-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, nO7knmC0k2JCfWz7X3t+y7acgNi5jPyMegiuVgM1rmdF55WViGVuzAECVlcNmqaz HC6UETpShKd9O2j+PmrPAA== 0000052491-95-000009.txt : 19950616 0000052491-95-000009.hdr.sgml : 19950616 ACCESSION NUMBER: 0000052491-95-000009 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950322 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: IOWA ILLINOIS GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000052491 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 420673189 STATE OF INCORPORATION: IL FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 002-26675 FILM NUMBER: 95522338 BUSINESS ADDRESS: STREET 1: 206 E 2ND ST CITY: DAVENPORT STATE: IA ZIP: 52808 BUSINESS PHONE: 3193267111 10-K 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [Fee Required] For the Fiscal Year Ended December 31, 1994 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [No Fee Required] For the Transition Period from ____________ to ____________ Commission File Number 1-3573 IOWA-ILLINOIS GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Illinois 42-0673189 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) One RiverCenter Place, 106 East Second Street, Davenport, Iowa 52801 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (319) 326-7111 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange on Title of each class which registered Common Shares Chicago Stock Exchange Common Share Purchase Rights New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None (Title of Class) 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 and 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 by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X) The aggregate market value of the Company's Common Shares was approximately $648 million based upon the New York Stock Exchange composite transaction closing price as of February 27, 1995. The Company's $7.80 and $5.25 Series Cumulative Preference Shares are traded in the over-the-counter market. Bid and asked prices on all such shares are not regularly quoted. As of February 27, 1995, 99.8% of the Company's voting shares were owned by nonaffiliates. The aggregate number of the Company's Common Shares outstanding at February 27, 1995 was 29,781,296. Documents of Which Portions are Incorporated by Reference Part of Form 10-K Document Incorporated by Reference I and II Annual Report to Shareholders for the year ended December 31, 1994 III Proxy Statement dated March 15, 1995 Only the portions of such documents which are specifically incorporated by reference herein shall be deemed to be filed as a part of this Form 10-K. Part I Item 1. Business (a) General Development of Business Iowa-Illinois Gas and Electric Company (the Company or Iowa- Illinois) was incorporated under the laws of the State of Illinois in 1940 and is engaged in the business of generating, transmitting, distributing and selling electric energy and distributing, selling and transporting natural gas in the States of Illinois and Iowa. Through a wholly owned subsidiary, InterCoast Energy Company, the Company engages in non-regulated energy-related businesses. The Company's principal executive offices are located at One RiverCenter Place, 106 East Second Street, Davenport, Iowa 52801 (telephone: 319-326-7111). On December 21, 1994, the shareholders of the Company, Midwest Resources Inc. (Midwest Resources) and Midwest Power Systems Inc. (Midwest Power) approved a strategic merger of equals to form MidAmerican Energy Company (MidAmerican). MidAmerican will be structured as a utility with the Company, Midwest Resources and Midwest Power being merged into the new company. Pursuant to the terms of the merger agreement, Midwest Resources' common shareholders will receive one share of MidAmerican common stock for each Midwest Resources share and the Company's common shareholders will receive 1.47 shares of MidAmerican common stock for each Company share. At the effective date of the merger, each series of the Company's preference shares then outstanding will be converted into an equal number of shares of MidAmerican preferred stock. Approval of the merger is required from the following regulatory agencies: the Iowa Utilities Board (IUB), the Illinois Commerce Commission (ICC) and the Federal Energy Regulatory Commission (FERC). Approval by the Nuclear Regulatory Commission (NRC) of the transfer of the Quad-Cities Nuclear Power Station (Quad-Cities Station) license to MidAmerican must also be obtained. Applications for approval of the merger were filed with the IUB and the ICC in October 1994. An application for approval of the merger was filed with the FERC in November 1994. At the same time, consistent with FERC policy, the Company filed open access, comparable services electric tariffs with the FERC, which tariffs will allow others to use MidAmerican's electric transmission system in a manner comparable to its use by MidAmerican. In January 1995, the IUB issued an order approving the merger. The ICC and FERC are expected to issue orders on the merger by mid 1995. A filing with the NRC was made in November 1994. Completion of the merger is expected during 1995. The management of the Company believes that the formation of MidAmerican will create a larger, stronger company, which will be better positioned to grow and succeed within the emerging competitive utility industry. In this new environment, management believes that successful utilities will need financial strength, market leadership and low costs. The merger will address these elements. The Company expects that competitive pressures in the electric industry initially will be focused on industrial sales. While about 25% of Iowa-Illinois' electric revenues come from industrial customers, only about 20% of MidAmerican's electric revenues will come from this customer group. In terms of the competitive position of MidAmerican, the industrial rates of both Iowa-Illinois and Midwest Power are well below national and regional averages. Management believes that MidAmerican also will be well- positioned for competition in the natural gas industry, with low- cost reliable gas supply portfolios and multiple pipeline suppliers. The residential gas rates of Iowa-Illinois and Midwest Power are well below national averages. Management believes that the merger will provide opportunities to achieve significant long-term benefits for shareholders, customers, employees and the communities served by the two companies. These benefits are: increased size and stability, better use of generating capacity, coordination of dispatch, savings on purchases, coordination of non-regulated businesses and reduced administrative costs. It is estimated the merger will result in savings of nearly $500 million over 10 years. Iowa-Illinois and Midwest Power have announced plans to reduce their combined utility work forces by a total of approximately 15 percent in conjunction with development of a restructured organization to be effective at the completion of the merger. As part of these reductions, the companies are offering incentive retirement and severance programs to salaried employees. The companies estimate these programs will reduce 1995 after-tax earnings of MidAmerican by approximately $9 million, or 9 cents a share, if the merger is consummated in 1995. (b) Financial Information About Industry Segments Financial information on the Company's segments of business is included under the Note "Segment Information" on pages 36 and 37 of the Company's Annual Report to Shareholders for 1994 which pages are incorporated herein by reference. This information is also included in Exhibit 13.A.4 to this Form 10-K. (c) Narrative Description of Business General The Company distributes electric energy in the Quad-Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois), Iowa City and Fort Dodge, Iowa and a number of adjacent communities and areas. The Company distributes natural gas in the Quad-Cities, and in Iowa City, Cedar Rapids, Fort Dodge and Ottumwa, Iowa and a number of adjacent communities and areas. Electric and/or gas service is provided in 22 incorporated communities in Illinois and 48 incorporated communities in Iowa. Franchises with various expiration dates have been obtained from all 70 communities. The length of term of the franchises is typically 25 years. The population of the Company's electric service territory is approximately 425,000 and the population of its gas service territory is approximately 600,000. As of December 31, 1994, the Company had 202,003 retail electric customers and 244,062 gas customers. The Company has a residential, agricultural commercial and diversified industrial customer group, in which no single industry or customer accounted for more than 8.6% (primary metal industry) of the Company's total 1994 electric operating revenues or 4.7% (real estate) of its total 1994 gas operating revenues. Among the primary industries served by the Company are those which are concerned with the manufacturing, processing and fabrication of primary metals, real estate, food products, farm and other non-electrical machinery, cement and gypsum products. For the year ended December 31, 1994, the Company derived approximately 64.1% of its gross utility operating revenues from its electric business and 35.9% from its gas business. For 1993 and 1992, the corresponding percentages were 62.1% electric and 37.9% gas, and 62.8% electric and 37.2% gas, respectively. Historical electric sales (kwh) by customer class as a percent of total electric sales and retail electric sales data (kwh) by jurisdiction are shown below: Total Electric Sales By Customer Class 1994 1993 1992 Residential 20.1% 19.9% 19.4% Small Commercial and Industrial 22.3 21.5 21.5 Large Commercial and Industrial 34.3 31.9 34.9 Public Street Lighting 0.4 0.3 0.5 Public Authorities 1.6 1.6 1.6 Sales for Resale 21.3 24.8 22.1 Total 100.0% 100.0% 100.0% Retail Electric Sales By Jurisdiction 1994 1993 1992 Iowa 67.1% 67.0% 65.4% Illinois 32.9 33.0 34.6 Total 100.0% 100.0% 100.0% Historical gas sales (ccf), including transportation, by customer class and by jurisdiction are shown below: Total Gas Sales By Customer Class 1994 1993 1992 Residential 33.9% 36.5% 36.6% Commercial 19.7 20.7 20.8 Industrial 6.0 5.3 6.5 Processing & Boiler Fuel - 0.2 0.6 Transportation 40.4 37.3 35.5 Total 100.0% 100.0% 100.0% Retail Gas Sales By Jurisdiction 1994 1993 1992 Iowa 81.1% 80.1% 79.4% Illinois 18.9 19.9 20.6 Total 100.0% 100.0% 100.0% There are seasonal variations in the Company's electric and gas businesses, which are principally related to the use of energy for air conditioning and heating. In 1994, 39.2% of the Company's electric revenues were reported in the months of June, July, August and September, reflecting the use of electricity for cooling, and 63.1% of the Company's gas revenues were reported in the months of January, February, March and December, reflecting the use of gas for heating. At December 31, 1994, the Company had 1,387 employees, of which 1,289 were employed in utility operations and 98 were employed by InterCoast Energy Company. Rate Matters Under Illinois law, new rates may be put into effect by the Company 45 days after filing with the ICC, or on such earlier date as the ICC may approve, subject to the power of the ICC to suspend the proposed new rates for a period not to exceed eleven months after filing, pending a hearing. Under Iowa law, temporary collection of higher rates can begin (subject to refund) 90 days after filing with the IUB for that portion of such higher rates approved by the IUB based on prior ratemaking principles and a rate of return on common equity previously approved. If the IUB has not issued a final order within ten months after the filing date, the temporary rates cease to be subject to refund and any balance of the requested rate increase may then be collected subject to refund. Exceptions to the ten month limitation are provided for extensions due to a utility's lack of due diligence in the rate proceeding, judicial appeals and situations involving new generating units being placed in service. In October 1994, the Company filed an application with the IUB to recover the costs of state-mandated energy-efficiency programs offered to Iowa electric and gas customers since 1992. Costs of the programs are to be recovered over four years, as required by Iowa law. The overall annual rate increase requested, including a return on deferred amounts and an allowance for performance rewards, is approximately $4.7 million (1.4%). The proposed effective date for cost-recovery additions on customer bills is June 1995. In April 1992, the FERC issued Order No. 636, directing a restructuring by interstate pipeline companies for their natural gas sales and transportation services. The FERC Order contemplated that transitional gas supply realignment costs related to this restructuring may be billed by interstate pipelines to their customers. At December 31, 1994, a regulatory asset of $23.5 million, with an offsetting non-current Other Liability, has been recorded. In addition, the Company estimates it may incur other future billings of approximately $15 million related to such restructuring. The Company is currently recovering such costs through rates. The Company has established an external trust for the investment of funds collected for nuclear decommissioning. Electric tariffs in effect for 1995 include provisions for annual decommissioning costs of approximately $8.6 million. In Illinois, nuclear decommissioning costs are included in customer billings through a mechanism that permits annual adjustments. In Iowa, such costs are reflected in base rates. The Company's Iowa electric tariffs contain a Uniform Electric Energy Adjustment Clause under which the Company's billings reflect changes in the cost of all fuels used for electric generation, including nuclear fuel disposition costs, as well as the net effect of energy transactions (other than capacity) with other utilities. Changes in the cost of gas to the Company are reflected in its Iowa gas rates through the Iowa Uniform Purchased Gas Adjustment Clause. Under Illinois electric tariffs, the Company's Fuel Cost Adjustment Clause reflects changes in the cost of all fuels used for electric generation, including allowable fuel transportation costs, nuclear fuel disposition costs and the effects of energy transactions (other than capacity and margins on interchange sales) with other utilities. Changes in the cost of gas to the Company are reflected in its Illinois gas rates through the Illinois Uniform Purchased Gas Adjustment Clause. Electric Operations The Company's accredited 1994 summer net generating capacity was 1,430,868 kilowatts, consisting of (a) 384,750 kilowatts from the Company's 25% undivided interest in the Quad-Cities Station, jointly owned with ComEd, (b) 914,918 kilowatts from interests in wholly or jointly owned coal-fired units, (c) 128,000 kilowatts from wholly owned gas/oil fired units, and (d) 3,200 kilowatts from wholly owned hydro-electric units. In February 1995, the Mid-Continent Area Power Pool approved an increase in the accreditation of the Louisa Generating Station from 650 megawatts to 675 megawatts effective as of June 7, 1994. This action increased the Company's summer net generating capacity from 1,430,868 kilowatts to 1,441,618 kilowatts. The net generating capacity at any time may be less due to regulatory restrictions, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling or modifications. On August 26, 1993, the Company established its record one-hour peak electric demand of 1,084,965 kilowatts. Fuel Supply for Electric Operations The Company's sources of fuel for electric generation have been as follows for the periods shown: Year Ended December 31, Fuel Source 1994 1993 1992 Coal 73.63% 63.18% 63.95% Nuclear 25.80 36.52 35.56 Gas 0.46 0.28 0.45 Oil 0.11 0.02 0.04 In 1995 the Company projects its electric generation requirements will be met as follows: coal - 59%, nuclear - 41%. The average costs of fuels (including transportation and handling costs) in cents per million BTU's consumed have been as follows for the periods shown: Year Ended December 31, Fuel Source 1994 1993 1992 Nuclear 47.40 47.36 44.57 Coal 97.49 105.79 102.97 Gas 345.09 373.25 313.33 Oil 378.36 440.95 412.80 Total Weighted Average 84.93 86.62 83.93 The average cost of coal (including transportation and handling costs) per ton for the years 1994, 1993 and 1992 has been $17.13, $18.22 and $17.57, respectively. The Company has been advised by ComEd that the majority of its uranium concentrate and uranium conversion requirements for the Quad-Cities Station for 1995 can be met under existing supplies or commitments. ComEd foresees no problem in obtaining the remaining requirements now or obtaining future requirements. ComEd further advises that all enrichment requirements have been contracted for through 1999. Commitments for fuel fabrication have been obtained at least through 2000. ComEd does not anticipate that it will have any difficulty in contracting for uranium concentrates for conversion, enrichment or fabrication of nuclear fuel needed for the Quad-Cities Station. In June 1985, the Company satisfied its financial obligation for Quad-Cities Station disposal costs for fuel burned prior to April 1983 by making a lump sum payment of $24.8 million to the Department of Energy (DOE). The payment was made principally from funds previously collected from customers. Disposal costs for fuel burned after April 1983 are paid quarterly. Such costs are included in the cost of fuel and recovered through fuel and energy adjustment clause billings. See Nuclear Regulation herein for further information concerning the disposal of spent nuclear fuel. The Company believes its sources of coal for its fossil- fueled generating stations are and will be satisfactory. Renewal of expiring contracts and negotiations of new agreements will be pursued as required. The coal requirements for the Riverside Station are being met primarily through spot purchases. Contracts for low-sulfur Wyoming coal have been executed for the Neal Unit 3, Council Bluffs, Ottumwa and Louisa units which will supply a portion of requirements through the years 1996, 1999, 2001 and 2003, respectively. Unit trains are being used for transporting coal for the Riverside, Neal, Council Bluffs, Ottumwa and Louisa units. The Company has negotiated certain modifications to existing contracts to achieve flexibility in volumes to be delivered while also providing reasonable assurance of supply. In addition, the Company has used spot market purchases of coal to effectively manage inventory levels and take advantage of near term coal market opportunities. The Company is continuing to monitor existing contracts and coal supply requirements, balancing coal requirements with a combination of contract and spot purchases. Gas Operations During 1994, the Company purchased over 99 percent of the gas required to supply its customers from non-pipeline gas suppliers on a firm or interruptible basis and transported such gas on a firm or interruptible basis through the Natural Gas Pipeline Company of America (NGPL), ANR Pipeline Company (ANR) and Northern Natural Gas (NNG) systems. The remainder was purchased from NNG. All gas supply purchased from NNG is at rates approved by the FERC under the Natural Gas Act. Likewise, transportation rates negotiated with NGPL, ANR and NNG are subject to FERC approval. Non-pipeline supply prices are negotiated. The Company withdrew approximately 94 percent of the gas in leased storage during the 1993-94 heating season. Storage gas was replaced during the summer for the 1994-95 heating season. Beginning in December 1993, the Company has rebundled a portion of its firm pipeline transportation with firm supply from a third party supplier. This citygate service replaces bundled sales service previously purchased from one of the Company's pipeline suppliers. The Company provides natural gas transportation service through its distribution system for end-use customers. Transportation of customer-owned gas was 40.4 percent of the total Company throughput during 1994. For the 1994-95 heating season, the Company's peak-day supply delivery availability consists of firm capacity on the NGPL, ANR and NNG systems for the transportation of firm non- pipeline gas. In addition, peak-day supply is available from gas previously purchased by the Company and held in leased pipeline storage. The Company leases storage from NGPL, ANR and NNG. Liquefied natural gas (LNG) stored in the Company's LNG facility is also available for peak-day use. Following are the current peak-day supply sources for the Company which are available for the 1994-95 heating season by volume and proportions: Millions Percent of Cubic of Feet Total Underground Storage 205.1 42.1 Firm Non-Pipeline Supply 141.4 29.0 Rebundled Service 96.9 19.9 LNG Facility 40.0 8.2 Pipeline System Management Service 4.0 0.8 487.4 100.0 Peak-day firm demand for the 1994-95 heating season was projected to be 464.4 million cubic feet for the Company. The actual highest demand for peak-day firm sales for the 1994-95 heating season for the Company was 353 million cubic feet on January 