-----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, fRDdZ7y7LxnwcAh4l1W4rrlpro1ATN3vMXLLqva5bpCVNM/UZqeiw6GitDRCEU3l nVfBTruJISAH+6Yy6SKfjg== 0000051720-95-000015.txt : 19950616 0000051720-95-000015.hdr.sgml : 19950616 ACCESSION NUMBER: 0000051720-95-000015 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950323 SROS: MSE SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: INTERSTATE POWER CO CENTRAL INDEX KEY: 0000051720 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 420329500 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03632 FILM NUMBER: 95522562 BUSINESS ADDRESS: STREET 1: 1000 MAIN ST STREET 2: PO BOX 769 CITY: DUBUQUE STATE: IA ZIP: 52004-0769 BUSINESS PHONE: 3195825421 10-K 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C 20549 FORM 10-K For the fiscal year ended December 31, 1994 Commission file number 1-3632 (Mark One) (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 INTERSTATE POWER COMPANY (Exact name of registrant as specified in its charter) DELAWARE 42-0329500 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1000 Main St., P.O. Box 769, Dubuque, IA 52004-0769 (Address of principal executive office) (Zip Code) Registrant's telephone number, including area code 319-582-5421 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange on Title of each class which registered Common Stock Par Value $3.50 Per Share ) New York Stock Exchange ) Chicago Stock Exchange ) Pacific Stock Exchange Securities registered pursuant to Section 12(g) of the Act: N O N E Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No . Indicate 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. [ ] As of March 1, 1994 the aggregate market value of the voting stock held by non-affiliates of the registrant was $233,129,495. Indicate the number of shares outstanding of each of the issuer's classes of common stock. Shares Outstanding March 1, 1995 Common Stock Par Value $3.50 Per Share 9,564,287 Documents incorporated by reference - portions of the Annual Report to Stockholders for 1994 (Exhibit EX-13) are incorporated by reference in Parts I, II and IV; portions of the Annual Proxy Statement for 1995 are incorporated by reference in Part III. INTERSTATE POWER COMPANY 1994 Form 10-K Annual Report Table of Contents Page Part I Item 1. Business 1 General 1 Construction Program 1 Electric Operations 1 Sources and Availability of Raw Materials 2 Duration and Effect of Electric Patents and Franchises 3 Electric Seasonal Business 3 Working Capital Items 3 Electric Governmental Regulations 3 Electric Competitive Conditions 4 Other Sources of Power 5 Other Electric Operations 7 Gas Operations 7 Gas Sources and Availability of Raw Materials 7 Duration and Effect of Gas Patents and Franchises 9 Gas Seasonal Business 9 Gas Governmental Regulations 9 Gas Competitive Conditions 9 Dependence of Segment Upon a Single Customer 10 Research and Development 10 Electric and Magnetic Fields 10 Environmental Regulations 10 Employees 13 Accounting Matters 13 Item 2. Properties 14 Electric Properties 14 Generating Stations 15 Gas Properties 16 General Properties 16 Titles 16 Item 3. Legal Proceedings 16 Item 4. Submission of Matters to a Vote of Security Holders 17 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 17 Item 6. Selected Financial Data 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 17 Item 8. Financial Statements and Supplementary Data 17 Item 9. Disagreements on Accounting and Financial Disclosure 17 Part III Item 10. Executive Officers of the Registrant 18 Item 11. Executive Compensation 18 Item 12. Security Ownership of Certain Beneficial Owners and Management 18 Item 13. Certain Relationships and Related Transactions 19 Part IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 19 PART I ITEM 1. BUSINESS (General) Interstate Power Company, (the company), is an operating public utility incorporated in 1925 under the laws of the State of Delaware. The company is engaged in the generation, purchase, transmission, distribution and sale of electricity. It owns property in portions of twenty-five counties in the northern and northeastern parts of Iowa, in portions of twenty-two counties in the southern part of Minnesota, and in portions of four counties in northwestern Illinois. The company also engages in the distribution and sale of natural gas in Albert Lea, Minnesota; Clinton, Mason City and Clear Lake, Iowa; Fulton and Savanna, Illinois and in a number of smaller Minnesota, Iowa and Illinois communities, and in the transportation of natural gas within Iowa, Minnesota and in interstate commerce. For information pertaining to industry segments and lines of business please refer to pages 26 and 27 of Exhibit EX-13 (the Annual Report to Stockholders). (Construction Program) The table below shows actual construction expenditures for 1994 and estimated expenditures for the period 1995 through 1999: (Thousands of Dollars) 1994 Actual $ 40,600 1995 Est. $ 29,500 1996 Est. $ 40,400 1997 Est. $ 37,200 1998 Est. $ 46,700 1999 Est. $103,500 Refer to (Environmental Regulations) on page 10 for additional information on construction expenditures related to compliance with the regulations of the Clean