for the storage of low- level radioactive waste produced within its borders. The State of Iowa has joined the Midwest Interstate Low-Level Radioactive Waste Compact Commission (Compact), which is planning a storage facility to be located in Ohio to store waste generated by the Compact's six member states. At June 30, 1996, Utilities has prepaid costs of approximately $1.1 million to the Compact for the building of such a facility. A Compact disposal facility is anticipated to be in operation in approximately ten years after approval of new enabling legislation by the member states. Such legislation has been approved by all six states. Approval by the U.S. Congress will also be required before it is effective and is currently expected to be considered in 1997. On-site storage capability currently exists for low-level radioactive waste expected to be generated until the Compact facility is able to accept waste materials. In addition, the Barnwell, South Carolina disposal facility has reopened for an indefinite time period and Utilities is in the process of shipping to Barnwell the majority of the low-level radioactive waste it has accumulated on-site, and intends to ship the waste it produces in the future as long as the Barnwell site remains open, thereby minimizing the amount of low-level waste stored on-site. The possibility that exposure to electric and magnetic fields (EMF) emanating from power lines, household appliances and other electric sources may result in adverse health effects has been the subject of increased public, governmental, industry and media attention. A considerable amount of scientific research has been conducted on this topic without definitive results. Research is continuing in order to resolve scientific uncertainties. The Company cannot predict the outcome of this research. OTHER MATTERS Competition As legislative, regulatory, economic and technological changes occur, electric utilities are faced with increasing pressure to become more competitive. Such competitive pressures could result in loss of customers and an incurrence of stranded costs (i.e. the cost of assets rendered unrecoverable as the result of competitive pricing). To the extent stranded costs cannot be recovered from customers, they would be borne by security holders. The National Energy Policy Act of 1992 addresses several matters designed to promote competition in the electric wholesale power generation market. In April 1996, the FERC issued final rules (FERC Orders 888 and 889), largely confirming earlier proposals, requiring electric utilities to open their transmission lines to other wholesale buyers and sellers of electricity. The rules became effective on July 9, 1996. The key provisions of the rules are: 1) utilities must act as "common carriers" of electricity, reserving capacity on their lines for other wholesale buyers and sellers of electricity and charging competitors no more than they pay themselves for use of the lines; 2) utilities must establish electronic bulletin boards to share information about transmission capacity; and 3) utilities can recover "stranded costs" by charging large wholesale customers a fee for switching to a new supplier. Utilities filed conforming pro-forma open access transmission tariffs with the FERC which became effective October 1, 1995. In response to FERC Order 888, Utilities filed its final pro-forma tariffs with FERC on July 9, 1996. These tariffs have not yet been approved by the FERC. The geographic position of Utilities' transmission system could provide revenue opportunities in the open access environment. The Company cannot predict the long-term consequences of these rules on its results of operation or financial condition. The final FERC rules do not provide for the recovery of stranded costs resulting from retail competition. The various states retain jurisdiction over whether to permit retail competition, the terms of such retail competition and the recovery of any portion of stranded costs that are ultimately determined by FERC and the states to have resulted from retail competition. As part of Utilities' strategy for the emerging and competitive power markets, Utilities, IPC and Wisconsin Power and Light Company (the utility subsidiary of WPLH), and a number of other utilities have proposed the creation of an independent system operator (ISO) for the companies' power transmission grid. The companies would retain ownership and control of the facilities, but the ISO, subject to FERC approval, would set rates for access and assume fair treatment for all companies seeking access. The proposal requires approval from state regulators and the FERC. The IUB initiated a Notice of Inquiry (Docket No. NOI-95-1) in early 1995 on the subject of "Emerging Competition in the Electric Utility Industry." A one-day roundtable discussion was held to address all forms of competition in the electric utility industry and to assist the IUB in gathering information and perspectives on electric competition from all persons or entities with an interest or stake in the