4, 1995. The average temperature on that day was 1 degree above zero. On January 17, 1994, a new record was set for total Company gas throughput (sales and transportation) of 516 million cubic feet. In the Spring of 1995, the Company will begin construction on a 63-mile, 16-inch diameter pipeline from NNG's main line near Dubuque, Iowa, to the Company's facilities in Davenport, Iowa. The interconnection will give the Company and its customers more supply and pipeline transportation options, which will help ensure continued access to the lowest-cost gas supplies. A 1994 ruling by the IUB will enhance gas earnings. The Company has firm rights to pipeline capacity to transport gas from the production area to its service territory. With the restructuring of the industry, if the Company does not need the capacity (due to fluctuations in anticipated system demand), it can "sublease" such capacity to other companies. To provide incentives for the achievement of optimum use of available transportation capacity, the IUB ruling allows the Company to retain 30% of Iowa revenues earned on the "subleased" capacity and returns 70% to customers through the purchased gas adjustment. See Rate Matters for a discussion of certain transition costs. Construction Program The table below shows actual construction expenditures for 1994 and budgeted expenditures for 1995 and for the period 1996- 1999: 1994 1995 1996-99 Actual Budgeted Budgeted (Thousands of Dollars) Electric Production $ 18,279 $ 15,651 $ 56,497 Transmission 1,429 1,307 6,912 Distribution 10,128 13,345 37,196 Gas 12,246 31,118 59,268 General Plant 26,875 13,633 19,982 Subtotal 68,957 75,054 179,855 Nuclear Fuel 11,316 9,283 35,669 Total $ 80,273 $ 84,337 $215,524 The amounts shown above include allowance for funds used during construction. Of the $72.1 million of budgeted electric production expenditures for the 1995-1999 period, $35.9 million are for expenditures at the Quad-Cities Station. In addition to the amounts shown above, the Company also expects to contribute a total of $43.2 million to an external trust for nuclear decommissioning during the 1995-1999 period. The Company's above budgeted construction expenditures do not include any amounts that may be required to pay the Company's share of the cost of replacing certain stainless steel piping at the Quad-Cities Station. Such expenditures are currently not expected to be required. See Nuclear Regulation. General Regulation The Company is a public utility under the laws of Illinois and is regulated by the ICC as to retail rates, services, accounts, issuance of securities, affiliate transactions, construction, acquisition and sale of utility property, acquisition and sale of securities and in other respects as provided by the laws of Illinois. The Company is also a public utility under the laws of Iowa and is regulated by the IUB as to retail rates, services, accounts, construction of utility property and in other respects as provided by the laws of Iowa. The Company is subject to the jurisdiction of the FERC with respect to certain matters, including short-term borrowings, rates for transmission and sale of electric energy at wholesale, interconnection of electric transmission facilities, acquisition and sale of certain electric utility property, installation and replacement of certain gas utility property and accounting policies and practices. Nuclear Regulation The Company is subject to the jurisdiction of the NRC with respect to the Quad-Cities Station. The NRC regulations control the granting of permits and licenses for the construction and operation of nuclear generating stations and subject such stations to continuing review and regulation. The NRC review and regulatory process covers, among other things, operations, maintenance, and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses. Attempts are made from time to time by various individuals or citizen groups to prohibit the development or use of nuclear power through initiation of proceedings before the NRC, other agencies or courts. Such proceedings frequently involve attacks on the validity of NRC rules which, if successful, could provide a basis for challenges to permits and licenses granted by the NRC in the past. The Illinois Department of Nuclear Safety (IDNS) has jurisdiction over certain activities in Illinois relating to nuclear power and safety and radioactive materials. Effective June 1987, the IDNS replaced the NRC as the regulator and licensor of certain source, by-product and special nuclear material in quantities not sufficient to form a critical mass, including such material contained in various measuring devices used at fossil-fuel power plants. The IDNS has promulgated regulations which are substantially similar to the corresponding federal regulations. The IDNS also has authority to license a low-level radioactive waste disposal facility and to regulate alternative methods for disposing of materials which contain only trace amounts of radioactivity. Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high- level radioactive wastes. ComEd, as required by the NWPA, has signed a contract with the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste beginning not later than January 1998. The DOE has stated, however, that the delivery schedule for spent nuclear fuel may be delayed, and ComEd expects that it will be significantly delayed. The costs incurred by the DOE for disposal activities will be financed by fees charged to owners and generators thereof. The primary responsibility for the interim storage of spent nuclear fuel and high-level radioactive wastes will rest with the owners and generators thereof. ComEd has informed the Company that there is on-site storage capability at the Quad-Cities Station sufficient to permit such interim storage at least through 2009. Meeting spent nuclear fuel storage requirements beyond such time could require a new and separate storage facility, the cost of which has not been determined at this time. Industry activities are underway to utilize dry cask storage for high-level radioactive waste. This may provide an alternative for interim on-site storage of such waste. ComEd anticipates the possibility of serious difficulties in disposing of high-level radioactive waste. The federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into compacts to provide for regional disposal facilities for such waste, subject to approval by the U.S. Congress of each such compact. Under the 1985 amendments to that Act, a compact could restrict the use of a region's disposal facilities after January 1993 to wastes generated within the region. Illinois has entered into a compact with the State of Kentucky which has been approved by Congress. The IDNS had previously estimated that a low-level radioactive waste disposal facility would be operational in Illinois by March 1994 at the earliest. However, in 1992 an independent panel rejected the only site in Illinois then being considered for a low-level disposal facility. Illinois has since enacted legislation changing the procedures for siting a low-level waste disposal facility. Since the loss of access to the only low- level radioactive waste site (at Barnwell, South Carolina) available to the Quad-Cities Station, effective June 30, 1994, Quad-Cities Station has constructed a temporary storage facility for on-site storage of this material. Quad-Cities Station will continue to store all low-level radioactive waste on-site until an off-site facility is again available. ComEd anticipates the possibility of serious difficulties in disposing of low-level radioactive waste. The continuing viability of commercial nuclear power is subject to resolution of the issues of spent nuclear fuel storage and disposal of radioactive waste. Quad-Cities Station continues to be considered by the NRC as a plant that is safe to operate. However, the NRC has characterized the plant as "adversely trending" with respect to certain performance expectations. ComEd has undertaken measures to correct this performance trend. Federal regulations provide that any operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility and the deficiencies are not corrected within four months of such determination. Under the regulations, the NRC may permit operation of facilities, even though the emergency preparedness plans are deficient, upon an examination of other factors, including whether the deficiencies are significant for the facility in question, whether adequate interim compensatory actions have been or will be taken promptly and whether other compelling reasons exist for operation consistent with public health and safety. ComEd has advised the Company that emergency preparedness plans for the Quad-Cities Station have been approved by the NRC. ComEd has also advised the Company that state and local plans relating to the Quad- Cities Station have been approved by the Federal Emergency Management Agency. ComEd continues to cooperate with the NRC and appropriate state and local agencies on emergency preparedness issues. In June 1988, the NRC adopted final regulations with respect to the decommissioning of nuclear power plants. Among other things the regulations address the planning and funding of the eventual decommissioning of nuclear power plants. In response to these regulations, the Company submitted a report to the NRC in July 1990 indicating that it will provide "reasonable assurance" that funds will be available to pay the costs of decommissioning its nuclear power plants by making monthly deposits to an external trust fund. Inter-granular stress corrosion was discovered in 1983 in certain stainless steel piping at the Quad-Cities Station. Remedial actions intended to avoid the need to replace such piping continue and the replacement of such piping is not expected to be required. Accordingly, the Company's budgeted construction expenditures do not include the amounts which would be required to pay the Company's share of the cost of replacing such piping. If replacement of all such piping were required, the Company's share of the costs of such replacement is estimated to be approximately $55 million at current price levels. Replacement of such piping would result in an extended outage and require the purchase of replacement power. The Company is a member of Nuclear Mutual Limited (NML), an industry mutual insurer established to provide property damage coverage for members' nuclear generating facilities. The Company would be subject to a maximum retrospective premium assessment of approximately $2 million based on its 25% share of the NML premium for Quad-Cities coverage in the event covered losses of NML members exceed the financial resources of the insurance company. A reserve has been established for this contingency. At December 31, 1994, NML had accumulated capital to a level that would make it unlikely the Company would have an exposure to a retrospective premium assessment in the event of a single incident to a member's facility. The Company is also a member of Nuclear Electric Insurance Limited (NEIL), an industry mutual insurance company, and an insured of American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters (ANI/MAELU). The related policy provisions provide that expenses for decontamination and the removal of debris shall be paid before any payment in respect of claims for property damage. A separate NEIL insurance policy covers the extra costs that would be incurred in obtaining replacement power during a prolonged covered outage of a member's nuclear plant. The Company is subject to retrospective premium assessments of approximately $4.1 million and $843,000 for its 25% share of the premium under the NEIL portion of the property damage coverage and the replacement power coverage, respectively. At December 31, 1994, NEIL had accumulated capital to a level that would make it unlikely the Company would have an exposure to a retrospective premium assessment in the event of a single incident to a member's facility. A Master Worker Policy issued by ANI/MAELU provides coverage for worker tort claims filed for bodily injury caused by the nuclear energy hazard. The coverage applies to workers whose "nuclear related employment" began after January 1, 1988. Under this policy, the Company could be subject to a maximum retrospective premium assessment of $1.5 million. Under the Price-Anderson federal legislation adopted in 1988, nuclear public liability coverage is supported by a mandatory industry-wide program under which owners of nuclear generating facilities could be assessed in the event of nuclear incidents. The Company would currently be subject to a maximum assessment of $39.6 million in the event of an incident, to be paid in increments of no more than $5 million per year per incident. Environmental Regulation The Company is subject to regulation regarding air, water, solid waste, hazardous and toxic materials and noise pollution by agencies of the federal government and of the States of Illinois and Iowa and may become subject to additional regulation as to these and other matters in the future. The Quad-Cities Station is subject to the jurisdiction of the NRC and IDNS as to atomic radiation. State and federal environmental laws and regulations as currently in effect have, and future modifications may have, the effect of (i) increasing the lead time for the construction of new facilities, (ii) significantly increasing the total cost of new facilities, (iii) requiring modification of certain of the Company's existing facilities, (iv) increasing the risk of delay on construction projects, (v) increasing the Company's cost of waste disposal and (vi) possibly reducing the reliability of service provided by the Company and the amount of energy available from the Company's facilities. Any of such items could have a substantial impact on amounts required to be expended by the Company in the future. Air Quality. Air quality regulations, promulgated by both the Iowa and Illinois pollution control boards in accordance with federal standards, impose restrictions on the emission of sulfur dioxide, nitrogen oxides and other air pollutants and require permits from the respective state environmental protection agency for the operation of emission sources. Permits authorizing operation of the Company's fossil-fueled generating facilities subject to this requirement have been obtained and, when such permits are to expire, the Company has, in a timely manner, filed applications for renewal. Clean Air Act legislation was signed into law in November 1990. Under the acid deposition control section of this legislation, national utility emissions of sulfur dioxide will be reduced in phased increments by 10 million tons from 1980 levels by the year 2000 and permanently capped at that level. National nitrogen oxide emissions will also be reduced in phased increments by 2 million tons from 1980 levels by the year 2000. In addition, continuous emission monitoring systems will be required at all affected facilities. This legislation also requires the government to study what controls, if any, should be imposed on utilities to control air toxics. The impact, if any, of the air toxics study on the Company cannot be determined at this time. The Company has four jointly and one wholly owned coal-fired generating stations, which represent approximately 65 percent of the Company's electric generating capability. Each of these facilities will be impacted to varying degrees by the legislation. Only one unit at the wholly owned generating station, representing approximately 10 percent of the Company's electric generating capability, is impacted by the emission reduction requirements effective in 1995. Under such requirements, beginning in 1995, this unit is required to hold allowances, issued by the federal government, in order to emit sulfur dioxide. The compliance strategy for this unit includes modifications to allow for burning low-sulfur coal, modifications for nitrogen oxide control and installation of a new emission monitoring system. The Company's remaining construction expenditures relative to this work are estimated to be $2.5 million. The four generating stations not affected until 2000 already burn low-sulfur coal, so additional capital costs will not be incurred for sulfur dioxide emission reduction requirements. Beginning in 2000, these facilities will be required to hold allowances, issued by the federal government, in order to emit sulfur dioxide. Installation of low nitrogen oxide burners is required at one of these facilities and existing emission monitoring systems at all four facilities require upgrading. The Company's remaining construction cost for this work is estimated to be $1.4 million. It is anticipated that any costs incurred by the Company to comply with the Clean Air Act legislation would be included in the cost of service on which the Company's rates for utility service are based. Water Quality. Under the Federal Water Pollution Control Act Amendments of 1972, as amended, the Company is required to obtain National Pollutant Discharge Elimination System (NPDES) permits to discharge effluents (including thermal discharges) from its properties into various waterways. All NPDES permits are subject to renewal after specified time periods not to exceed five years. The Company has obtained all necessary NPDES permits for its generating stations and, when such permits are expected to expire, the Company will file applications for renewal. Hazardous Materials and Waste Management. The Company is investigating five properties currently owned by the Company which were, at one time, sites of gas manufacturing plants. The purpose of these investigations is to determine whether waste materials are present, whether such materials constitute an environmental or health risk, and whether the Company has any responsibility for remedial action. One site is located in Illinois and four sites are located in Iowa. With regard to the Illinois property, the Company has signed a working agreement with the Illinois Environmental Protection Agency to perform further investigation to determine whether waste materials are present and, if so, whether such materials constitute an environmental or health risk. At December 31, 1994, an estimated liability of $3.3 million has been recorded for litigation, investigation and remediation related to the Illinois site. A regulatory asset has been recorded reflecting anticipated cost recovery through rates in Illinois. With regard to the Iowa sites, no agreement or consent order has been negotiated to perform any site investigations or remediation. Approximately $218,000 and $154,000 has been budgeted in 1995 and 1996, respectively, for site studies. The Company has recorded a $4 million estimated liability for the Iowa sites. A regulatory asset has been recorded based on the current regulatory treatment of comparable costs in Iowa. The estimated recorded liabilities for these properties are based upon preliminary data. Thus, actual costs could vary significantly from the estimates. In addition, insurance recoveries for some or all of the costs may be possible, but the liabilities recorded have not been reduced by any estimate of such recoveries. Although the timing of incurred costs, recoveries and the inclusion of provision for such costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on the Company's financial position or results of operations. Pursuant to the Toxic Substances Control Act, a federal law administered by the Environmental Protection Agency, the Company developed a comprehensive program for the use, handling, control and disposal of all polychlorinated biphenyls (PCB's) contained in electrical equipment. The future use of equipment containing PCB's will be minimized. Capacitors, transformers and other miscellaneous equipment are being purchased with a non-PCB dielectric fluid. The Company's exposure to PCB liability has been reduced through the orderly replacement of a number of such electrical devices with similar non-PCB electrical devices. An unresolved issue is whether exposure to electric and magnetic fields (EMFs) may result in adverse health effects. EMFs are produced by all devices carrying or using electricity, including transmission and distribution lines and home appliances. The Company cannot predict the effect on construction costs of electric utility facilities if EMF regulations were to be adopted. Although the Company is not the subject of any suit involving EMFs, litigation has been filed in a number of jurisdictions against a variety of defendants alleging that EMFs had an adverse effect on health. If such litigation were successful, the impact on the Company and on the electric utility industry generally could be significant. InterCoast Energy Company InterCoast Energy Company (InterCoast) is a wholly owned non-regulated subsidiary of the Company. The non-regulated activities emphasize energy-related diversification, credit quality and liquidity. InterCoast takes advantage of a core expertise in energy, participating in the energy industry through three non-regulated business groups: oil and gas (Medallion Production Company), energy services (InterCoast Energy Services Company) and financial