Air Act of 1990. (Electric Operations) Of the 234 communities served with electricity, Dubuque, Iowa, is the largest with a population of approximately 58,000. Other major cities served are Albert Lea, Minnesota and Clinton and Mason City, Iowa. The remainder of the communities served are under 15,000 population, of which 193 or 84% are less than 1,000 population. The company sells electricity at wholesale to 19 small communities which have municipal distribution systems, 13 of which are total requirements customers, and 6 of which are partial requirements customers. The territory served with electricity at retail by the company is a residential, agricultural and widely diversified industrial area with an estimated population of 338,000. There have been no significant changes since the beginning of the fiscal year in the kind of products produced, services rendered, markets or method of distribution. The facilities owned or operated by the company include facilities for the transmission of electric energy in interstate commerce or the sale of electric energy at wholesale in interstate commerce. (Sources and Availability of Raw Materials) Electricity generated by the company in 1994 was 92.6% from coal as a fuel, 0.3% from oil and 7.1% from natural gas. In 1995, the sources of such generation are estimated to be: 97.3% from coal, 0.6% from middle distillate oils, and 2.1% from natural gas. In 1994, 84.0% of the company's coal requirements came from long-term contracts. In 1995, the company anticipates that 75.8% of its coal requirements will be from long-term contracts. These contracts have expiration dates ranging through August 31, 1999. The company entered into a contract effective March 1, 1995 through August 31, 1999, for a total of 450,000 tons per year of 0.5% sulfur Colorado coal for its Kapp #2, a 217 MW unit at Clinton, Iowa because of sulfur dioxide restrictions mandated by the Clean Air Act Amendments of 1990. The company will purchase coal on an annual basis for the Dubuque Power Plant and for Lansing Units #1, #2 and #3. The company has a contract for 500,000 tons per year for its 260 MW Lansing #4 unit. Lansing Unit #4 requires low sulfur coal, which is being purchased in the Powder River Basin of Wyoming. The company has this coal shipped by rail and then transloaded to barge, using facilities near Keokuk, Iowa. A contract with Orba-Johnson Transshipment Company, Inc., covers rail to barge coal transloading. Coal required for the company's generation by Neal #4 unit, located near Sioux City, Iowa is contracted for by the operator, Midwest Power Systems, under terms of the Unit Participation Agreement. Similar arrangements prevail with respect to the company's participation in Louisa #1 located near Muscatine, Iowa and operated by Iowa-Illinois Gas and Electric Company. The company owns 120 coal cars and has an undivided ownership (21.528%) in 372 coal cars in connection with Neal #4. The company has an undivided ownership (4%) in 136 cars in connection with Louisa #1. Coal requirements in 1995 will require using leased cars for the Louisa #1 coal supply. The company burned 1,110,491 gallons of No. 2 and No. 6 oil in 1994 and has 6,477,000 gallons of oil storage capacity in which to store adequate reserves during periods of high demand on refineries. The company relies on spot purchases of oil. The company presently has interruptible natural gas available for its electric generation station at Clinton, Iowa through Natural Gas Pipeline Company of America. At the Fox Lake and Dubuque plants, interruptible gas is available through Peoples Natural Gas Company. There is no assurance that interruptible gas will continue to be available as fuel for electric generating plants. (Duration and Effect of Electric Patents and Franchises) The company owns no patents. The company has, in the opinion of its legal counsel, all necessary franchises or other rights from the incorporated communities and other governmental subdivisions now served, required for the operation of its properties. With 196 electric franchises in effect in cities and villages, and with the majority of such franchises being for a term of 25 years, the renewal of such franchises is a continuing process. Thirty-two percent (62) of the franchises have been secured since January 1, 1985. (Electric Seasonal Business) The effects of air conditioning in summer and heating in winter have a seasonal impact on the business of the registrant. The air conditioning sales in the summer months are primarily related to the residential and commercial customer classes, however, the company does not meter air conditioning sales separately. During the past five years, the highest and lowest average residential consumption in the peak summer month has been 891 Kwh (July 1991) and 565 Kwh (June 1990), respectively, compared to 811 Kwh (January 1991) and 635 Kwh (February 1990) during the peak winter month. Refer to the section (Electric Governmental Regulations) for discussion of Iowa seasonal rates. (Working Capital Items) Three of the company's generating stations are located on the Mississippi River at Clinton, Dubuque and Lansing, Iowa, with their coal supply