issues. Additional discussions were held in December 1995, May 1996 and July 1996. In January 1996, the IUB created its own timeline for evaluating industry restructuring in Iowa. Included in the IUB's process was the creation of a 22-member advisory panel, of which Utilities is a member. The IUB has established a self-imposed deadline of the fourth quarter of 1996, for publishing its analysis of various restructuring options and any advisory panel comments on the IUB's options and analysis. The IUB's schedule calls for public information meetings to be held around the state of Iowa during late 1996 and early 1997. Utilities is subject to the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). If a portion of Utilities' operations become no longer subject to the provisions of SFAS 71, as a result of competitive restructurings or otherwise, a write-down of related regulatory assets would be required, unless some form of transition cost recovery is established by the appropriate regulatory body. Utilities believes that it still meets the requirements of SFAS 71. The Company cannot predict the long-term consequences of these competitive issues on its results of operations or financial condition. The Company's strategy for dealing with these emerging issues includes seeking growth opportunities, continuing to offer quality customer service, ongoing cost reductions and productivity enhancements, the major objective of which is to allow Utilities to better prepare for a competitive, deregulated electric utility industry. In this connection, Utilities has undertaken Process Redesign, an effort to improve service levels, to reduce its cost structure and to become more market-focused and customer-oriented. Process Redesign is examining the major business processes within Utilities, which are: Customer Service Fulfillment, Fossil-Fueled Energy Supply, Nuclear Energy Supply, Non-Electric Fuel Supply Chain, Transmission and Distribution Energy Delivery, and Planning, Budgeting & Performance Management. These areas were examined during Phase I of the effort, which lasted from January 1995 through May 1995. Phase I recommendations were designed to make broad-based changes in the way work was performed and results were achieved in each of the processes. Management accepted the recommendations and, in June 1995, initiated Phase II of the project. The detailed designs resulting from Phase II were substantially completed in November 1995 and pilot programs began. Examples of the Process Redesign changes include, but are not limited to: managing the business in business unit form, rather than functionally; formation of alliances with vendors of certain types of material rather than opening most purchases to a bidding process; changing standards and construction practices in transmission and distribution areas; changing certain work practices in power plants; and improving the method by which service is delivered to customers in all customer classes. The specific recommendations range from simple improvements in current operations to radical changes in the way work is performed and service is delivered. Utilities currently intends to implement all of the recommendations of the Process Redesign teams, although the pilot stage or potential effects of the Proposed Merger could prove that some of the recommendations are not efficient or effective and must be revised or eliminated. Subject to delays caused by implementing any such revisions, implementation of the Process Redesign changes will be partially completed in 1996, but, certain results will not be achieved until 1997. In addition, the Company must give consideration to the potential effects of the Proposed Merger as part of the implementation process so that duplication of efforts are avoided. Accounting Pronouncements SFAS 121, issued in March 1995 by the FASB and effective for 1996, establishes accounting standards for the impairment of long-lived assets. SFAS 121 also requires that regulatory assets that are no longer probable of recovery through future revenues be charged to earnings. The Company adopted this standard on January 1, 1996, and the adoption had no effect on the financial position or results of operations of the Company. Financial Derivatives The Company has a policy that financial derivatives are to be used only to mitigate business risks and not for speculative purposes. At June 30, 1996, the Company did not have any material financial derivatives outstanding. Inflation Under the rate making principles prescribed by the regulatory commissions to which Utilities is subject, only the historical cost of plant is recoverable in revenues as depreciation. As a result, Utilities has experienced economic losses equivalent to the current year's impact of inflation on utility plant. In addition, the regulatory process imposes a substantial time lag between the time when operating and capital costs are incurred and when they are recovered. Utilities does not expect the effects of inflation at current levels to have a significant effect on its financial