investments (InterCoast Capital Company). Medallion Production Company (Medallion) is an independent oil and gas company based in Tulsa, Oklahoma. Medallion's oil and gas assets at December 31, 1994 and 1993 were $142.4 million and $121 million, respectively. In September 1993, Medallion acquired DKM Resources, Inc. The transaction totaled in excess of $50 million and more than doubled Medallion's oil and gas reserve base. Medallion's reserves totaled 32.1 million barrels of oil equivalent at December 31, 1994. Principal oil and gas production facilities are in Texas, Louisiana, California, Oklahoma and Colorado. InterCoast Energy Services Company (Energy Services) consolidates passive energy investment activities with actively managed energy operations through development efforts and acquisitions to provide a full spectrum of energy services. Energy Services' assets at December 31, 1994 and 1993 were $50.3 million and $48.8 million, respectively. InterCoast Power Marketing Company (IPM), a subsidiary of Energy Services, was established in September 1993 to offer wholesale power brokering and marketing services to utilities and other power supply agencies. IPM brokers wholesale electric power nationwide. In August 1994, FERC conditionally accepted IPM's request for marketer status to enable it to directly buy and sell power. FERC's acceptance of IPM's request was conditioned upon Iowa-Illinois filing an open access, comparable services electric transmission tariff within 30 days of its order. In September 1994, FERC granted IPM an extension of time in which Iowa-Illinois or MidAmerican could file such tariffs, and on or about November 10, 1994, the tariffs were filed by MidAmerican. While IPM can continue to broker power, it will not be able to market power until the MidAmerican open access, comparable services transmission tariffs become effective. Continental Power Exchange, Inc. (CPE), a subsidiary of Energy Services, was established in March 1994. CPE was formed to operate a computerized information system facilitating the real-time exchange of power in the electric industry. The services will be initially available to those who buy and sell bulk power in the next-hour bulk power market. In August 1994, the FERC issued an order disclaiming jurisdiction over CPE and its proposed National Interchange Agreement (NIA). Although the FERC disclaimed jurisdiction over CPE, it accepted for filing on January 9, 1995 the formula rates submitted in conjunction with the NIA by Central Illinois Public Service Company (CIPS), the utility sponsor of CPE. Other utilities may either apply to the FERC to use the same rate formulas as CIPS or transact business through CPE's system under rate schedules or tariffs already on file with the FERC. InterCoast Gas Marketing Company, a subsidiary of Energy Services, owns a 50 percent partnership interest in Tenaska Marketing Ventures (TMV), a natural gas marketer located in Omaha, Nebraska. TMV provides a full range of natural gas related services to industrial and utility customers, with primary emphasis on owners of natural gas-fired electric generation. Energy Services also has indirect investments in a variety of non-regulated energy production technologies including wind, solar, hydroelectric, and natural gas and coal-fueled generation. A subsidiary of Energy Services has an ownership interest in a 70 megawatt wind plant that operates in northern California and has ownership interests in four solar electric generating stations in southern California's Mojave Desert. In addition, IWG Co. 8, a subsidiary of Energy Services, has an equity interest in a hydroelectric operating and development company located in Annapolis, Maryland and is a participant in a closed-end fund created to invest in independent power projects. Energy Services also has equity investments in two developing companies which produce products and services for the electric and gas utility industries. InterCoast Capital Company (InterCoast Capital), headquartered in Dallas, Texas, manages InterCoast's financial investments. Such investments consist primarily of investment grade marketable securities. InterCoast Capital also has investments in aircraft leases, special purpose funds and real estate. InterCoast Capital's total financial investments at December 31, 1994 and 1993 were $297.1 million and $332.1 million, respectively. InterCoast Capital's marketable securities portfolio, totaling $199.5 million and $233.4 million at December 31, 1994 and 1993, respectively, focuses on energy securities consisting primarily of preferred stocks issued by utility companies. All such preferred stocks have been issued by companies having investment grade senior debt ratings by Moody's or Standard & Poor's. In addition to the preferred stocks, InterCoast Capital has investments in independently managed mutual funds. InterCoast Capital holds InterCoast's equity participations in equipment leases for passenger and freight transport aircraft. Such investments totaled $57.3 million and $56.6 million at December 31, 1994 and 1993, respectively. InterCoast Capital also had invested $2.8 million and $3.3 million at December 31, 1994 and 1993, respectively, in safe harbor leases under the provisions of the Economic Recovery Tax Act of 1981, as amended. Such safe harbor lease transactions are considered leases for income tax purposes only. InterCoast Capital has equity interests in special purpose funds that invest in venture capital and leveraged buyout opportunities totaling $34.8 million and $36 million at December 31, 1994 and 1993, respectively. InterCoast Capital has interests in two real estate partnerships totaling $2.7 million and $2.8 million at December 31, 1994 and 1993, respectively. Item 2. Properties The Company's utility properties consist of physical assets necessary and appropriate to rendering electric and gas service in its service territories. Electric property may be classified principally as distribution, transmission or generation. Gas property consists principally of distribution plant, including feeder lines to communities served from natural gas pipelines owned by others. The following table sets forth certain information with respect to the Company's accredited 1994 summer net generating capacity. All electric energy generated by the Company is 60- cycle alternating current, and the Company's generating units are steam turbine, combustion turbine, and hydro. 1994 Year Nameplate Total Summer Placed Ratings of Nameplate Net In Generators Rating Capacity Station Service in KW In KW in KW Fuel Quad-Cities 1972 207,079(1) 414,158(1) 384,750(1) Nuclear Nuclear 207,079(1) Power Station Cordova, Illinois Neal Station, 1975 159,445(2) 159,445(2) 149,350(2) Coal Unit No. 3, Sergeant Bluff, Iowa Council 1978 235,175(3) 235,175(3) 218,700(3) Coal Bluffs Station, Unit No. 3, Council Bluffs, Iowa Ottumwa 1981 134,282(4) 134,282(4) 132,368(4) Coal Station, Chillicothe, Iowa Louisa 1983 317,379(5) 317,379(5) 279,500(5) Coal Station, Fruitland, Iowa Riverside 1949 5,000 141,000 135,000 Coal-Gas Station, 1961 136,000 Bettendorf, Iowa Moline 1970 4 @ 18,000 72,000 64,000 Gas-Oil Station, 1941-42 4 @ 900 3,600 3,200 Hydro Moline, Illinois Coralville 1970 4 @ 18,000 72,000 64,000 Gas-Oil Station, Coralville, Iowa 1,549,039 1,430,868(5) (1) Company's share (25%) of jointly owned station with ComEd (operator of the station). Station has two units each having a generator nameplate rating of 828,315 KW (920,350 KVA at 0.90 power factor). (2) Company's share (29%) of jointly owned unit with Midwest Power Systems Inc. (operator of the unit) and IES Utilities, Inc. Unit has a generator nameplate rating of 549,810 KW (610,900 KVA at 0.90 power factor). (3) Company's share (32.4%) of jointly owned unit with Midwest Power Systems Inc. (operator of the unit), Cedar Falls Municipal Electric Utility, Central Iowa Power Cooperative, Corn Belt Power Cooperative, Inc., and Atlantic Municipal Utilities. Unit has a generator nameplate rating of 725,850 KW (806,500 KVA at 0.90 power factor). (4) Company's share (18.5%) of jointly owned unit with IES Utilities, Inc. (operator of the unit) and Midwest Power Systems Inc. Unit has a generator nameplate rating of 725,850 KW (806,500 KVA at 0.90 power factor). (5) Company's share (43%) of jointly owned station with Midwest Power Systems Inc., Central Iowa Power Cooperative, Interstate Power Company, the city of Geneseo, Illinois and the cities of Waverly, Harlan, Tipton and Eldridge, Iowa. Station has one unit with a generator nameplate rating of 738,090 KW (820,100 KVA at 0.90 power factor). The Company is the operator of this station. In February 1995, the Mid-Continent Area Power Pool approved an increase in the accreditation of the Louisa Generating Station from 650 MW to 675 MW effective as of June 7, 1994. This action increased the Company's summer net generating capacity from 1,430,868 KW to 1,441,618 KW. The electric system of the Company at December 31, 1994 included 305 miles of 345-kV transmission lines, 381 miles of 161-kV lines and 282 miles of 69-kV lines. Distribution lines included 13,959 miles of overhead conductor and 1,510 miles of underground conductor at December 31, 1994. The gas distribution facilities of the Company at December 31, 1994 included 4,271 miles of gas mains. Substantially all of the fixed utility property and franchises of the Company, consisting principally of electric generating plants, electric transmission and distribution lines and systems, gas feeder and distribution lines and systems and buildings, are subject to the lien of the Company's Indenture of Mortgage and Deed of Trust dated as of March 1, 1947, as amended and supplemented, relating to its First Mortgage Bonds. The Company's principal plants and properties, insofar as they constitute real estate, are owned in fee, except for minor encroachments and other inconsequential defects of title not interfering, in the opinion of counsel for the Company, with the Company's operations or use of its property. The Company's electric and gas distribution facilities and its electric transmission lines (which constitute a substantial portion of the Company's investment in physical property) are located over and under streets, alleys, highways and other public places or on property owned by others for which permits, grants, easements and licenses (deemed satisfactory but without examination of underlying land titles) have been obtained. Some of the Company's overhead lines and appurtenant equipment are attached to poles owned by others pursuant to contractual arrangements and certain transformer vaults and other property are located in buildings owned by others. Item 3. Legal Proceedings See Item 1. Business for discussion of merger, rate and environmental matters. Item 4. Submission of Matters to a Vote of Security Holders At a special meeting held December 21, 1994, shareholders of the Company approved the Merger Agreement, providing for the merger of the Company, Midwest Resources Inc. and Midwest Power Systems Inc. with and into MidAmerican. The votes cast were as follows: Number of Votes Common Preference Total For 22,480,332 396,250 22,876,582 Against 557,579 - 557,579 Abstain 343,884 6,000 349,884 Broker Non-votes 4,023,425 97,750 4,121,175 Item 4a. Executive Officers of the Registrant Age at Position Incumbent Dec. 31, 1994 Chairman, President and Chief Executive Officer Stanley J. Bright (a) 54 Vice President-Finance and Chief Financial Officer Lance E. Cooper (b) 51 Vice President Brent E. Gale (c) 43 Vice President Stephen E. Hollonbeck (d) 44 Vice President David J. Levy (e) 40 Vice President Stephen E. Shelton 47 Vice President Ronald W. Stepien (f) 48 Controller Peter E. Burks (g) 59 President and Chief Operating Officer, InterCoast Energy Company Donald C. Heppermann (h) 51 All incumbents have held their respective positions for at least five years, except where noted. Officers are elected annually by the Board of Directors. (a) Elected May 1, 1991. Prior to that time Mr. Bright was President and Chief Operating Officer (elected effective April 1, 1990) and Vice President-Finance and Chief Financial Officer (elected effective September 1, 1986). (b) Elected effective October 9, 1991. Prior to that time Mr. Cooper was Vice President-Control, Atlantic City Electric Company. (c) Elected effective January 23, 1992. Prior to that time Mr. Gale was General Counsel, Associate General Counsel, Assistant General Counsel and Attorney. (d) Elected effective April 1, 1990. Prior to that time Mr. Hollonbeck was Manager, Gas Department and Manager, Gas Supply and System Design. (e) Elected effective July 1, 1993. Prior to that time Mr. Levy was Director, Energy Services and Director, Marketing and Industrial Engineering. (f) Elected effective August 15, 1990. Prior to that time Mr. Stepien was Manager for International Parts and Service After Market Sales of General Electric Company. (g) Elected effective April 1, 1990. Prior to that time Mr. Burks was Director, Accounting. (h) Elected effective June 1, 1990. Prior to that time Mr. Heppermann was Vice President and Treasurer of Pinnacle West Capital Corporation. Previous to that position, he was Vice President-Finance and Administration with Enron Corporation. PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters Incorporated by reference to the caption "Shareholders of Record (1994)" on page 39 and "Stock Listings" on page 41 of the Company's Annual Report to Shareholders for 1994. This information is also included in Exhibit 13.A.1 to this Form 10-K. The quarterly high and low prices for the Company's Common Shares as reported on the New York Stock Exchange Composite Transactions Tape for the years 1994 and 1993 are as follows: 1994 High Low 1993 High Low 1st Quarter $24.75 $22.38 1st Quarter $22.88 $19.25 2nd Quarter 24.50 19.88 2nd Quarter 23.75 22.38 3rd Quarter 22.50 19.25 3rd Quarter 26.63 23.63 4th Quarter 20.63 18.88 4th Quarter 26.38 22.63 The $1.73 per Common Share annual dividend was paid quarterly in 1994 and 1993. Item 6. Selected Financial Data Incorporated by reference to the following captions for the years 1990-1994 on page 39 of the Company's Annual Report to Shareholders for 1994: (1) Utility Revenues (2) Net Income (3) Net Income on Common Shares (4) Common Share Statistics-Earnings per Share (5) Total Assets (6) Capitalization (7) Common Share Statistics-Annual Dividend Rate at December 31 This information is also included in Exhibit 13.A.2 to this Form 10-K. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Incorporated by reference to pages 17-21 of the Company's Annual Report to Shareholders for 1994. This information is also included in Exhibit 13.A.3 to this Form 10-K. Item 8. Financial Statements and Supplementary Data Incorporated by reference to pages 22-38 of the Company's Annual Report to Shareholders for 1994. This information is also included in Exhibit 13.A.4 to this Form 10-K. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable. PART III Item 10. Directors and Executive Officers of the Registrant Information relating to directors is incorporated by reference to pages 2-5 of the Company's Proxy Statement dated March 15, 1995. Information relating to executive officers is set forth in Part I, Item 4a. of this Annual Report of Form 10-K. Item 11. Executive Compensation Incorporated by reference to: the last paragraph of page 4, page 6 -- "Executive Compensation" and pages 7 and 8 -- "Pension Plan", "Long-Term Incentive Plan (LTIP) Awards Table", "Supplemental Retirement Plan for Designated Officers" and "Severance Plan" of the Company's Proxy Statement dated March 15, 1995. Item 12. Principal Holders of Voting Securities and Security Ownership of Management Incorporated by reference to pages 1 and 5 of the Company's Proxy Statement dated March 15, 1995. Item 13. Certain Relationships and Related Transactions NONE PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a)(1) Financial Statements The following financial statements (including the notes thereto) and the related audit reports, incorporated herein by reference, are included in the Company's 1994 Annual Report to Shareholders (except as noted): Page No. in 1994 Annual Report to Share- holders 22 Consolidated statements of income and retained earnings for the three years ended December 31, 1994 23,24 Consolidated balance sheets and statements of capitalization as of December 31, 1994 and 1993 25 Consolidated statements of cash flows for the three years ended December 31, 1994 26-37 Notes to consolidated financial statements 38 Independent Auditors' Report - 1994 and 1993 Report of Independent Public Accountants - 1992 (included in this Report on Form 10-K at page 33) (2) Financial statement schedule The following schedule is included herein: Page No. of this Annual Report on Form 10-K 34 Independent Auditors' Report - 1994 and 1993 35 Report of Independent Public Accountants - 1992 36 II Valuation and qualifying accounts for the years ended December 31, 1994, 1993 and 1992. (3) Exhibits See Exhibit Index on pages 39 through 46. (b) A report on Form 8-K dated December 21, 1994 was filed. The report included under "Item 5 Other Events" information related to the special meeting held December 21, 1994 at which the shareholders of the Company approved the merger of the Company, Midwest Resources Inc. and Midwest Power Systems Inc. with and into MidAmerican Energy Company. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Iowa-Illinois Gas and Electric Company: We have audited the consolidated balance sheet and statement of capitalization of Iowa-Illinois Gas and Electric Company (an Illinois corporation) and Subsidiary Company as of December 31, 1992, and the related consolidated statements of income, retained earnings and cash flows for the year 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 audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Iowa- Illinois Gas and Electric Company and Subsidiary Company as of December 31, 1992, and the results of their operations and their cash flows for the year then ended, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Chicago, Illinois January 28, 1993 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Iowa-Illinois Gas and Electric Company: We have audited the consolidated financial statements of Iowa-Illinois Gas and Electric Company as of December 31, 1994 and 1993 and for each of the two years in the period ended December 31, 1994, and have issued our report thereon dated January 25, 1995; such financial statements and report are included in your 1994 Annual Report to Shareholders and are incorporated herein by reference. Our audits also included the financial statement schedule of Iowa-Illinois Gas and Electric Company as of December 31, 1994 and 1993 and for each of the two years in the period ended December 31, 1994, listed in Item 14. The financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. Deloitte & Touche LLP Davenport, Iowa January 25, 1995 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Iowa-Illinois Gas and Electric Company: We have audited in accordance with generally accepted auditing standards, the consolidated balance sheet and statement of capitalization of Iowa-Illinois Gas and Electric Company and Subsidiary Company as of December 31, 1992, and the related consolidated statements of income, retained earnings and cash flows for the year then ended, included in the Company's annual report to shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated January 28, 1993. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in Item 14(a)(2) as of December 31, 1992, and for the year then ended is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This financial statement schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Chicago, Illinois January 28, 1993
SCHEDULE II IOWA-ILLINOIS GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANY VALUATION AND QUALIFYING ACCOUNTS Column A Column B Column C Column D Column E Balance Additions Balance Beginning Charged to End of Description of Period Income Deductions Period YEAR ENDED DECEMBER 31, 1994 ACCUMULATED PROVISION DEDUCTED FROM APPLICABLE ASSETS: Uncollectible Accounts $1,164,997 $1,504,048 ($1,504,040) $1,165,005 ACCUMULATED PROVISIONS NOT DEDUCTED FROM ASSETS: Property Insurance 2,561,285 200,000 (536,950) 2,224,335 Injuries and Damages 974,539 473,452 (444,168) 1,003,823 YEAR ENDED DECEMBER 31, 1993 ACCUMULATED PROVISION DEDUCTED FROM APPLICABLE ASSETS: Uncollectible Accounts $1,171,314 $882,951 ($889,268) $1,164,997 ACCUMULATED PROVISIONS NOT DEDUCTED FROM ASSETS: Property Insurance 2,426,440 134,845 2,561,285 Injuries and Damages 741,663 591,998 (359,122) 974,539 YEAR ENDED DECEMBER 31, 1992 ACCUMULATED PROVISION DEDUCTED FROM APPLICABLE ASSETS: Uncollectible Accounts $1,149,069 $825,283 ($803,038) $1,171,314 ACCUMULATED PROVISIONS NOT DEDUCTED FROM ASSETS: Property Insurance 2,605,000 43,000 (221,560) 2,426,440 Injuries and Damages 795,943 671,860 (726,140) 741,663