being delivered by barge during the barging season (approximately April 1st to December 1st). Coal in the stockpile at December 1st of each year has been sufficient to supply the normal requirements of these generating stations until the reopening of the Mississippi River for barge traffic. Coal shipments to the company's Neal #4 and Louisa #1 generating stations are able to continue year-round because river transportation is not involved. (Electric Governmental Regulations) In August 1993, the company implemented a revised electric tariff structure. The new tariffs give greater weight to the demand component of electric usage, and include a provision for a higher rate during the summer cooling season (June-September), but did not change the company's overall annual electric revenue. The company filed an Iowa electric rate increase application in August 1993. The application requested an annual increase of $11.5 million, including a return on common equity of 12.35%. Interim rates at an annual amount of $11.0 million were placed in effect on October 28, 1993, subject to refund. An IUB order issued in June 1994 allowed an annual increase of $7.4 million based on a return on common equity of 11.0%. A second quarter 1994 entry to record the refund liability included $0.9 million of revenue reduction applicable to the first quarter of 1994 and $0.5 million applicable to the fourth quarter of 1993. Refunds to customers, including $0.2 million of interest, were made in October 1994. In July 1994, the company filed an application with the FERC for an increase in annual firm electric wholesale rates of $1.4 million. In August 1994, in accord with the settlement of a wholesale customer complaint, the company withdrew the rate request. The settlement also required the company to pay the wholesale customers a cash settlement of $0.3 million, and prohibits another firm wholesale rate case with an effective date prior to February 28, 1996. The wholesale customer complaint, which was initially filed in 1992, alleged that the company had been imprudent by entering into certain long-term coal contracts, an associated transloading agreement, and a rail transportation agreement. The company's Minnesota rates recover jurisdictional energy efficiency expenditures and lost revenues. Other operating expenses for 1994, 1993, and 1992 include $0.5, $0.5, and $0.6 million, respectively, for the amortization of Minnesota energy efficiency costs. A May 1994 IUB Order allows recovery of $6.7 million of deferred Iowa energy efficiency costs incurred through December 31, 1992, over a four year period; such recovery began October 1994. Other operating expenses for 1994 include $0.3 million for the amortization of Iowa energy efficiency costs. As of December 31, 1994, and 1993, the total energy efficiency costs deferred were $17.0 and $9.7 million, respectively. Of the $17.0 million total deferred, approximately $11.8 million relates to Iowa energy efficiency costs incurred in calendar 1993 and 1994. The company anticipates filing in late 1995 for recovery of those costs. Management believes that amounts deferred meet the criteria established by the respective commissions for recovery as energy efficiency costs. The company's electric rate tariffs provide for recovery of the cost of fuel through energy adjustment clauses, which clauses are subject to revision from time to time by the regulatory authority having jurisdiction. These clauses are designed to pass on to the consumer the increases or decreases in the cost of fuel without formal rate proceedings. Purchased capacity costs are not recovered from customers through energy adjustment clauses, but rather must be addressed in base rates in a formal rate proceeding. In the company's 1991 Iowa electric rate case, the IUB required that any jurisdictional revenue from capacity sales to other utilities be returned to Iowa customers through the fuel adjustment clause. (Electric Competitive Conditions) In 1993 the Illinois Commerce Commission entered an order determining that Interstate, and not Jo-Carroll Electric Cooperative, had the right to provide electric service to a large new freezer service plant near East Dubuque, IL. The company is providing service to that plant pursuant to Commission order. Jo-Carroll filed for judicial review of the Commission action in the Illinois 15th Judicial Circuit, which court remanded the proceeding to the Commission for further hearings. Proceedings on remand are now pending before the Commission. The Energy Policy Act of 1992 (Act) allows FERC to order utilities to grant access to transmission systems by third-party power producers. The Act specifically prohibits federally-mandated wheeling of power for retail customers. The company's industrial rates generally compare favorably with those of neighboring utilities. For the company's six largest industrial customers, the aggregate 1993 rate was approximately 3.4 cents per KWH. This rate also compares favorably with that of potential independent power producers and electric wholesale generators. The company's favorable rates mitigate the incentive that these customers might otherwise have to relocate, self-generate