position or results of operations. PART II. - OTHER INFORMATION Item 1. Legal Proceedings. On April 30, 1996, Utilities filed suit, IES Utilities Inc. v. Home Ins. Co., et al., No. 4-96-CV-10343 (S.D. Iowa filed Apr. 30, 1996), against various insurers who had sold comprehensive general liability policies to Iowa Southern Utilities Company (ISU) and Iowa Electric Light and Power Company (IE) (Utilities was formed as the result of a merger of ISU and IE). The suit seeks judicial determination of the respective rights of the parties, a judgment that each defendant is obligated under its respective insurance policies to pay in full all sums that the Company has become or may become obligated to pay in connection with its defense against allegations of liability for property damage at and around FMGP sites, and indemnification for all sums that it has or may become obligated to pay for the investigation, mitigation, prevention, remediation and monitoring of damage to property, including damage to natural resources like groundwater, at and around the FMGP sites. Reference is made to Notes 3 and 6 of the Notes to Consolidated Financial Statements for a discussion of rate matters and environmental matters, respectively, and Item 2. Management's Discussion and Analysis of the Results of Operations and Financial Condition - Environmental Matters. Item 2. Changes in the Rights of the Company's Security Holders. None. Item 3. Default Upon Senior Securities. None. Item 4. Results of Votes of Security Holders. None. Item 5. Other Information. (a) The Company has calculated the ratio of earnings to fixed charges pursuant to Item 503 of Regulation S-K of the Securities and Exchange Commission as follows: For the twelve months ended: June 30, 1996 3.23 December 31, 1995 3.04 December 31, 1994 3.18 December 31, 1993 3.41 December 31, 1992 2.49 December 31, 1991 2.64 (b) John E. Ebright joined the Company as Controller & Chief Accounting Officer, effective July 8, 1996. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits - 3(a) Bylaws of Registrant, as amended May 7, 1996 (Filed as Exhibit 3(a) to the Company's Form 10-Q for the quarter ended March 31, 1996). *12 Ratio of Earnings to Fixed Charges *27 Financial Data Schedule. * Exhibits designated by an asterisk are filed herewith. (b) Reports on Form 8-K - Items Reported Financial Statements Date of Report 5,7 None April 3, 1996 (1) 5,7 None April 12, 1996 (2) 5,7 None May 22, 1996 (3) (1) The Form 8-K report was filed on April 8, 1996 with the earliest event reported occurring on April 3, 1996. (2) The Form 8-K report was filed on April 18, 1996 with the earliest event reported occurring on April 12, 1996. (3) The Form 8-K report was filed on May 24, 1996 with the earliest event reported occurring on May 22, 1996. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. IES UTILITIES INC. (Registrant) Date: August 14, 1996 By /s/ Dennis B. Vass (Signature) Dennis B. Vass Treasurer & Principal Financial Officer By /s/ John E. Ebright (Signature) John E. Ebright Controller & Chief Accounting Officer EX-12 2 EXHIBIT 12 IES UTILITIES INC. COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
Twelve Months Year Ended December 31, Ended 1991 1992 1993 1994 1995 June 30, 1996 (in thousands, except ratio of earnings to fixed charges) Net income $ 47,563 $ 45,291 $ 67,970 $ 61,210 $ 59,278 $ 63,408 Federal and state income taxes 23,494 20,723 37,963 37,966 41,095 45,363 Net income before income taxes 71,057 66,014 105,933 99,176 100,373 108,771 Interest on long-term debt 31,171 35,689 34,926 37,942 36,375 35,923 Other interest 5,595 3,939 5,243 3,630 8,085 8,228 Estimated interest component of rents 6,594 4,567 3,729 3,970 4,637 4,562 Fixed charges as defined 43,360 44,195 43,898 45,542 49,097 48,713 Earnings as defined $ 114,417 $ 110,209 $ 149,831 $ 144,718 $ 149,470 $ 157,484 Ratio of earnings to fixed charges (unaudited) 2.64 2.49 3.41 3.18 3.04 3.23 For the purposes of computation of these ratios (a) earnings have been calculated by adding fixed charges and federal and state income taxes to net income; (b) fixed charges consist of interest (including amortization of debt expense, premium and discount) on long-term and other debt and the estimated interest component of rents.
EX-27 3
UT The schedule contains summary financial information extracted from the Consolidated Balance Sheet at June 30, 1996 and the Consolidated Statement of Income and the Consolidated Statement of Cash Flows for the six months ended June 30, 1996 and is qualified in its entirety by reference to such financial statements. 1,000 6-MOS DEC-31-1996 JUN-30-1996 PER-BOOK 1,324,281 61,581 98,504 21,697 211,776 1,717,839 33,427 279,042 211,422 523,891 0 18,320 457,422 21,575 0 108,000 23,140 0 26,649 13,883 524,959 1,717,839 363,008 16,494 305,796 305,796 57,212 2,519 59,731 21,880 21,357 457 20,900 22,000 35,222 71,675 0 0 Income tax expense is not included in Operating Expense in the Consolidated Statements of Income for IES Utilities Inc.
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