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. IOWA-ILLINOIS GAS AND ELECTRIC COMPANY March 22, 1995 By L. E. Cooper L. E. Cooper Vice President-Finance and CFO Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title Date S. J. Bright Chairman, President, Chief S. J. Bright Executive Officer and Director (Principal executive officer) March 22, 1995 L. E. Cooper Vice President-Finance, Chief L. E. Cooper Financial Officer and Director (Principal financial officer) March 22, 1995 P. E. Burks Controller March 22, 1995 P. E. Burks (Principal accounting officer) John W. Colloton Director March 22, 1995 John W. Colloton Frank S. Cottrell Director March 22, 1995 Frank S. Cottrell William C. Fletcher Director March 22, 1995 William C. Fletcher Mel Foster, Jr. Director March 22, 1995 Mel Foster, Jr. Signature Title Date Nancy L. Seifert Director March 22, 1995 Nancy L. Seifert S. E. Shelton Director March 22, 1995 S. E. Shelton W. Scott Tinsman Director March 22, 1995 W. Scott Tinsman L. L. Woodruff Director March 22, 1995 L. L. Woodruff EXHIBIT INDEX EXHIBITS FILED HEREWITH 13.A.1 "Shareholders of Record (1994)" appearing on page 39 and "Stock Listing" appearing on page 41 of the Company's Annual Report to Shareholders for 1994, incorporated by reference into Item 5 of this Form 10-K. 13.A.2 "Utility Revenues," "Net Income," "Net Income on Common Shares," "Common Share Statistics--Earnings per Share," "Total Assets," "Capitalization" and "Common Share Statistics--Annual Dividend Rate at December 31" for the years 1990-1994, appearing on page 39 of the Company's Annual Report to Shareholders for 1994, incorporated by reference into Item 6 of this Form 10-K. 13.A.3 "Management's Discussion and Analysis of Financial Condition and Results of Operations," appearing on pages 17-21 of the Company's Annual Report to Shareholders for 1994, incorporated by reference into Item 7 of this Form 10-K. 13.A.4 "Financial Statements and Supplementary Data," appearing on pages 22-38 of the Company's Annual Report to Shareholders for 1994, incorporated by reference into Items 1(b), 8 and 14(a)(1) of this Form 10-K. 21 Subsidiaries of the Registrant. 23.A Consent of Deloitte & Touche LLP. 23.B Consent of Arthur Andersen LLP. 27 Financial Data Schedule. EXHIBITS INCORPORATED BY REFERENCE The following Exhibits previously filed with the Commission are incorporated herein by reference. The file number for the Company's Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q is 1-3573. Ex. File No. or Previous No. Description Ex. No. Description of Document 2 Registration 2(a) Agreement and Plan of Merger Statement dated as of July 26, 1994 as on Form S-4 amended and restated as of (33-56153) of September 27, 1994 among Iowa- MidAmerican Illinois, Midwest Resources, Energy Co. Inc., an Iowa corporation, and Midwest Power Systems, an Iowa corporation and a subsidiary of Resources, and a newly-formed corporation MidAmerican Energy Company. 3.A Form 10-K 3.A First Restated Articles of 1993 Incorporation of Iowa-Illinois Gas and Electric Company. 3.B Form 10-Q 3.A Article Eleven of the First 6/30/94 Restated Articles of Incorporation of Iowa-Illinois Gas and Electric Company. 3.C Form 10-K 3.B By-laws as amended through April 1993 25, 1991. 4.B.1 2-6922 7B Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947. 4.B.2 2-6922 7C Supplemental Indenture dated as of March 1, 1947. 4.B.3 2-8112 7B Second Supplemental Indenture dated as of October 1, 1949. 4.B.4 2-9990 4.04 Third Supplemental Indenture dated as of January 15, 1953. 4.B.5 2-62330 2.03E Resignation and appointment of successor Individual Trustee. 4.B.6 2-17786 2.06 Fourth Supplemental Indenture dated as of April 15, 1960. 4.B.7 2-26675 2.07 Fifth Supplemental Indenture dated as of May 1, 1961. 4.B.8 2-28806 2.08 Sixth Supplemental Indenture dated as of July 1, 1967. 4.B.9 2-34089 2.10 Seventh Supplemental Indenture dated as of April 1, 1969. 4.B.10 2-38102 2.10 Eighth Supplemental Indenture dated as of August 15, 1969. 4.B.11 2-38102 2.12 Ninth Supplemental Indenture dated as of September 1, 1970. 4.B.12 2-45994 2.04L Resignation and appointment of successor Individual Trustee. 4.B.13 2-53814 2.03M.2 Tenth Supplemental Indenture dated as of June 15, 1975. 4.B.14 2-55527 2.03N.1 Eleventh Supplemental Indenture dated as of March 15, 1976. 4.B.15 2-57912 2.03O.1 Twelfth Supplemental Indenture dated as of January 15, 1977. 4.B.16 2-58838 2.03P Thirteenth Supplemental Indenture dated as of October 1, 1977. 4.B.17 2-62330 2.03Q.1 Fourteenth Supplemental Indenture dated as of September 1, 1979. 4.B.18 2-66779 2.03R Fifteenth Supplemental Indenture dated as of July 15, 1979. 4.B.19 2-66779 2.03S Sixteenth Supplemental Indenture dated as of January 15, 1980. 4.B.20 2-68600 2.03T Seventeenth Supplemental Indenture dated as of June 15, 1980. 4.B.21 Form 10-K 4.B.21 Eighteenth Supplemental Indenture 1980 dated as of February 15, 1981. 4.B.22 Form 10-K 4.B.22 Nineteenth Supplemental Indenture 1981 dated as of October 1, 1981. 4.B.23 Form 10-Q 4.B.23 Twentieth Supplemental Indenture 6/30/82 dated as of May 1, 1982. 4.B.24 Form 10-Q 4.B.24 Twenty-First Supplemental 6/30/82 Indenture dated as of July 1, 1982. 4.B.25 Form 10-K 4.B.25 Twenty-Second Supplemental 1983 Indenture dated as of February 15, 1984. 4.B.26 Form 10-K 4.B.26 Twenty-Third Supplemental 1984 Indenture dated as of November 1, 1984. 4.B.27 Form 10-Q 4.B.27 Twenty-Fourth Supplemental 9/30/85 Indenture dated as of September 1, 1985. 4.B.28 Form 10-Q 4.B.28 Twenty-Fifth Supplemental 9/30/86 Indenture dated as of September 15, 1986. 4.B.29 Form 10-K 4.B.29 Twenty-Sixth Supplemental 1986 Indenture dated as of February 15, 1987. 4.B.30 Reg. No. 4.B.30 Resignation and Appointment of 33-39211 successor Individual Trustee. 4.B.31 Form 8-K 4.31.A Twenty-Seventh Supplemental dated Indenture dated as of October 1, 10/1/91 1991. 4.B.32 Form 8-K 4.31.B Twenty-Eighth Supplemental dated Indenture dated as of May 15, 5/21/92 1992. 4.B.33 Form 8-K 4.32.A Twenty-Ninth Supplemental dated Indenture dated as of March 15, 3/24/93 1993. 4.B.34 Form 8-K 4.34.A Thirtieth Supplemental Indenture dated dated as of October 1, 1993. 10/7/93 10.A.1 2-62331 5.01A Quad-Cities Station Ownership Agreement dated as of March 17, 1967 between the Company and Commonwealth Edison Company. 10.A.2 2-45994 5.01B Amendment No. 1 dated as of April 20, 1972 to Quad-Cities Station Ownership Agreement and Quad- Cities Operating Agreement. 10.A.3 2-45994 5.02 Quad-Cities Operating Agreement dated as of November 24, 1967 between the Company and Commonwealth Edison Company. 10.B 2-45994 5.03 Agreement dated February 2, 1971 re Unit 3 George Neal Generating Station between the Company, Iowa Power and Light Company, Iowa Southern Utilities Company and Iowa Public Service Company. 10.C 2-45994 5.04 Transmission Facilities Agreement dated July 28, 1972 between the Company, Iowa Power and Light Company, Iowa Southern Utilities Co. and Iowa Public Service Co. 10.D 2-45994 5.07 Financing Agreement dated as of April 15, 1972 among the Company, The First National Bank of Saint Paul, First National Bank of Muscatine, the institutions named in Section 2 thereof and United States Trust Company of New York. 10.E Form 10-K 10.E Mid-Continent Area Power Pool 1981 Agreement as amended through Amendment No. 14 effective May 1, 1982. 10.F.1 2-49376 5.08 Agreement dated July 31, 1973 re Unit 3 Council Bluffs Generating Station between the Company, Cedar Falls Municipal Electric Utility, Central Iowa Power Cooperative, Inc., Corn Belt Power Co-operative, Inc., Eastern Iowa Light and Power Cooperative Inc. and Iowa Power and Light Co. 10.F.2 2-57912 5.08B Amendment No. 1 to Council Bluffs Generating Station Unit 3 Agree- ment, dated January 31, 1975. 10.F.3 2-57912 5.08C Amendment No. 2 to Council Bluffs Generating Station Unit 3 Agree- ment, dated September 5, 1975. 10.G 2-53814 5.09 Agreement dated April 16, 1975 re Unit 1 Ottumwa Generating Station between the Company, Iowa Power and Light Company, Iowa Southern Utilities Company and Iowa Public Service Company. 10.H.1 2-53814 5.10 Ownership Agreement dated as of August 15, 1974 re Units 1 and 2 Carroll County Station among the Company, Commonwealth Edison Co. and Interstate Power Company. 10.H.2 2-53814 5.11 Operating Agreement dated as of August 15, 1974 re Units 1 and 2 Carroll County Station among the Company, Commonwealth Edison Co. and Interstate Power Company. 10.I.1 2-58838 5.12 Agreement dated October 4, 1977 re Unit 1 Louisa Generating Station among the Company, Iowa Power and Light Company, Iowa Public Service Company, Eastern Iowa Light and Power Cooperative and City of Tipton. 10.I.2 Form 10-K 10.J.2 Amendment No. 1 to Unit 1 Louisa 1980 Generating Station Agreement, dated May 23, 1980. 10.I.3 Form 10-K 10.I.3 Amendment No. 2 to Unit 1 Louisa 1982 Generating Station Agreement, dated April 26, 1982. 10.I.4 Form 10-K 10.I.4 Amendment No. 3 to Unit 1 Louisa 1982 Generating Station Agreement, dated February 2, 1983. 10.I.5 Form 10-K 10.I.5 Amendment No. 4 to Unit 1 Louisa 1983 Generating Station Agreement, dated May 26, 1983. 10.I.6 Form 10-K 10.I.6 Amendment No. 5 to Unit 1 Louisa 1983 Generating Station Agreement dated October 11, 1983. 10.I.7 Form 10-K 10.I.7 Amendment No. 6 to Unit 1 Louisa 1985 Generating Station Agreement dated May 29, 1985. 10.J Form 8-K II Rights Agreement dated as of dated February 25, 1992 between the 2/26/92 Company and First Chicago Trust Co. of New York, as Rights Agent. 10.K.1* Form 10-K 10.K.1 Severance Plan In The Event Of A 1993 Change In Control, as amended as of July 1, 1993. 10.K.2* Form 10-K 10.K.2 Supplemental Retirement Plan for 1993 Principal Officers, as amended as of July 1, 1993. 10.K.3* Form 10-K 10.K.2 Compensation Deferral Plan for 1993 Principal Officers, as amended as of July 1, 1993. 10.K.4* Form 10-K 10.K.4 Board of Directors' Compensation 1992 Deferral Plan. 10.K.5* Form 10-K 10.K.5 Trust Agreement. 1992 10.K.6* Form 10-K 10.K.6 Key Employee Sustained 1993 Performance Plan. 10.L.1 Form 10-K 10.L.1 Employee Stock Purchase Plan. 1992 10.M Registration 2(a) Agreement and Plan of Merger Statement dated as of July 26, 1994 as on Form S-4 amended and restated as of (33-56153) of September 27, 1994 among Iowa- MidAmerican Illinois, Midwest Resources, Energy Co. Inc., an Iowa corporation, and Midwest Power Systems, an Iowa corporation and a subsidiary of Resources, and a newly-formed corporation MidAmerican Energy Company. * Compensatory Plan or Arrangement for Directors or Executive Officers of the Company. EX-13.A.1 2 Exhibit 13.A.1 Iowa-Illinois Gas and Electric Company 1994 Shareholders of Record Common 22,839 Preferred and Preference 3 Stock Listings: Iowa-Illinois' common stock is listed on the New York Stock Exchange and on the Chicago Stock Exchange under the ticker symbol "IWG." Preference shares are traded in the over-the- counter market. Many daily newspapers carry quotes on the common stock. EX-13.A.2 3 Exhibit 13.A.2 Iowa-Illinois Gas and Electric Company Selected Financial Data (Dollars in thousands, except per share amounts) (1) Utility Revenues 1994: 555,084 1993: 545,414 1992: 497,534 1991: 512,537 1990: 511,672 (2) Net Income 1994: 59,136 1993: 59,228 1992: 45,433 1991: 54,367 1990: 55,490 (3) Net Income on Common Shares 1994: 54,065 1993: 54,233 1992: 40,404 1991: 50,020 1990: 53,490 (4) Common Share Statistics-Earnings per Share 1994: $ 1.83 1993: $ 1.85 1992: $ 1.45 1991: $ 1.86 1990: $ 1.99 (5) Total Assets 1994: 1,849,899 1993: 1,783,070 1992: 1,648,450 1991: 1,520,049 1990: 1,404,162 (6) Capitalization First Mortgage Bonds 1994: 323,745 1993: 323,625 1992: 293,727 1991: 296,466 1990: 293,757 Exhibit 13.A.2 Iowa-Illinois Gas and Electric Company Selected Financial Data (Dollars in thousands, except per share amounts) Other Long-Term Debt 1994: 48,133 1993: 48,275 1992: 37,453 1991: 37,682 1990: 37,910 Long-Term Debt of InterCoast Energy Company 1994: 239,000 1993: 242,500 1992: 257,000 1991: 215,100 1990: 159,000 Preferred/Preference -- nonredeemable 1994: - 1993: 19,829 1992: 19,829 1991: 19,829 1990: 19,829 Preferred/Preference -- redeemable 1994: 50,000 1993: 50,000 1992: 48,625 1991: 49,200 1990: 9,775 Common Equity 1994: 502,242 1993: 499,412 1992: 495,582 1991: 443,608 1990: 436,855 Total 1994: 1,163,120 1993: 1,183,641 1992: 1,152,216 1991: 1,061,885 1990: 957,126 (7) Common Share Statistics-Annual Dividend Rate at December 31 1994: $ 1.73 1993: $ 1.73 1992: $ 1.73 1991: $ 1.71 1990: $ 1.67 EX-13.A.3 4 Exhibit 13.A.3 Iowa-Illinois Gas and Electric Company MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION The operating results and financial condition of Iowa- Illinois Gas and Electric Company (the Company) reflect the Company's regulated utility operations and the operations of its wholly owned non-regulated subsidiary, InterCoast Energy Company (InterCoast). The Company's regulated utility operations are concerned with the generation, transmission and distribution of electric energy and the purchase, sale and transportation of natural gas. The business strategy of InterCoast is focused on areas closely related to the Company's core electric and gas utility businesses. These activities are: oil and natural gas; energy services; and financial investments. OVERVIEW Contributions to consolidated earnings per share for the last three years are: 1994 1993 1992 Utility operations....... $1.52 $1.42 $1.11 InterCoast............... .31 .43 .34 Earnings per share....... 1.83 1.85 1.45 The utility's ratio of earnings to fixed charges (pretax), excluding the income of InterCoast, was 3.93 in 1994 and 3.54 in 1993. The return on average consolidated common equity was 10.8% for 1994 and 10.9% for 1993. In January 1995, the Board of Directors declared the quarterly dividend of 43.25 cents per common share, the rate established in January 1992. RESULTS OF OPERATIONS Operating Revenues Electric revenues increased in 1994 compared to 1993 primarily due to higher retail rates, increased retail unit sales reflecting increases in commercial and industrial usage and increased fuel and energy cost billings to retail customers. These increases were partially offset by lower sales for resale. Variations in fuel and energy cost billings reflect corresponding changes in fuel and purchased energy costs from levels included in base rates and, thus, do not affect net income. On July 26, 1993, the Company implemented temporary electric rates in its Iowa jurisdiction designed to increase annual electric revenues by $6.8 million. The Iowa Utilities Board (IUB) approved final rates at the $6.8 million increase level, which became effective April 15, 1994. On July 28, 1993, an annual electric rate increase in Illinois of $9.6 million became effective following Illinois Commerce Commission (ICC) approval. On January 15, 1994, an additional annual electric increase of $230,000 related to the increase in the federal corporate income tax rate became effective on rehearing. Also on rehearing, the ICC approved a rate rider that permits the Company to recover costs of investigation, remediation and litigation relating to former manufactured gas plant sites. In addition, on January 1, 1994, nuclear decommissioning costs included in Illinois customer billings through a rate rider were increased by $1.2 million annually. The previously mentioned rate increases were partially offset by a $3.2 million decrease in revenues in 1994 reflecting the expiration of the Company's Louisa Phase-In Clause (LPIC) on June 30, 1993. Increased revenues collected through rate riders relating to former manufactured gas plant sites and nuclear decommissioning and the decreased revenues from expiration of the LPIC did not affect net income due to a corresponding increase or decrease in costs. Electric revenues increased in 1993 compared to 1992 primarily due to increased revenues reflecting higher retail rates, increased retail sales volumes reflecting more typical temperatures (approximately 40% warmer in 1993 than 1992) and increased sales for resale. The Company began billing higher electric rates of $7.5 million on an annual basis in Iowa in July 1992. Effective January 1, 1993, the IUB approved a permanent annual increase in that rate proceeding of $10.4 million, including $4.8 million related to nuclear decommissioning costs, which did not affect net income due to a corresponding increase in expense. (See Provision for Depreciation.) As previously mentioned, rates were also increased in July of 1993 in Iowa and Illinois. These rate increases were partially offset by a $3.3 million decrease in revenues in 1993 reflecting the expiration of the LPIC on June 30, 1993. In addition, the Company began billing its customers for the costs of electric energy-efficiency plans in Illinois in April of 1993. Such billings of approximately $700,000 did not affect net income due to a corresponding amortization of previously deferred costs. Partially offsetting these increases were lower fuel and energy cost billings to retail customers. The changes in electric revenues are shown below: Revenue Increase (Decrease) from Prior Year 1994 1993 (In thousands) Change in Retail Unit Sales..... $ 6,900 $ 7,900 Change in Retail Fuel and Energy Adjustment Clause Billings.... 3,400 ( 600) Change in Sales for Resale...... ( 1,800) 5,900 Change Due to the Effect of Higher Retail Rates........... 8,900 12,700 $ 17,400 $ 25,900 Gas revenues decreased in 1994 compared to 1993. The principal factors contributing to the decrease were decreased sales volumes reflecting temperatures that were 7% warmer than 1993 and lower purchased gas cost billings. Higher rates in Illinois, as discussed below, were partially offset by a decrease of $1.1 million in energy-efficiency plan billings. Changes in energy-efficiency plan billings do not affect net income due to corresponding changes in cost. Variations in purchased gas cost billings reflect corresponding changes in cost of gas sold and, thus, do not affect net income. On July 28, 1993, an annual gas rate increase in Illinois of $2 million became effective following ICC approval. On January 15, 1994, an additional annual gas increase of $49,000 related to the increase in the federal corporate income tax rate became effective on rehearing. As noted previously, also on rehearing, the ICC approved a rate rider that permits the Company to recover costs of investigation, remediation and litigation relating to former manufactured gas plant sites. Gas revenues increased in 1993 compared to 1992. The principal factors contributing to the increase were increased sales volumes reflecting temperatures that were 10% colder than 1992, higher purchased gas cost billings and higher rates. In addition to the higher rates in Illinois, as discussed previously, the Company began billing higher gas rates of $4.7 million on an annual basis in Iowa in July 1992. Effective January 1, 1993, the IUB approved a permanent annual increase of $5.4 million. In addition, the Company began billing its customers for the costs of gas energy-efficiency plans in Illinois in April of 1993. Such billings of approximately $1.1 million did not affect net income due to a corresponding amortization of previously deferred costs. The changes in gas revenues are shown below: Revenue Increase (Decrease) from Prior Year 1994 1993 (In thousands) Change in Purchased Gas Adjustment Clause Billings.... $( 400) $ 8,600 Change in Unit Sales............ (7,700) 9,000 Change Due to the Effect of Higher Rates.................. 