or purchase electricity from other suppliers. The company anticipates that its generating cost will decline slightly over the next several years as long-term coal purchase and transloading contracts expire and are renegotiated. The company has no competition from the same type of public utility service in the sale of electricity in any of the incorporated communities served by it. Interstate may be subject to competition in unincorporated areas. In the States of Iowa, Illinois and Minnesota, territorial laws govern the question of possible service to customers in such unincorporated areas, and such laws regulate competition in such areas. Laws and statutory regulations in the different states in which service is rendered provide, under varying terms and conditions, for municipal ownership of electric generating plants and distribution systems. Certain franchises under which utility service is rendered give the municipality the right to purchase the system of the company within said municipality upon certain terms and conditions. However, no such purchase option and no right of condemnation of the company's properties has been exercised and no municipal generating plant or municipal distribution system has been established in the territory now served by the company during the past twenty-five years. The Iowa Utilities Board, the Illinois Commerce Commission and the Minnesota Public Utilities Commission have each approved tariffs that allow the company to offer interruptible electric service for qualifying customers. The availability of this service provides price incentives to those customers having the ability to interrupt their connected load. The primary objective of the incentives is to reduce the system peak. The incentives also serve to retain existing customers and attract new customers. (Other Sources of Power) The company has been a participant in the Mid-Continent Area Power Pool (MAPP) Agreement since March 31, 1972. MAPP had a total coincident 1994 summer peak of 23,863 MW at which time the net capacity of the pool was 31,107 MW. Membership in the pool permits sharing of reserve capacities of the members which affects reductions in plant facilities investment for MAPP members. The minimum reserve margin for participants in MAPP has been established at 15%. Parties to the MAPP Agreement include, as participants, 29 electric power suppliers consisting of 10 investor-owned utilities, the United States Department of Interior (Western Area Power Administration), a Canadian system, public power districts and rural electric generating and transmission cooperative associations, municipal electric supply agencies and, as associate participants, 16 other electric power suppliers operating in Canada and in the North Central region of the United States. The pool coordinates planning and operation of power suppliers in Minnesota, Wisconsin, Montana, Iowa, Nebraska, North Dakota and South Dakota and provides reliability and economy for the company's bulk power supply. The MAPP Agreement was filed with the FERC and accepted as an initial rate filing effective December 1, 1972 and has been in operation since that time. In addition to MAPP, the company has interchange connections with certain Missouri and Illinois utilities through 345 KV transmission systems. Future interconnections are planned to meet transmission requirements for the next ten years. In 1992, the company entered into three long-term power purchase contracts with other utilities. The contracts provide for the purchase of 230 to 255 MW of capacity over the period from May 1992 through April 2001. Energy is available at the company's option at approximately 100% to 110% of monthly production costs for the designated units. The three power purchase contracts required capacity payments of $24.6, $24.1, and $16.3 million in 1994, 1993, and 1992, respectively. Over the remaining life of the contracts, total capacity payments will be approximately $155 million. The purchased power contract payments are not for debt service requirements of the selling utility, nor do they transfer risk or rewards of ownership. A portion of the purchased power capacity payments is not presently being recovered through rates: A 1992 rate order by the MPUC held that the company had 100 MW of excess capacity. The Minnesota jurisdictional portion of the 100 MW of disallowed capacity is approximately $1.9 million annually. An additional 25 MW of purchased power contracts became effective after 1992. Annual electric rates do not provide for the recovery of $0.8 and $0.2 million, respectively, applicable to the Iowa and Minnesota jurisdictions. The company has not yet filed for rate recovery of the allocable portions of the purchased power payments in the Illinois and FERC jurisdictions. The annual Illinois and FERC jurisdictional portions are approximately $1.7 and $0.9 million, respectively. The amounts which are not being recovered through rates are expensed as incurred. The impact of not recovering the purchased power payments is mitigated to the extent that load growth has occurred since the last rate case. The company has contracts with several governmental power agencies whereby