400 4,400 $(7,700) $22,000 Operation Changes in the cost of electric fuel, energy and capacity reflect fluctuations in generation mix, fuel cost and energy and capacity purchases. Increased fuel, energy and capacity costs in 1994 compared to 1993 are primarily due to increased average unit fuel and energy costs. Increased fuel, energy and capacity costs in 1993 compared to 1992 are primarily due to increased sales. Cost of gas sold decreased in 1994 compared to 1993 primarily due to decreased purchased gas costs from suppliers and lower gas storage withdrawals reflecting warmer temperatures in 1994. Substantially offsetting these decreases were increased pipeline demand and transition costs. Cost of gas sold increased in 1993 compared to 1992 primarily due to increased purchased gas costs from suppliers and higher gas purchases reflecting colder temperatures in 1993. Other operation and maintenance increased in 1994 compared to 1993 and in 1993 compared to 1992 primarily due to increased costs at the Quad-Cities Nuclear Power Station (Quad-Cities Station). In January 1994, the Company was advised by ComEd, operator and 75 percent owner of the Quad-Cities Station, that the Nuclear Regulatory Commission (NRC) had placed the station on its list of plants with adverse performance trends. The NRC concerns with the Quad-Cities Station include deficiencies in the condition of certain station equipment and the effectiveness of the operators of the units in identifying and responding to certain operational problems. ComEd has provided written and verbal responses to the NRC and is working to resolve the concerns. As of February 1995, the Quad-Cities Station remains on the list of plants with adverse performance trends. The Company anticipates that it will need to make operating and capital expenditures in future years in connection with the resolution of the noted deficiencies at the Quad-Cities Station. In addition, increases were experienced in other operation and maintenance expense in 1994 related to costs associated with the merger with Midwest Resources Inc. and an ice storm in the Quad- Cities service area. The increase in other operation expense in 1993 also reflects adoption of Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions, and amortization of previously deferred costs of energy-efficiency programs. Provision for Depreciation The provision for depreciation increased in 1994 compared to 1993 and in 1993 compared to 1992 primarily due to a greater provision for nuclear decommissioning, consistent with current ratemaking treatment, and greater utility plant investment. Depreciation and Equity Funds Recovered Under Louisa Phase-In Clause The decreases in the amount being recovered under the LPIC in 1994 compared to 1993 and in 1993 compared to 1992 reflect the expiration of the LPIC on June 30, 1993. Operating Income Taxes Income tax expense increased in 1994 compared to 1993 and in 1993 compared to 1992 primarily due to higher taxable income. The Omnibus Budget Reconciliation Act of 1993 (the Act) was signed into law on August 10, 1993. In accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, which the Company adopted January 1, 1993, the adjustments required as a result of the increase in income tax rates included in the Act were recorded in the third quarter of 1993. The primary financial effect of the new tax law was an increase in net regulatory assets and deferred income tax liabilities of approximately $8 million. Oil and Gas Revenues of InterCoast Energy Company Oil and gas revenues of InterCoast increased in 1994 compared to 1993 primarily due to higher production volumes reflecting additional acquired reserves and successful drilling results, partially offset by lower oil and gas prices. In the event that 1995 oil and gas prices are below such prices for 1994, oil and gas operating income could be reduced from 1994 levels. Oil and gas revenues of InterCoast increased in 1993 compared to 1992 primarily due to higher production volumes reflecting additional acquired reserves, successful drilling results and higher gas prices, partially offset by lower oil prices. Other Income of InterCoast Energy Company Other income of InterCoast increased in 1994 compared to 1993 primarily due to greater income from special-purpose funds and increased gains on the disposition of direct holdings in common stock, substantially offset by lower energy project income. Expenses of InterCoast Energy Company Expenses of InterCoast increased in 1994 compared to 1993 primarily due to greater oil and gas expenses, increased interest expense reflecting higher rates and greater other operating expenses. Expenses of InterCoast increased in 1993 compared to 1992 primarily due to greater oil and gas expenses, increased interest expense reflecting InterCoast's additional long-term debt outstanding and greater other operating expenses. Utility Interest Charges Decreased interest on long-term debt in 1994 compared to 1993 and in 1993 compared to 1992 reflects refinancing of several series of long-term debt at lower interest rates. Allowance for Funds Used During Construction The increase in the total allowance for funds used during construction (AFUDC) for 1994 compared to 1993 is primarily due to a higher AFUDC rate, 5.6% compared to 3.3%, and higher construction work in progress balances. Other Matters On December 21, 1994, the shareholders of the Company, Midwest Resources Inc. and Midwest Power Systems Inc. approved a strategic merger of equals to form MidAmerican Energy Company (MidAmerican). MidAmerican will be structured as a utility with the Company, Midwest Resources Inc. and Midwest Power Systems Inc. being merged into the new company. Pursuant to the terms of the merger agreement, Midwest Resources' common shareholders will receive one share of MidAmerican for each Midwest share and the Company's shareholders will receive 1.47 shares of MidAmerican for each Company share. At the effective date of the merger, each series of the Company's preference shares then outstanding will be converted into an equal number of shares of MidAmerican preferred stock. Approval of the merger is required from the following regulatory agencies: the IUB, the ICC and the Federal Energy Regulatory Commission (FERC). The NRC approval for the transfer of the Quad-Cities Station license to MidAmerican must also be obtained. Applications for approval of the merger were filed with the IUB and the ICC in October 1994. An application for approval of the merger was filed with the FERC in November 1994. At the same time, consistent with FERC policy, the Company filed open access, comparable services tariffs with the FERC, which tariffs will allow others to use MidAmerican's electric transmission system in a manner comparable to its use by MidAmerican. In January 1995, the IUB issued an order approving the merger. The ICC and FERC are expected to issue orders on the merger by mid 1995. A filing with the NRC was made in November 1994. Completion of the merger is expected in the second half of 1995. The formation of MidAmerican will create a larger, stronger company, which will be better positioned to grow and succeed within the emerging competitive utility industry. In this new environment, successful utilities will need financial strength, market leadership and low costs. The merger will address these elements. The Company expects that competitive pressures in the electric industry initially will be focused on industrial sales. While about 25% of Iowa-Illinois' electric revenues come from industrial customers, only about 20% of MidAmerican's electric revenues will come from this customer group. The industrial rates of both Iowa-Illinois and Midwest Resources are well below national and regional averages, providing MidAmerican with a strong competitive position in the industrial sector. MidAmerican also will be well-positioned for competition in the natural gas industry, with low-cost reliable gas supply portfolios and multiple pipeline suppliers. The residential gas rates of both companies are well below national averages. The merger will provide opportunities to achieve significant long-term benefits for shareholders, customers, employees and the communities served by the two companies. These benefits are: increased size and stability, better use of generating capacity, coordination of dispatch, savings on purchases, coordination of non-regulated businesses and reduced administrative costs. It is estimated the merger will result in savings of nearly $500 million over 10 years. Iowa-Illinois and Midwest Resources have announced plans to reduce their combined work forces by a total of approximately 15 percent in conjunction with development of a restructured organization to be effective at the completion of the merger. As part of these reductions, the companies are offering incentive retirement and severance programs to employees. The companies estimate these programs will reduce 1995 after-tax earnings of MidAmerican by approximately $9 million, or 9 cents a share, if the merger is consummated in 1995. Since utility properties are accounted for, and reflected in the cost of service on which utility rates are based, at historical cost, the potentially material effect of inflation and changing prices is not reflected in the consolidated financial statements. The strategy of the non-regulated business is focused on areas that relate closely to the Company's core utility businesses: oil and natural gas; energy services; and financial investments. Changes in the electric utility industry may provide some new opportunities for InterCoast. Continental Power Exchange Inc. (CPE), a subsidiary of InterCoast, was established in March 1994. CPE was formed to operate an information system facilitating the real-time exchange of power in the electric industry. The services will be initially available to those who buy and sell bulk power in the next-hour bulk power market. LIQUIDITY AND CAPITAL RESOURCES In 1994, 1993 and 1992, net cash from utility operating activities, after dividends, was $67 million, $68 million and $30 million, respectively. Utility construction expenditures totaled $80.3 million in 1994. The Company's current utility construction program forecast calls for expenditures of $84.3 million in 1995. In excess of 75% of these expenditures are expected to be met from cash generated from operations. The Company's utility capital requirements for the years 1995-1999 include budgeted construction expenditures of $299.9 million, expected contributions to nuclear decommissioning trust funds of $43.2 million and maturities, sinking funds and redemptions related to long-term debt of $98.3 million. The estimated 1995-1999 construction expenditures include $72.1 million for electric production construction (principally at the Quad-Cities Station), $58.8 million for electric transmission and distribution system construction, $45.0 million for nuclear fuel, $90.4 million for gas plant construction and $33.6 million for general plant construction, all of which are expected to be met by cash generated from operations. The Company has a Dividend Reinvestment and Share Purchase Plan. Effective with the June 1994 dividend, this Plan provides for the issuance of new shares with dividends reinvested and optional cash investments by shareholders. The Company's budgeted construction expenditures do not include any amounts that may be required to pay the Company's share of the cost of replacing certain stainless steel piping at the Quad-Cities Station. Although such expenditures could be required, they are not expected to be required. Accumulated deferred income taxes at December 31, 1994 include offsetting benefits related to federal and state Alternative Minimum Tax (AMT) in the amounts of $29.2 million in federal AMT and $5.4 million in state AMT. The AMT credits may be carried forward indefinitely to offset future regular tax liabilities. On December 15, 1994, the Company redeemed all of its outstanding preferred shares. The redemption was made at a premium, which resulted in a charge to net income on common shares of $312,000. In January 1995, $12.75 million of floating rate Pollution Control Refunding Revenue Bonds, due 2025, were issued. Proceeds from this financing will be used to redeem $12.75 million of collateralized Pollution Control Revenue Bonds, 5.8% Series, due 2007. In 1993, the Company sold $176.1 million principal amount of First Mortgage Bonds and Pollution Control Obligations to refinance $160.2 million principal amount of First Mortgage Bonds, Pollution Control Obligations and short-term debt. In addition, the Company sold $10.0 million of Preference Stock principally to refinance $8.6 million of Preference Stock. The balance of such proceeds was used for general corporate purposes. The aggregate amounts of maturities and cash sinking fund requirements for long-term debt outstanding at December 31, 1994 are $145,000 for 1995 and $98.2 million for the years 1996-1999. At December 31, 1994, the Company had bank lines of credit of $72.8 million to provide short-term financing for its utility operations. All such lines of credit were unused. The Company generally maintains compensating balances under its bank line of credit arrangements. The Company has regulatory authority to incur up to $100 million of short-term debt for its utility operations. At December 31, 1994, the Company had $67.5 million of outstanding short-term commercial paper notes. The capitalization ratios for the Company's utility businesses (including short-term debt, long-term debt maturing within one year and preference shares redeemable within one year) at the end of each of the last three years were as follows: December 31, 1994 1993 1992 Long-term debt.............. 43.9% 45.0% 40.8% Short-term debt............. 8.0 3.7 6.4 Total debt............... 51.9 48.7 47.2 Preferred and Preference stock equity.............. 5.9 8.5 8.4 Common stock equity......... 42.2 42.8 44.4 100.0% 100.0% 100.0% The Company's selections of long-term financing alternatives are affected by provisions of its Mortgage relating to its First Mortgage Bonds. Under the Mortgage, the Company may issue First Mortgage Bonds on the basis of 60% of available net property additions, provided net earnings available for interest (before income taxes) are at least two times annual interest charges on First Mortgage Bonds and Prior Lien Bonds then to be outstanding. Not more than 10% of such net earnings can be derived from certain sources, principally non-operating income (which includes AFUDC). As of December 31, 1994, available net property additions would have permitted the issuance of at least $240 million principal amount of additional First Mortgage Bonds. Under the Articles of Incorporation, the Company may not become liable for debt (other than short-term indebtedness not exceeding 10% of the sum of items (a) and (b) below, or indebtedness issued for purposes of refunding, reacquiring or retiring certain securities) if, after becoming liable, the total principal amount of all indebtedness (excluding short-term indebtedness, as defined above) would exceed 65% of the aggregate of (a) the total principal amount of all long-term indebtedness and (b) the capital and surplus of the Company. The Company's First Mortgage Bond ratings as assigned by Duff & Phelps Inc., Fitch Investors' Service, Moody's Investor Services Inc. and Standard & Poor's Corporation are AA-, AA, Aa3 and AA-, respectively. In April 1992, the FERC issued Order No. 636, directing a restructuring by interstate pipeline companies for their natural gas sales and transportation services. The FERC Order contemplated that transitional gas supply realignment costs related to this restructuring may be billed by interstate pipelines to their customers. At December 31, 1994, a regulatory asset of $23.5 million, with an offsetting non-current Other Liability, has been recorded. In addition, the Company estimates it may incur other future billings of approximately $15 million related to such restructuring. The Company is currently recovering such cost through rates. The Company is investigating five properties currently owned by the Company which were, at one time, sites of gas manufacturing plants. The purpose of these investigations is to determine whether waste materials are present, whether such materials constitute an environmental or health risk, and whether the Company has any responsibility for remedial action. One site is located in Illinois and four sites are located in Iowa. With regard to the Illinois property, the Company has signed a working agreement with the Illinois Environmental Protection Agency to perform further investigation to determine whether waste materials are present and, if so, whether such materials constitute an environmental or health risk. At December 31, 1994, an estimated liability of $3.3 million has been recorded for litigation, investigation and remediation related to the Illinois site. A regulatory asset has been recorded reflecting anticipated cost recovery through rates in Illinois. With regard to the Iowa sites, no agreement or consent order has been negotiated to perform any site investigations or remediation. The Company has recorded a $4 million estimated liability for the Iowa sites. A regulatory asset has been recorded based on the current regulatory treatment of comparable costs in Iowa. The estimated recorded liabilities for these properties are based upon preliminary data. Thus, actual costs could vary significantly from the estimates. In addition, insurance recoveries for some or all of the costs may be possible, but the liabilities recorded have not been reduced by any estimate of such recoveries. Although the timing of incurred costs, recoveries and the inclusion of provision for such costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on the Company's financial position or results of operations. Clean Air Act legislation was signed into law in November 1990. The Company has four jointly and one wholly owned coal- fired generating stations, which represent approximately 65% of the Company's electric generating capability. Each of these facilities will be affected to varying degrees by the legislation. Only one unit at the wholly owned generating station, representing approximately 10% of the Company's electric generating capability, will be impacted by the emission reduction requirements effective in 1995. Beginning in 1995, this unit will be required to hold allowances, issued by the federal government, in order to emit sulfur dioxide. The compliance strategy for this unit includes modifications to allow for burning low-sulfur coal, modifications for nitrogen oxide control and installation of a new emission monitoring system. The Company's remaining construction expenditures relative to this work are estimated to be $2.5 million. The four generating stations not affected until 2000 already burn low-sulfur coal, so additional capital costs will not be incurred for sulfur dioxide emission reduction requirements. Beginning in 2000, these facilities will be required to hold allowances, issued by the federal government, in order to emit sulfur dioxide. Installation of low nitrogen oxide burners is required at one of these facilities and existing emission monitoring systems at all four facilities require upgrading. The Company's remaining construction cost for this work is estimated to be $1.4 million. It is anticipated that any costs incurred by the Company to comply with the Clean Air Act legislation would be included in the cost of service on which the Company's rates for utility service are based. The National Energy Policy Act of 1992 established funding for the decontamination and decommissioning of nuclear enrichment facilities operated by the Department of Energy (DOE). A portion of such funding is to be collected over a 15-year period, which began in 1992, from electric utilities that had previously purchased enrichment services from the DOE. At December 31, 1994, the Company's liability for its share of such funding was $9.2 million. In 1994, 1993 and 1992, $849,000, $770,000 and $200,000 of such payments were charged to fuel expense and recognized in the energy adjustment clauses. In September 1993, Medallion Production Company acquired all the outstanding capital stock of DKM Resources Inc. from the Dyson-Kissner-Moran Corporation, New York. Medallion is the oil and gas business of InterCoast. The transaction totaled more than $50 million and more than doubled Medallion's oil and gas reserve base. Capital expenditures for InterCoast during 1995 are estimated to be approximately $65 million. Actual capital expenditures for InterCoast are dependent on overall InterCoast performance and general market conditions. InterCoast's unsecured Senior Notes (Notes) are issued in private placement transactions. All Notes are issued without recourse to the parent Company. In November 1994, InterCoast issued $70 million of 8.52% Notes due 2002 in a private placement transaction with four insurance companies. The Notes have sinking fund requirements in 2000 and 2001. InterCoast's aggregate amounts of maturities and cash sinking fund requirements for long-term debt outstanding at December 31, 1994 are $64 million for 1995 and $169 million for the years 1996-1999. Amounts due in 1995 are expected to be refinanced with debt instruments and operating cash flow. InterCoast has a $110 million unsecured revolving credit facility agreement, which matures in February 1996. Borrowings under this agreement may be on a fixed rate, floating rate or competitive bid rate basis. All such borrowings are without recourse to the parent Company. Borrowings at December 31, 1994 were $35 million at a weighted average interest cost of 6.6%. Borrowings at December 31, 1993 were $44.5 million at a weighted average interest cost of 4.1%. InterCoast is subject to certain restrictions under the terms of its borrowing arrangements. Such restrictions include provisions which limit the amounts that can be expended for dividends and the issuance of additional debt. At December 31, 1994, $23.2 million was available for dividends. In addition, at December 31, 1994, under the most restrictive of such provisions, additional debt up to $11 million could be issued. The Company's consolidated capitalization ratios (including short-term debt, long-term debt maturing within one year and preference shares redeemable within one year) at the end of each of the last three years were as follows: December 31, 1994 1993 1992 Long-term debt............... 52.1% 52.9% 49.2% Short-term debt.............. 5.2 2.4 4.3 Total debt................ 57.3 55.3 53.5 Preferred and Preference stock equity............... 3.9 5.5 5.7 Common stock equity.......... 38.8 39.2 40.8 100.0% 100.0% 100.0% Quarterly common stock dividends were paid in 1994 and 1993 at a rate of 43.25 cents per share, a total of $1.73 for each of the years. EX-13.A.4 5
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME Year Ended December, 31 1994 1993 1992 (In thousands, except per share amounts) OPERATING REVENUES Electric $355,955 $338,593 $312,667 Gas 199,129 206,821 184,867 555,084 545,414 497,534 OPERATING EXPENSES AND TAXES Operation- Cost of gas sold 135,197 141,712 125,317 Cost of fuel, energy and capacity 68,748 64,619 58,266 Other operation 105,916 104,281 102,311 Maintenance 46,665 44,524 39,536 Provision for depreciation 61,829 58,647 53,941 Depreciation and equity funds recovered under Louisa Phase-In Clause - 2,370 4,515 Income taxes 29,185 24,477 16,320 Property and other taxes 33,903 33,401 33,827 481,443 474,031 434,033 OPERATING INCOME 73,641 71,383 63,501 OTHER INCOME InterCoast Energy Company - Oil and gas revenues 59,685 54,979 28,478 Other income 30,717 29,105 27,350 Expenses, including interest and provision for income taxes (81,386) (71,583) (46,351) Net income of InterCoast Energy Company 9,016 12,501 9,477 Miscellaneous 380 461 (984) 9,396 12,962 8,493 INCOME BEFORE UTILITY INTEREST CHARGES 83,037 84,345 71,994 UTILITY INTEREST CHARGES Interest on long-term debt 23,731 24,471 25,793 Other interest expense 1,644 1,625 1,872 Allowance for borrowed funds used during construction (1,474) (979) (1,104) 23,901 25,117 26,561 NET INCOME 59,136 59,228 45,433 PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS 5,071 4,995 5,029 NET INCOME ON COMMON SHARES $54,065 $54,233 $40,404 AVERAGE COMMON SHARES OUTSTANDING 29,492 29,338 27,944 NET INCOME PER AVERAGE COMMON SHARE OUTSTANDING $1.83 $1.85 $1.45 CASH DIVIDENDS DECLARED AND PAID PER COMMON SHARE $1.73 $1.73 $1.73 The accompanying notes to consolidated financial statements are an integral part of these statements. -1-
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Year Ended December 31, 1994 1993 1992 (In thousands) BALANCE BEGINNING OF YEAR $219,371 $216,082 $224,345 ADD-NET INCOME 59,136 59,228 45,433 DEDUCT: Cash dividends declared- Preferred and preference shares 4,661 4,978 5,026 Common shares 50,955 50,756 48,592 Premium paid to reacquire preferred and preference shares 312 173 - Other, primarily loss on reissuance of treasury shares 38 32 78 55,966 55,939 53,696 BALANCE END OF YEAR $222,541 $219,371 $216,082 The accompanying notes to consolidated financial statements are an integral part of these statements. -2-
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31, 1994 1993 (In thousands) PROPERTY AND OTHER ASSETS UTILITY PLANT, at original cost Electric $1,281,027 $1,270,103 Gas 279,118 270,446 1,560,145 1,540,549 Less--Accumulated provision for depreciation 638,493 605,708 921,652 934,841 Nuclear fuel, net of accumulated amortization 31,103 25,120 Construction work in progress 51,316 22,791 1,004,071 982,752 CURRENT ASSETS Cash and cash equivalents 24,740 17,844 Accounts receivable, less reserves of $1,165 41,498 43,389 Accrued unbilled revenues 21,637 22,182 Inventories 37,328 35,597 Deferred gas expense 4,471 5,794 Other 16,262 18,246 145,936 143,052 INVESTMENTS InterCoast Energy Company 489,830 501,829 Nuclear decommissioning trust fund 49,432 39,470 Corporate-owned life insurance 14,338 12,836 553,600 554,135 OTHER ASSETS Regulatory assets 133,427 92,828 Other 12,865 10,303 146,292 103,131 1,849,899 1,783,070 CAPITALIZATION AND LIABILITIES CAPITALIZATION (See accompanying statements) 1,163,120 1,183,641 CURRENT LIABILITIES Notes payable 67,500 31,000 Debt redeemable within one year 64,145 59,232 Accounts payable 37,785 44,847 Accrued taxes 26,240 24,913 Accrued interest 10,987 11,413 Accrued gas expense 9,499 11,745 Other 20,921 17,865 237,077 201,015 OTHER LIABILITIES Accumulated provision for nuclear decommissioning 49,432 39,470 Other 69,650 42,984 119,082 82,454 ACCUMULATED DEFERRED INCOME TAXES 291,426 274,605 ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 39,194 41,355 $1,849,899 $1,783,070 The accompanying notes to consolidated financial statements are an integral part of these statements. -3-
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1994 1993 (In thousands, except share amounts) COMMON SHAREHOLDERS' EQUITY Common shares-authorized 80,000,000 shares- outstanding 29,783,486 and 29,352,173 shares stated at $288,692 $280,009 Retained earnings 222,541 219,371 Other (8,991) 32 Total 502,242 43% 499,412 42% PREFERRED SHARES-authorized 400,000 shares, cumulative- Not subject to mandatory redemption-outstanding- $4.36 Series Preferred, 60,000 shares - 6,000 $4.22 Series Preferred, 40,000 shares - 4,000 $7.50 Series Preferred, 98,288 shares - 9,829 Total - - 19,829 2% PREFERENCE SHARES-authorized 2,386,250 shares, cumulative- Subject to mandatory redemption-outstanding- $5.25 Series Preference, 100,000 shares 10,000 10,000 $7.80 Series Preference, 400,000 shares 40,000 40,000 Total 50,000 4% 50,000 4% LONG-TERM DEBT First Mortgage Bonds- 5-7/8% Series, due 1997 22,000 22,000 Adjustable Rate Series, due 1997 (7.6%) 25,000 25,000 5.05% Series, due 1998 50,000 50,000 6.0% Series, due 2000 35,000 35,000 8.15% Series, due 2001 40,000 40,000 7.70% Series, due 2004 60,000 60,000 5.8% Series, due 2007 12,750 12,750 7.45% Series, due 2023 30,000 30,000 6.95% Series, due 2025 50,000 50,000 324,750 324,750 Pollution Control Obligations- 5.75%, due 2003 3,683 3,828 Variable Rate- Due 2016 (5.7% and 2.5%) 33,700 33,700 Due 2017 (5.7% and 2.5%) 3,900 3,900 Due 2023 (5.6% and 3.2%) 6,850 6,850 Unamortized debt premium and discount, net (1,005) (1,128) Total utility 371,878 371,900 InterCoast Energy Company- Senior Notes- 9.80%, due 1995 - 9,000 10.01%, due 1995 - 15,000 8.27%, due 1995 - 32,000 9.30%, due 1995 and 1996 9,000 17,000 10.20%, due 1996 and 1997 60,000 60,000 7.34%, due 1998 20,000 20,000 7.76%, due 1999 45,000 45,000 8.52%, due 2000-2002 70,000 - Borrowings under unsecured revolving credit facility (6.6% and 4.1%) 35,000 44,500 Total InterCoast Energy Company 239,000 242,500 Total 610,878 53% 614,400 52% $1,163,120 100% $1,183,641 100% The accompanying notes to consolidated financial statements are an integral part of these statements. -4-
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 1994 1993 1992 (In thousands) CASH FLOWS FROM OPERATING ACTIVITIES Net income $59,136 $59,228 $45,433 Adjustments to reconcile net income to net cash from operating activities - Depreciation 65,880 63,839 58,374 Depletion 17,949 12,880 8,517 Depreciation and equity funds recovered under Louisa Phase-In Clause - 2,370 4,515 Nuclear fuel amortization 5,334 7,989 7,860 Deferred income taxes, net 11,047 9,707 5,128 Tax credits, net (2,161) (2,208) (2,326) Net gain on disposition of securities (5,187) (3,289) (4,261) Changes in current assets and liabilities - Accounts receivable 1,891 2,434 (2,937) Accrued unbilled revenues 545 (1,567) (2,340) Inventories (1,731) 4,550 (349) Deferred and accrued gas expense (923) 3,310 (7,641) Accounts payable (7,162) 5,038 3,529 Accrued taxes 1,327 (2,643) 2,794 Other current assets and liabilities 4,423 (4,659) (6,568) Energy-efficiency program cost deferrals (7,641) (5,669) (4,005) Other 2,222 3,054 (5,743) Net cash from operating activities 144,949 154,364 99,980 CASH FLOWS FROM INVESTING ACTIVITIES Utility plant expenditures (68,957) (60,162) (64,385) Nuclear fuel expenditures (11,317) (6,795) (9,313) Nuclear decommissioning trust fund (9,044) (7,918) (4,469) Oil and gas investments (39,384) (73,538) (22,169) Purchase of available-for-sale investments (123,714) - - Sale of available-for-sale investments 142,272 - - Purchase of investments - (206,139) (216,264) Sale of investments - 208,271 173,941 Other 1,975 (1,151) (6,826) Net cash from investing activities (108,169) (147,432) (149,485) CASH FLOWS FROM FINANCING ACTIVITIES Common stock issued 8,812 - 61,563 Preference shares issued - 10,000 - Preferred and preference shares redeemed (20,141) (9,373) (575) Long-term debt issued - 175,784 59,830 Long-term debt retired (232) (143,493) (62,626) Increase (decrease) in short-term borrowings 36,500 (21,500) - Long-term borrowings of InterCoast Energy Company - Senior Notes issued 70,000 - 65,000 Senior Notes retired (59,000) (8,000) Increase (decrease) in unsecured revolving credit facility (9,500) 44,500 (15,100) Dividends paid (55,953) (55,745) (53,630) Issuance expense (370) (2,088) (3,187) Net cash from financing activities (29,884) (9,915) 51,275 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 6,896 (2,983) 1,770 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 17,844 20,827 19,057 CASH AND CASH EQUIVALENTS AT END OF YEAR $24,740 $17,844 $20,827 SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the year for - Interest (net of amounts capitalized) $50,121 $51,295 $48,036 Income taxes 15,728 18,014 10,074 The accompanying notes to consolidated financial statements are an integral part of these statements. -5-
Iowa-Illinois Gas and Electric Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Summary of Significant Accounting Policies: (A) Principles of Consolidation The consolidated financial statements include the Company and its wholly owned non-regulated subsidiary, InterCoast Energy Company (InterCoast). Intercompany transactions have been eliminated. _________________________________________________________________ (B) Regulation The Company's utility operations are subject to the regulation of the Iowa Utilities Board (IUB), the Illinois Commerce Commission (ICC) and the Federal Energy Regulatory Commission (FERC). The Company's accounting policies and the accompanying Consolidated Financial Statements conform to generally accepted accounting principles applicable to rate- regulated enterprises and reflect the effects of the ratemaking process. Such effects concern mainly the time at which various items enter into the determination of net income in accordance with the principle of matching costs and revenues. The following regulatory assets represent probable future revenue to the Company because provisions for these costs are expected to be included in charges to utility customers through the ratemaking process: December 31, 1994 1993 (In thousands) Income taxes recoverable through future rates............ $ 61,150 $50,571 FERC Order 636 transition costs... 23,465 - Unamortized premium on reacquired debt............................ 10,645 11,513 Deferred energy-efficiency program costs................... 18,432 10,791 United States Department of Energy (DOE) nuclear enrichment facilities decontamination and decommissioning fee............. 9,807 10,656 Manufactured gas plant site related costs................... 7,682 7,768 Other, primarily deferred pension costs........................... 2,246 1,529 $133,427 $92,828 Refer to Note 4 for information regarding income taxes recoverable through future rates. Refer to Note 2B for information regarding gas transition costs. Consistent with regulatory treatment, the premiums paid to reacquire debt prior to scheduled maturity dates are deferred and amortized over the life of the debt issued to finance the reacquisitions. In 1991, the Company filed a comprehensive three-year energy-efficiency plan with the IUB in compliance with 1990 Iowa legislation. The legislation permits recovery of deferred energy-efficiency program costs, and related carrying charges, so long as the utility's programs are cost effective or, if not cost effective, planned and implemented in a prudent and reasonable manner. The legislation also allows for performance rewards. In October 1994, the Company filed an application for recovery of an aggregate $18.6 million of deferred energy-efficiency program costs, associated returns and performance rewards over a four- year period. The National Energy Policy Act of 1992 established funding for the decontamination and decommissioning of nuclear enrichment facilities operated by the DOE. A portion of such funding is to be collected over a 15-year period, which began in 1992, from electric utilities that had previously purchased enrichment services from the DOE. At December 31, 1994, the Company's liability for its share of such funding was $9.2 million. In 1994, 1993 and 1992, $849,000, $770,000 and $200,000, respectively, of such payments were charged to fuel expense and recognized in the energy adjustment clauses. In Illinois, costs related to the litigation, investigation and remediation of former manufactured gas plant sites are recovered through gas and electric adjustment riders. Costs from 1992 and 1993 were deferred pursuant to an ICC order for recovery beginning in 1994. All such costs are to be amortized over a five-year period and no carrying charges are assigned to the unamortized balances. In Iowa, costs related to the litigation, investigation and remediation of former manufactured gas plant sites are being expensed as incurred. The Company's current Iowa gas rates include an annual provision of $250,000 for such costs. Refer to Note 14 for information regarding former manufactured gas plant sites. Refer to Note 5 for information regarding deferred pension costs. _________________________________________________________________ (C) Customer Receivables and Operating Revenues The Company's customer receivables, gas and electric sales and gas transportation revenue are derived from supplying and delivering electricity and natural gas to a well-diversified base of residential, commercial and industrial customers located in central and eastern Iowa and western Illinois. Customer accounts receivable include the following amounts by class of customer: December 31, 1994 1993 (In thousands) Residential.................... $ 18,174 $ 18,525 Commercial..................... 10,897 11,107 Industrial..................... 9,602 9,795 Other.......................... 1,531 1,557 Revenues are recorded as services are rendered to customers. The Company records unbilled revenues, and related energy costs, representing the estimated amount customers will be billed for services rendered between the meter-reading dates in a particular month and the end of such month. _________________________________________________________________ (D) Energy Costs The energy (electric fuel and energy and purchased gas) rate provisions in the Company's tariffs are designed to provide for separately stated energy billings that cover changes in applicable net energy costs from levels incorporated in base rates. Differences between applicable energy costs incurred and energy rate revenues billed in any given period are accounted for as other current assets or other current liabilities, pending the disposition of such differences through reconciliation provisions in the energy adjustment clauses. _________________________________________________________________ (E) Nuclear Fuel Costs Included as a part of the cost of nuclear fuel is a provision for its estimated disposal cost, which is being recognized at a rate of 1 mill per kilowatt-hour of nuclear generation in conformance with DOE rules. Such amounts are recoverable through the energy adjustment clauses. _________________________________________________________________ (F) Allowance for Funds Used During Construction The allowance for funds used during construction (AFUDC) includes the costs of equity and borrowed funds used to finance construction, which are capitalized in accordance with rules prescribed by the FERC. In 1994, 1993 and 1992, the Company's AFUDC rates were 5.6%, 3.3% and 3.8%, respectively, compounded semi-annually. While currently capitalized AFUDC does not represent a current source of cash, it does represent a basis for future sources of cash through the inclusion in rates of depreciation charges and allowance for returns on investment. _________________________________________________________________ (G) Depreciation Depreciation is computed using the straight-line method. Provisions for depreciation, expressed as an annual percentage of the cost of average depreciable plant in service, were as follows for the periods shown: Year Ended December 31, 1994 1993 1992 Electric........................ 4.3% 4.2% 4.0% Gas............................. 3.6 4.0 3.8 An allowance for the estimated decommissioning costs of the Quad-Cities Nuclear Power Station (Quad-Cities) is included in depreciation expense. The Company's share of the cost to decommission the Quad-Cities units is estimated to be $181.9 million in 1994 dollars. Such decommissioning costs include the cost of decontamination, dismantlement and site restoration. Electric tariffs included provisions for the costs of nuclear decommissioning of $9.1 million, $7.9 million and $5.0 million for 1994, 1993 and 1992, respectively. The Company has established an external trust for the investment of funds collected for nuclear decommissioning. Electric tariffs for 1995 include provisions for annual decommissioning costs of approximately $8.6 million. In Illinois, nuclear decommissioning costs are included in customer billings through a mechanism that permits annual adjustments. In Iowa, such costs are reflected in base rates. _________________________________________________________________ (H) Scheduled Nuclear Refueling Outage Costs Incremental operation and maintenance costs due to scheduled nuclear refueling outages are accrued, based upon the planned outage schedules and the estimated costs for such outages, over the estimated periods between scheduled outages. Any differences between accrued and actual outage costs are expensed in the periods in which the outages occur. _________________________________________________________________ (I) Marketable Securities InterCoast's holdings of marketable securities generally consist of preferred stocks, common stocks and mutual funds. Prior to 1994, InterCoast's holdings of marketable securities were stated at the lower of aggregate cost or market. A decline in the market value of marketable equity securities below their cost basis was recognized in the consolidated financial statements through the establishment of a valuation allowance, which was reflected as a reduction of Other Common Shareholders' Equity. On January 1, 1994, the Company adopted Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities (SFAS 115). Upon adoption, InterCoast classified its entire holdings of marketable securities as available-for-sale reflecting management's intention to hold such securities for indefinite periods of time. Under this statement, InterCoast's investments in marketable securities that are classified as available-for-sale are reported at fair value with net unrealized gains and losses reported as a net of tax amount in Other Common Shareholders' Equity until realized. On August 31, 1994, InterCoast transferred certain sinking fund preferred stocks with a market value of $40.6 million from the available-for-sale category to the held-to- maturity category. This transfer, which is at market value and is the new cost basis of such securities, was based on management's intent and ability to hold such securities until maturity. The $1.5 million excess of amortized cost over market value at August 31, 1994 will be amortized over the life of such securities. InterCoast's investments in marketable securities that are classified as held-to-maturity are reported at amortized cost. An other-than-temporary decline in the value of a marketable security is recognized through a write-down or write- off of the investment to earnings. Investments held by the nuclear decommissioning trust fund are classified as available-for-sale and are reported at fair value with net unrealized gains and losses reported as adjustments to the accumulated provision for nuclear decommissioning. The adoption of SFAS 115 did not have a material effect on the financial position or results of operations of the Company. _______________________________________________________________ (J) Oil and Gas InterCoast uses the full cost method of accounting for oil and gas activities. Under the full cost method, all acquisition, exploration and development costs are capitalized and amortized over the estimated production from proved oil and gas reserves. Under the full cost method, net capitalized costs may not exceed the present value of proved reserves as determined under the rules of the Securities and Exchange Commission. _________________________________________________________________ (K) Consolidated Statements of Cash Flows For purposes of the Consolidated Balance Sheets and the Consolidated Statements of Cash Flows, the Company considers all highly liquid debt instruments held that have original maturities of three months or less to be cash equivalents. No material non- cash investing or financing transactions occurred during 1994, 1993 or 1992. _________________________________________________________________ (L) Reclassification Certain 1993 and 1992 amounts have been reclassified to conform to the current year presentation. _________________________________________________________________ (2) Rate Matters: (A) Iowa Energy-Efficiency Programs Filing In October 1994, the Company filed an application with the IUB to recover the costs of state-mandated energy-efficiency programs offered to Iowa electric and gas customers since 1992. Costs of the programs are to be recovered over four years, as required by Iowa law. The overall annual rate increase requested, including a return on deferred amounts and an allowance for performance rewards, is approximately $4.7 million (1.4%). The proposed effective date for cost-recovery additions on customer bills is June 1995. _________________________________________________________________ (B) Federal Gas Transition Costs In April 1992, the FERC issued Order No. 636, directing a restructuring by interstate pipeline companies for their natural gas sales and transportation services. The FERC Order contemplated that transitional gas supply realignment costs related to this restructuring may be billed by interstate pipelines to their customers. At December 31, 1994, a regulatory asset of $23.5 million, with an offsetting non-current Other Liability, has been recorded. In addition, the Company estimates it may incur other future billings of approximately $15 million related to such restructuring. The Company is currently recovering such costs through rates. _________________________________________________________________ (3) InterCoast Energy Company: The Company's non-regulated businesses are managed by InterCoast, a wholly owned subsidiary. The non-regulated activities emphasize energy-related diversification, credit quality and liquidity. InterCoast takes advantage of a core expertise in energy, participating in the energy industry through three non-regulated business groups: oil and natural gas; energy services; and financial investments. Condensed consolidated financial information of InterCoast and its subsidiaries follows. Consolidated Statements of Income Year Ended December 31, 1994 1993 1992 (In thousands) Income: Oil and gas revenues.......... $59,685 $54,979 $28,478 Dividends and interest........ 18,144 19,103 18,917 Realized gains, net........... 5,187 3,289 4,261 Other income.................. 7,386 6,713 4,172 Total income.................... 90,402 84,084 55,828 Expenses: Oil and gas................... 46,106 38,749 20,285 Interest...................... 25,794 24,573 20,994 Other expenses................ 11,215 8,885 6,240 Provision for income taxes.... (1,729) ( 624) ( 1,168) Total expenses.................. 81,386 71,583 46,351 Net income...................... $ 9,016 $12,501 $ 9,477 Consolidated Balance Sheets December 31, 1994 1993 (In thousands) Current assets.................. $ 29,597 $ 21,926 Investments: Marketable securities......... 199,514 233,386 Oil and gas................... 142,378 120,952 Equipment leases.............. 60,134 59,937 Energy projects............... 50,316 48,777 Special-purpose funds......... 34,767 36,021 Real estate................... 2,721 2,756 Total investments............... 489,830 501,829 Other assets.................... 3,788 2,961 Total assets.................... $523,215 $526,716 December 31, 1994 1993 (In thousands) Long-term debt maturing within one year............... $ 64,000 $ 59,000 Other current liabilities....... 13,977 20,682 Long-term debt.................. 239,000 242,500 Accumulated deferred income taxes......................... 61,112 59,433 Shareholder's equity............ 145,126 145,101 Total liabilities and shareholder's equity.......... $523,215 $526,716 InterCoast is subject to certain restrictions under the terms of its borrowing arrangements. Such restrictions include provisions that limit the amounts that can be expended for dividends. At December 31, 1994 and 1993, $23.2 million and $16.5 million, respectively, of InterCoast's equity was available for dividends. _________________________________________________________________ (4) Income Taxes: The IUB has primarily limited the use of deferred income tax accounting to federal income taxes deferred as a result of the use of accelerated tax depreciation, as mandated by the normalization provisions of the Internal Revenue Code. The ICC, however, generally permits deferral of the tax effect of all book and tax differences. Investment tax credits (ITC) on the Company's investments in utility plant have been deferred and are being amortized to income over the life of the related property. Accumulated deferred income taxes at December 31, 1994 include offsetting benefits related to federal and state Alternative Minimum Tax (AMT) in the amounts of $29.2 million in federal AMT and $5.4 million in state AMT. The AMT credits may be carried forward indefinitely to offset future regular tax liabilities. The Company recognizes deferred income tax assets and liabilities, based on enacted tax laws, for all temporary differences between the financial reporting and tax bases of assets and liabilities. The portion of the Company's deferred tax liability applicable to utility operations that has not been reflected in service rates represents income taxes recoverable through future rates. Income tax expense is reflected in the Consolidated Statements of Income as follows: Year Ended December 31, 1994 1993 1992 (In thousands) Included in Operating Expenses: Current -Federal............. $20,227 $16,398 $12,607 -State............... 5,551 4,429 3,464 Deferred -Federal............. 5,042 5,318 2,532 -State............... 527 539 43 Deferred federal ITC, net..... ( 2,162) ( 2,207) ( 2,326) Total included in Operating Expenses.................... 29,185 24,477 16,320 Included in Other Income........ ( 2,117) ( 666) ( 1,763) Total income tax expense........ $27,068 $23,811 $14,557 The components of the net deferred tax liability are as follows: December 31, 1994 1993 (In thousands) Accelerated depreciation methods..... $ 270,321 $267,942 Income taxes recoverable through future rates............... 84,550 75,212 AMT credit carryforward.............. (34,555) (37,756) Deferred ITC refundable through future rates............... (23,400) (24,641) Nuclear reserves and decommissioning. (8,551) (6,708) Other deferred taxes, net............ 3,061 556 Accumulated deferred income taxes.... $ 291,426 $274,605 The following is a reconciliation of the statutory federal income tax rate to the overall effective income tax rate (computed by dividing income taxes, including income tax amounts applicable to other income, by net income before the deduction of such taxes): Year Ended December 31, 1994 1993 1992 Statutory federal income tax rate...................... 35.0% 35.0% 34.0% State income taxes, net of federal income tax benefit.... 4.4 4.7 3.3 Investment and energy tax credits....................... ( 2.5) ( 2.7) ( 3.9) Excess of book depreciation over tax depreciation not deferred. 1.7 1.6 2.2 Dividends received deduction.... ( 4.9) ( 5.2) ( 6.9) Adjustment for method of deducting property taxes...... ( 1.4) ( 1.4) ( 2.0) Other items, net................ ( 0.9) ( 3.3) ( 2.4) Overall effective income tax rate...................... 31.4% 28.7% 24.3% _________________________________________________________________ (5) Pensions and Other Employee Benefits: The Company has a noncontributory defined benefit retirement income plan covering substantially all regular employees. Benefits under the plan are based on participants' compensation, years of service and age at retirement. Funding is based upon the actuarially determined costs of the plan and the requirements of the Internal Revenue Code and the Employee Retirement Income Security Act. Provisions for pension costs are determined under generally accepted accounting principles, which include the use of the projected unit credit actuarial cost method. A regulatory adjustment has been made to the pension cost amounts to reflect only the amount of pension cost recognized through the ratemaking process. Net pension cost, part of which was charged to utility plant or billed to others, was $466,000 in 1994, $562,000 in 1993 and $175,000 in 1992. The components of the 1994, 1993 and 1992 pension cost provisions are as follows: Year Ended December 31, 1994 1993 1992 (In thousands) Cost of benefits earned during the year...................... $ 3,581 $ 3,283 $ 2,769 Interest on projected benefit obligation.................... 10,303 10,480 9,519 Actual investment return on plan assets................... ( 3,433) (17,009) (12,340) Net amortization and deferral... ( 9,303) 4,712 548 Pension cost.................... 1,148 1,466 496 Regulatory adjustment........... ( 682) ( 904) ( 321) Net pension cost................ $ 466 $ 562 $ 175 The expected long-term rate of return on plan assets used in determining pension cost was 8.75% for 1994, 1993 and 1992. A reconciliation of plan assets and liabilities to the accrued pension costs included in the Consolidated Balance Sheets is presented below: December 31, 1994 1993 (In thousands) Fair market value of pension plan assets, invested primarily in equity and fixed-income securities.................... $147,046 $151,134 Actuarial present value of benefits for services rendered to date: Accumulated benefits to date, including vested benefits of $99,370 and $118,300 for 1994 and 1993, respectively.............. 102,171 122,221 Additional benefits based on estimated future compensation levels....... 23,188 29,478 Projected benefit obligation.... 125,359 151,699 Plan assets in excess of (or less than) projected benefit obligation.................... 21,687 ( 565) Unamortized balance of plan net assets existing at January 1, 1986, being amortized over 17 years....... ( 9,160) ( 10,305) Unrecognized prior service cost. 16,614 18,849 Unrecognized net gain........... ( 32,802) ( 10,492) Accrued pension cost............ $( 3,661) $( 2,513) Assumed discount rate........... 8.5% 7.0% Assumed rate of increase in future compensation levels.... 5.0% 5.0% The Company currently provides certain health care and life insurance benefits for retired employees. Substantially all of the Company's employees become eligible for these additional benefits if they reach retirement age while employed by the Company. Provisions for these postretirement health care and life insurance benefits are accrued over the years the employees are expected to render the necessary service. The Company is externally funding all such provisions. The components of the 1994 and 1993 net postretirement benefits other than pensions cost provision are as follows: Year Ended December 31, 1994 1993 (In thousands) Cost of benefits earned during the year..................$ 492 $ 474 Interest on accumulated postretirement benefit obligation....................... 914 1,061 Actual investment return on plan assets................... 31 (6) Net amortization and deferral...... 614 688 Net postretirement benefits other than pensions cost.........$ 2,051 $ 2,217 A reconciliation of such postretirement benefit plan assets and liabilities to the amounts included in the Consolidated Balance Sheets is presented below: December 31, 1994 1993 (In thousands) Fair market value of plan assets, invested primarily in short- term securities.................. $ 1,584 $ 976 Actuarial present value of benefits for services rendered to date: Active plan participants........ 5,488 6,941 Fully eligible plan participants 1,864 2,321 Retirees........................ 4,141 3,792 Accumulated postretirement benefit obligation............... 11,493 13,054 Accumulated postretirement benefit obligation in excess of plan assets................... ( 9,909) (12,078) Unamortized balance of plan obligation existing at January 1, 1993, being amortized over 20 years.......... 12,154 12,829 Unrecognized net gain.............. ( 2,245) ( 751) Accrued postretirement benefit other than pensions cost......... $ - $ - For measurement purposes, the health care cost trend rate assumed for pre-65 coverage is 12% for 1995, decreasing 1% per year to 5% in 2002 and thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. To illustrate, increasing the assumed health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation for health care costs as of December 31, 1994 by $722,000 and the aggregate of the 1994 service and interest cost components of net postretirement health care cost by $112,000. The discount rate used was 8.5%. The Company has adopted voluntary Compensation Deferral and Supplemental Retirement plans for designated executives. Such plans are unfunded and the liabilities thereunder are payable from general funds of the Company. To provide for its liabilities under these plans, the Company has purchased, owns and is the beneficiary of life insurance policies on the lives of participating executives. Returns on such policies are expected to cover the full cost of the related plans. On January 1, 1994, the Company adopted Statement of Financial Accounting Standards No. 112, Employers' Accounting for Postemployment Benefits, which requires the accrual of the estimated cost of benefits provided to former or inactive employees after employment but before retirement. Adoption did not have a material effect on financial position or results of operations. _________________________________________________________________ (6) Jointly Owned Generating Stations: Under joint ownership agreements with other utility companies, the Company has undivided interests in one nuclear and four coal-fired electric generating stations. Information concerning each of the jointly owned stations follows: Nuclear Coal-fired Council Quad-Cities Neal Bluffs Ottumwa Louisa Units Unit Unit Unit Unit No. 1 & 2 No.3 No.3 No.1 No.1 In service date..... 1972 1975 1978 1981 1983 Company share of utility plant in service (in millions)......... $194.6 $46.5 $120.3 $73.8 $260.4 Total plant capacity -megawatts........ 1,539 515 675 716 650 Company share -percent.......... 25.0% 29.0% 32.4% 18.5% 43.0% The Consolidated Financial Statements reflect the Company's portions of all plant investments and all operating costs associated with these units. Depreciation reserves by individual station are not maintained. Although the Louisa Unit No. 1 is operated and maintained by the Company, each of the other units is operated and maintained by another utility company. Each participant has provided the financing for its share of the total investment in each project. ________________________________________________________________ (7) Inventories: Inventories include the following amounts: December 31, 1994 1993 (In thousands) Materials and supplies, at average cost............ $14,871 $15,151 Coal stocks, at Last-In, First-Out (LIFO) cost...... 8,750 6,385 Fuel oil, at average cost......... 288 249 Gas in storage, at LIFO cost...... 13,419 13,812 $37,328 $35,597 At December 31, 1994 prices, the current costs of coal stocks and gas in storage were $9.0 million and $21.3 million, respectively. _________________________________________________________________ (8) Fair Value of Financial Instruments: The following methods and assumptions were used to estimate the fair value at December 31, 1994 and 1993 of each class of financial instruments for which it is practicable to make such estimates. Tariffs for the Company's utility services are established based on historical cost ratemaking. Therefore, the impact of any realized gains or losses related to financial instruments applicable to the Company's utility operations is dependent on the treatment authorized under future ratemaking proceedings. Cash and cash equivalents - The carrying amount approximates fair value due to the short maturity of these instruments. Nuclear decommissioning trust fund - Fair value is based on quoted market prices of the investments held by the fund. Marketable securities - Fair value is based on quoted market prices. Debt securities - Fair value is based on the discounted value of the future cash flows expected to be received from such investments. Equity investments carried at cost - Fair value is based on an estimate of the Company's share of partnership equity or on the discounted value of the future cash flows expected to be received from such investments. Equity investments in developing companies - It is not practicable to determine the fair value of such investments as they represent new ventures for which no market price exists. Notes payable - Fair value is estimated to be the carrying amount due to the short maturity of these issues. Preference shares - Fair value of preference shares with mandatory redemption provisions is estimated based on the quoted market prices for similar issues. Long-term debt - Fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturities. December 31, 1994 December 31, 1993 Carrying Fair Carrying Fair Amount Value Amount Value (In thousands) Electric and gas utility: Nuclear decommissioning trust fund............. $ 49,432 $ 49,432 $ 39,470 $ 41,588 Preference shares....... 50,000 50,836 50,000 54,850 Long-term debt, including current portion................ 372,023 346,241 372,132 384,954 InterCoast Energy Company: Marketable securities... 199,514 198,140 233,386 239,114 Debt securities......... 14,804 12,994 14,195 16,124 Equity investments carried at cost........ 22,352 23,930 27,141 27,789 Long-term debt, including current portion................ 303,000 294,762 301,500 317,700 The amortized cost, gross unrealized gains and losses and estimated fair value of investments in debt and equity securities at December 31, 1994 are summarized as follows: December 31, 1994 Amortized Unrealized Unrealized Fair Cost Gains Losses Value (In thousands) Investments in debt and equity securities-- Electric and gas utility: Nuclear decommissioning trust fund: Available-for-sale Cash equivalents...... $ 5,836 $ - $ - $ 5,836 Municipal bonds....... 43,034 749 (1,773) 42,010 Other................. 1,586 - - 1,586 $ 50,456 $ 749 $ (1,773) $ 49,432 InterCoast Energy Company: Available-for-sale Equity securities..... $171,201 $ 2,388 $ (14,703) $158,886 Held-to-maturity Equity securities..... 40,628 - ( 1,374) 39,254 Debt securities....... 14,804 39 ( 1,849) 12,994 At December 31, 1994, the debt securities held by the nuclear decommissioning trust fund and InterCoast had the following maturities: Nuclear Decommissioning Trust Fund InterCoast Amortized Fair Amortized Fair Cost Value Cost Value (In thousands) Within 1 year $ 2,862 $ 2,757 $ 1,791 $ 1,782 1 through 5 years 9,405 9,018 501 451 5 through 10 years 16,409 16,023 5,157 4,144 Over 10 years 14,358 14,212 7,355 6,617 The proceeds and the gross realized gains and losses on the disposition of investments held by the nuclear decommissioning trust fund and InterCoast for 1994 are as follows: Year Ended December 31, 1994 (In thousands) Nuclear Decommissioning Trust Fund: Proceeds from sales................ $ 2,214 Gross security gains............... 2 Gross security losses.............. (85) InterCoast Energy Company: Proceeds from sales................ 133,555 Gross security gains............... 10,336 Gross security losses.............. (5,149) _________________________________________________________________ (9) Common Shareholders' Equity: Changes in the Company's outstanding common shares for the years 1994, 1993 and 1992 are as follows: Year Ended December 31, Amount 1994 1993 1992 (In thousands) Outstanding, beginning of year. $280,009 $280,055 $220,819 Public sale of shares........ - - 61,563 Dividend reinvestment........ 8,812 - - Capital stock expense........ ( 45) ( 122) ( 2,392) Treasury shares Purchased.................. ( 771) ( 689) ( 632) Reissued................... 687 765 697 Outstanding, end of year....... $288,692 $280,009 $280,055 Shares 1994 1993 1992 Outstanding, beginning of year. 29,352,173 29,349,177 26,845,687 Public sale of shares........ - - 2,500,000 Dividend reinvestment........ 435,624 - - Treasury shares Purchased.................. (37,445) ( 31,100) ( 25,000) Reissued................... 33,134 34,096 28,490 Outstanding, end of year....... 29,783,486 29,352,173 29,349,177 The components of Other Common Shareholders' Equity are as follows: December 31, 1994 1993 (In thousands) Premium on Preferred shares.... $ - $ 32 Marked to market valuation, net of deferred tax.......... (8,991) - $(8,991) $ 32 The Company has an Employee Stock Purchase Plan. The purchase of common shares under this Plan is made on the open market. At December 31, 1994 and 1993, 4,750 and 439 treasury shares acquired in the open market for this Plan were held for reissuance. The Company has a Dividend Reinvestment and Share Purchase Plan. Effective with the June 1994 dividend, this Plan provides for the issuance of new shares with dividends reinvested and optional cash investments made by shareholders. _________________________________________________________________ (10) Long-Term Debt, Maturities and Sinking Fund Requirements: The 1994 sinking fund requirements for First Mortgage Bonds and Senior Notes were satisfied through the reacquisition of debt or the bonding of additional property. The aggregate maturities and sinking fund requirements for long-term debt outstanding at December 31, 1994 are as follows: 1995 1996 1997 1998 1999 (In thousands) First Mortgage Bonds. $ 220 $ 220 $47,200 $50,200 $ 200 Pollution Control Obligations........ 145 145 145 145 145 Senior Notes of InterCoast......... 64,000 39,000 30,000 20,000 45,000 Unsecured Revolving Credit Facility of InterCoast......... - 35,000 - - - Total................ $64,365 $74,365 $77,345 $70,345 $45,345 Included in the above amounts are annual sinking fund requirements related to First Mortgage Bonds of $220,000 for 1995 and 1996, which may be reduced by certifying net property additions not previously bonded, in accordance with the terms of the Company's Indenture of Mortgage securing its First Mortgage Bonds. The interest rate on the Company's Adjustable Rate Series First Mortgage Bonds is reset every two years at 160 basis points over the average yield to maturity of 10-year Treasury securities. The rate was reset in 1993. The Company's Variable Rate Pollution Control Obligations bear interest at rates that are periodically established through remarketing of the bonds in the short-term tax-exempt market. The Company, at its option, may change the mode of interest calculation for these bonds by selection from among several alternative floating or fixed rate modes. The interest rates shown in the Consolidated Statements of Capitalization are the weighted average interest rates as of December 31, 1994 and 1993. The Company maintains backup long-term letters of credit and a dedicated long-term revolving line of credit providing liquidity for holders of these issues. In January 1995, $12.75 million of floating rate Pollution Control Refunding Revenue Bonds, due 2025, were issued. Proceeds from this financing will be used to redeem $12.75 million of Collateralized Pollution Control Revenue Bonds, 5.8% Series, due 2007. The Company's First Mortgage Bonds are secured by substantially all fixed property and franchises of the Company devoted to its utility businesses. InterCoast's unsecured Senior Notes (Notes) are issued in private placement transactions. All Notes are issued without recourse to the parent Company. InterCoast has a $110 million unsecured revolving credit facility agreement, which matures in February 1996. Borrowings under this agreement may be on a fixed rate, floating rate or competitive bid rate basis. All such borrowings are without recourse to the parent Company. Borrowings at December 31, 1994 were $35.0 million at a weighted average interest cost of 6.6%. Borrowings at December 31, 1993 were $44.5 million at a weighted average interest cost of 4.1%. _________________________________________________________________ (11) Preferred and Preference Shares: The $5.25 Series Preference Shares, which are not redeemable prior to November 1, 1998 for any purpose, are subject to mandatory redemption on November 1, 2003 at $100 per share. The $7.80 Series Preference Shares, which are not redeemable prior to May 1, 1996 for any purpose, have sinking fund requirements under which 66,600 shares will be redeemed at $100 per share each May 1, beginning in 2001 through May 1, 2006. On December 15, 1994, the Company redeemed all of its outstanding preferred shares. The redemption was made at a premium, which resulted in a charge to net income on common shares of $312,000. _________________________________________________________________ (12) Notes Payable: The Company's notes payable reflect borrowings that have been obtained solely through its short-term commercial paper program. Information regarding short-term debt follows: 1994 1993 1992 (Dollars in thousands) Balance at year-end............. $67,500 $31,000 $52,500 Weighted average interest rate on year-end balance........... 6.1% 3.4% 3.6% Maximum amount outstanding during the year............... $67,500 $73,000 $77,000 Average daily amount outstanding during the year............... $28,605 $43,291 $39,973 Weighted average interest rate on average daily amount outstanding during the year... 4.5% 3.3% 3.8% At December 31, 1994, the Company had bank lines of credit of $72.8 million to provide short-term financing for its utility operations. All such lines of credit were unused. The Company generally maintains compensating balances under its bank line of credit arrangements. The Company has regulatory authority to incur up to $100 million of short-term debt for its utility operations. _________________________________________________________________ (13) Leases: Rental payments under non-cancellable operating leases for 1994, 1993 and 1992 were $2,123,000, $2,013,000 and $1,941,000, respectively. At December 31, 1994, the future minimum lease payments under non-cancellable operating leases are as follow: Amount (In thousands) 1995 ................................... $ 2,238 1996 ................................... 2,147 1997 ................................... 1,867 1998 ................................... 1,648 1999 ................................... 1,553 After 1999 ............................. 13,422 ________________________________________________________________ (14) Commitments and Contingencies: Utility construction expenditures for 1995 are estimated to be $84 million, including $9 million for nuclear fuel. Capital expenditures for InterCoast during 1995 are estimated to be approximately $65 million. Actual capital expenditures for InterCoast are dependent on overall InterCoast performance and general market conditions. The Company is investigating five properties currently owned by the Company which were, at one time, sites of gas manufacturing plants. The purpose of these investigations is to determine whether waste materials are present, whether such materials constitute an environmental or health risk, and whether the Company has any responsibility for remedial action. One site is located in Illinois and four sites are located in Iowa. With regard to the Illinois property, the Company has signed a working agreement with the Illinois Environmental Protection Agency to perform further investigation to determine whether waste materials are present and, if so, whether such materials constitute an environmental or health risk. At December 31, 1994, an estimated liability of $3.3 million has been recorded for litigation, investigation and remediation related to the Illinois site. A regulatory asset has been recorded reflecting anticipated cost recovery through rates in Illinois. With regard to the Iowa sites, no agreement or consent order has been negotiated to perform any site investigations or remediation. The Company has recorded a $4 million estimated liability for the Iowa sites. A regulatory asset has been recorded based on the current regulatory treatment of comparable costs in Iowa. The estimated recorded liabilities for these properties are based upon preliminary data. Thus, actual costs could vary significantly from the estimates. In addition, insurance recoveries for some or all of the costs may be possible, but the liabilities recorded have not been reduced by any estimate of such recoveries. Although the timing of incurred costs, recoveries and the inclusion of provision for such costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on the Company's financial position or results of operations. Clean Air Act legislation was signed into law in November 1990. The Company has four jointly and one wholly owned coal- fired generating stations, which represent approximately 65% of the Company's electric generating capability. Each of these facilities will be impacted to varying degrees by the legislation. Only one unit at the wholly owned generating station, representing approximately 10% of the Company's electric generating capability, will be impacted by the emission reduction requirements effective in 1995. Beginning in 1995, this unit will be required to hold allowances, issued by the federal government, in order to emit sulfur dioxide. The compliance strategy for this unit includes modifications to allow for burning low-sulfur coal, modifications for nitrogen oxide control and installation of a new emission monitoring system. The Company's remaining construction expenditures relative to this work are estimated to be $2.5 million. The four generating stations not affected until 2000 already burn low-sulfur coal, so additional capital costs will not be incurred for sulfur dioxide emission reduction requirements. Beginning in 2000, these facilities will be required to hold allowances, issued by the federal government, in order to emit sulfur dioxide. Installation of low nitrogen oxide burners is required at one of these facilities and existing emission monitoring systems at all four facilities require upgrading. The Company's remaining construction cost for this work is estimated to be $1.4 million. It is anticipated that any costs incurred by the Company to comply with the Clean Air Act legislation would be included in the cost of service on which the Company's rates for utility service are based. The Company is a member of Nuclear Mutual Limited (NML), an industry mutual insurer established to provide property damage coverage for members' nuclear generating facilities. The Company would be subject to a maximum retrospective premium assessment of approximately $2 million based on its 25% share of the NML premium for Quad-Cities coverage in the event covered losses of NML members exceed the financial resources of the insurance company. A reserve has been established for this contingency. At December 31, 1994, NML had accumulated capital to a level that would make it unlikely the Company would have an exposure to a retrospective premium assessment in the event of a single incident to a member's facility. The Company is also a member of Nuclear Electric Insurance Limited (NEIL), an industry mutual insurance company, and an insured of American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters (ANI/MAELU). The related policy provisions provide that expenses for decontamination and the removal of debris shall be paid before any payment in respect of claims for property damage. A separate NEIL insurance policy covers the extra costs that would be incurred in obtaining replacement power during a prolonged covered outage of a member's nuclear plant. The Company is subject to retrospective premium assessments of approximately $4.1 million and $843,000 for its 25% share of the premium under the NEIL portion of the property damage coverage and the replacement power coverage, respectively. At December 31, 1994, NEIL had accumulated capital to a level that would make it unlikely the Company would have an exposure to a retrospective premium assessment in the event of a single incident to a member's facility. A Master Worker Policy issued by ANI/MAELU provides coverage for worker tort claims filed for bodily injury caused by the nuclear energy hazard. The coverage applies to workers whose "nuclear related employment" began after January 1, 1988. Under this policy, the Company could be subject to a maximum retrospective premium assessment of $1.5 million. Under the Price-Anderson federal legislation adopted in 1988, nuclear public liability coverage is supported by a mandatory industry-wide program under which owners of nuclear generating facilities could be assessed in the event of nuclear incidents. The Company would currently be subject to a maximum assessment of $39.6 million in the event of an incident, to be paid in increments of no more than $5 million per year per incident. _________________________________________________________________ (15) Merger On December 21, 1994, the shareholders of the Company, Midwest Resources Inc. and Midwest Power Systems Inc. approved a strategic merger of equals to form MidAmerican Energy Company (MidAmerican). MidAmerican will be structured as a utility with the Company, Midwest Resources Inc. and Midwest Power Systems Inc. being merged into the new company. Pursuant to the terms of the merger agreement, Midwest Resources' common shareholders will receive one share of MidAmerican for each Midwest share and the Company's shareholders will receive 1.47 shares of MidAmerican for each Company share. At the effective date of the merger, each series of the Company's preference shares then outstanding will be converted into an equal number of shares of MidAmerican preferred stock. Approval of the merger is required from the following regulatory agencies: the IUB, the ICC and the FERC. The NRC approval for the transfer of the Quad-Cities Station license to MidAmerican must also be obtained. Applications for approval of the merger were filed with the IUB and the ICC in October 1994. An application for approval of the merger was filed with the FERC in November 1994. At the same time, consistent with FERC policy, the Company filed open access, comparable services tariffs with the FERC, which tariffs will allow others to use MidAmerican's electric transmission system in a manner comparable to its use by MidAmerican. In January 1995, the IUB issued an order approving the merger. The ICC and FERC are expected to issue orders on the merger by mid 1995. A filing with the NRC was made in November 1994. Completion of the merger is expected during 1995. _________________________________________________________________ (16) Segment Information: Information related to segments of the Company's business is as follows: Year Ended December 31, 1994 1993 1992 (In thousands) Operating information Electric- Operating revenues.......... $ 355,955 $ 338,593 $ 312,667 Operating expenses excluding income taxes.... 266,706 257,493 245,753 Pre-tax operating income.... 89,249 81,100 66,914 Income taxes................ 24,961 20,171 12,959 Operating income............ 64,288 60,929 53,955 Allowance for funds used during construction (AFUDC)................... 1,563 886 1,019 Operating income and AFUDC.. 65,851 61,815 54,974 Depreciation expense........ 53,237 50,379 46,236 Depreciation and equity funds recovered under Louisa Phase-In Clause ................... - 2,370 4,515 Total depreciation expense.. 53,237 52,749 50,751 Capital expenditures........ 53,924 49,976 52,922 Gas- Operating revenues.......... 199,129 206,821 184,867 Operating expenses excluding income taxes.... 185,552 192,061 171,960 Pre-tax operating income.... 13,577 14,760 12,907 Income taxes................ 4,224 4,306 3,361 Operating income............ 9,353 10,454 9,546 AFUDC....................... 376 93 85 Operating income and AFUDC.. 9,729 10,547 9,631 Depreciation expense........ 8,592 8,268 7,705 Capital expenditures........ $ 26,350 $ 16,981 $ 20,776 Year Ended December 31, 1994 1993 1992 (In thousands) InterCoast Energy Company- Income...................... $ 90,402 $ 84,084 $ 55,828 Expenses excluding income taxes.............. 83,115 72,207 47,519 Pre-tax operating income.... 7,287 11,877 8,309 Depreciation, depletion and amortization.......... 19,417 13,920 9,267 Capital expenditures........ $ 13,681 $ 68,147 $ 64,096 December 31, 1994 1993 1992 (In thousands) Asset information Identifiable assets- Electric (a)................ $1,019,519 $ 988,264 $ 936,025 Gas (a)..................... 273,444 235,510 215,491 Used in overall utility operations................ 33,721 32,580 30,799 InterCoast Energy Company... 523,215 526,716 466,135 Total assets.................. $1,849,899 $1,783,070 $1,648,450 (a) Utility plant less accumulated provision for depreciation, accounts receivable, accrued unbilled revenues, inventories, deferred gas expense, energy adjustment clause balance, nuclear decommissioning trust fund and regulatory assets. As of December 31, 1994, 1993 and 1992, respectively, the major classes of utility plant are as follows: December 31, 1994 1993 1992 (In thousands) Electric- Production.................... $ 745,242 $ 641,810 $ 617,761 Transmission.................. 158,590 147,080 138,887 Distribution.................. 307,969 285,699 262,450 Other......................... 69,226 195,514 206,358 Total Electric................ 1,281,027 1,270,103 1,225,456 Gas- Distribution.................. 232,531 206,498 195,863 Other......................... 46,587 63,948 63,999 Total Gas..................... $ 279,118 $ 270,446 $ 259,862 _________________________________________________________________ (17) Quarterly Results (Unaudited): 1994 Quarter Ended December September June March 31 30 30 31 (In thousands, except per share amounts) Operating revenues....... $131,867 $123,921 $114,432 $184,864 Operating income......... 12,336 24,909 17,592 18,804 Net income on common shares................. 5,744 19,427 13,007 15,887 Net income per average common share outstanding............ $ .19 $ .66 $ .44 $ .54 1993 Quarter Ended December September June March 31 30 30 31 (In thousands, except per share amounts) Operating revenues....... $141,210 $127,720 $114,614 $161,870 Operating income......... 10,592 23,871 16,608 20,312 Net income on common shares................. 7,215 17,921 12,099 16,998 Net income per average common share outstanding............ $ .25 $ .61 $ .41 $ .58 The quarterly data reflect seasonal variations common in the utility industry. Report of Management Management is responsible for the preparation of all information contained in this Annual Report, including the financial statements. The statements and related financial information have been prepared in conformity with generally accepted accounting principles. In the opinion of management, the financial position, results of operation and cash flows of the Company are reflected fairly in the statements. The statements have been audited by the Company's independent public accountants, Deloitte & Touche LLP, whose report appears below. The Company maintains a system of internal controls which is designed to provide reasonable assurance, on a cost effective basis, that transactions are executed in accordance with management's authorization, the financial statements are reliable and the Company's assets are properly accounted for and safeguarded. The Company's internal auditors continually evaluate and test the system of internal controls and actions are taken when opportunities for improvement are identified. Management believes that the system of internal controls is effective. The financial statements have been reviewed by the Audit Committee of the Board of Directors. The Audit Committee, the members of which are directors who are not employees of the Company, meets regularly with management, the internal auditors and Deloitte & Touche LLP to discuss accounting, auditing, internal control and financial reporting matters. The Company's independent public accountants are appointed annually by the Board of Directors on recommendation of the Audit Committee. The internal auditors and Deloitte & Touche LLP each have full access to the Audit Committee, without management representatives present. Stanley J. Bright Chairman and Chief Executive Officer Lance E. Cooper Vice President-Finance and Chief Financial Officer Independent Auditors' Report To the Shareholders and Board of Directors of Iowa-Illinois Gas and Electric Company: We have audited the accompanying consolidated balance sheets and statements of capitalization of Iowa-Illinois Gas and Electric Company and subsidiary as of December 31, 1994 and 1993, and the related consolidated statements of income, retained earnings, 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. The consolidated financial statements of the companies for the year ended December 31, 1992 were audited by other auditors whose report, dated January 28, 1993, expressed an unqualified opinion on those statements. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the companies as of December 31, 1994 and 1993, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Davenport, Iowa January 25, 1995 EX-21 6 EXHIBIT 21 Iowa-Illinois Gas and Electric Company has one wholly owned subsidiary, InterCoast Energy Company, a Delaware corporation. EX-23.A 7 CONSENT OF INDEPENDENT AUDITORS Iowa-Illinois Gas and Electric Company: We consent to the incorportion by reference in Registration Statement No. 33-23081 on Form S-8, Registration Statement No. 33-20329 on Form S-8 and Registration Statement No. 33-53249 on Form S-3 of our reports dated January 25, 1995, appearing in and incorporated by reference in this Annual Report on Form 10-K of Iowa-Illinois Gas and Electric Company for the year ended December 31, 1994. DELOITTE & TOUCHE LLP Davenport, Iowa March 22, 1995 EX-23.B 8 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in Registration Statement No. 33-23081 on Form S-8 and Registration Statement No. 33-20329 on Form S-8 and Registration Statement No. 33-53249 on Form S-3 of our report dated January 28, 1993, covering the consolidated balance sheet and statement of capitalization of Iowa-Illinois Gas and Electric Company and Subsidiary Company as of December 31, 1992, and the related statements of income, retained earnings and cash flows for the year then ended, included in the Company's Form 10-K for the year ended December 31, 1994 (Commission file number 1-3573). It should be noted that we have not audited any financial statements of the Company subsequent to December 31, 1992, or performed any audit procedures subsequent to the date of our report. ARTHUR ANDERSEN LLP Chicago, Illinois March 20, 1995 EX-27 9
UT This schedule contains summary financial information extracted from the consolidated balance sheet of Iowa-Illinois Gas and Electric Company as of December 31, 1994 and the related consolidated statements of income and cash flows for the twelve months ended December 31, 1994 and is qualified in its entirety by reference to such financial statements. 1000 12-MOS DEC-31-1994 DEC-31-1994 PER-BOOK $1,004,071 553,600 145,936 0 146,292 1,849,899 288,692 0 222,541 502,242 50,000 0 610,878 0 0 67,500 64,145 0 0 0 546,143 1,849,899 555,084 29,185 452,258 481,443 73,641 9,396 83,037 23,901 59,136 5,071 54,065 50,961 23,731 144,949 $1.83 $1.83
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