the company provides transmission service to their customer/members. During 1994, the company received $1,171,806 for transmission service to customers of the Western Area Power Administration (WAPA), and $1,267,322 from Cooperative Power Association (CPA) for wheeling power to nine of its member distribution cooperatives. The company's contract with CPA also provides for payment by the company for needed mutually utilized facilities constructed and owned by CPA. During 1994, these payments amounted to $336,736. The company and Southern Minnesota Municipal Power Agency (SMMPA) have agreed by contract to compensate each other if over/underinvestment in the shared transmission system occurs. During 1994, SMMPA made payments to the company in the amount of $524,700. The company's contract with Central Iowa Power Cooperative (CIPCO) provides for compensation to each other if over/underinvestment in the shared transmission system occurs. During 1994, the company owed CIPCO $59,195 for underinvestment in the Liberty Substation property, of which $41,038 was paid in 1995. (Other Electric Operations) The 1994 peak of 932,081 KW occurred on June 17, 1994 between 2:00 and 3:00 in the afternoon. At the time of its 1994 peak the company had a net effective electric capability of 1,308,600 KW. Of this net effective capability at the time of peak, 901,300 KW was in steam generation, 113,500 KW was in combustion turbine and the balance was in internal combustion units and purchases. The previous historical system net peak load for a sixty-minute period, of 927,366 KW, was reached on August 26, 1993. (Gas Operations) The company supplies retail gas service in 39 communities and serves approximately 48,500 gas customers. There have been no significant changes since the beginning of the fiscal year in the kind of products produced, markets or methods of distribution. (Gas Sources and Availability of Raw Materials) The natural gas industry was recently restructured as a result of Order 636, issued by the Federal Energy Regulatory Commission (FERC) on April 8, 1992. This Order required the interstate pipelines to provide transportation capacity unbundled (separated) from the sales of gas supply, as well as to provide open access to their storage facilities. The company no longer purchases a bundled gas supply from Northern Natural Gas Company (NNG) and Natural Gas Pipeline Company of American (NGPL). The company purchases pipeline capacity (space) from these companies to deliver a gas supply purchased from others. During 1994 the company purchased gas from eleven non- traditional suppliers, i.e. producers, brokers and marketers, at market responsive rates. The FERC continues to approve the tariffs of NNG and NGPL, but only with regard to capacity and storage rates, subject to change as rate cases are filed. A section of the Order permits the interstate pipelines to pass on industry transition costs to their customers. Transition costs are comprised of gas supply realignment costs, unrecovered gas cost, stranded costs and new facilities costs. As a customer of NGPL and NNG, Interstate is subject to a share of those costs. The FERC has approved the Order 636 Settlements between NNG, NGPL and their customers. Gas for the company's Mason City, Albert Lea and Savanna service areas is transported by NNG under capacity contracts for 36,533 Mcf daily, and for an additional 15,657 Mcf in the November to March time frame. The majority, 27,194 Mcf, of the above capacities is from the producing areas of New Mexico, Oklahoma and Texas, etc. These contracts expire in October, 1997. Gas is supplied by producers, marketers and brokers, as well as from storage services, to meet the peak heating season requirements. The Company had 22,302 Mcf/day of storage, with the necessary pipeline capacity, available for the 1994-1995 heating season. Gas for its Clinton service area is transported by NGPL under capacity contracts for 19,751 Mcf annually, with expiration dates of December 1, 1995 (6,949), December 1, 1995 (2,832), February 28, 1996 (4,970), and November 30, 1996 (5,000). This gas is supplied by producers, marketers and brokers. The company supplements this capacity with storage gas, which has the pipeline capacity embedded in its FERC approved rate. The company had 11,779 Mcf of storage available for the 1994-1995 heating season. During 1994, the company utilized approximately 39.2% of its annualized daily contract gas available from its firm suppliers. The Company's total throughput level of 33,653,839 Mcf represents a 1.0% decrease for 1994, as compared to 1993. The total throughput was composed of contract supply gas (26.3%), spot gas (0.9%) and customer transportation gas (72.8%). During 1994, eighteen of Interstate's customers transported a total of 24,498,793 Mcf of their own gas over the company's pipeline and distribution systems. In 1992, sixteen of Interstate's customers transported a total of 23,547,107 Mcf, and in 1993, nineteen customers transported a total of 23,994,891 Mcf. The customer owned gas was delivered by interstate pipeline companies for those customers' accounts to Interstate's town border stations, and is subsequently delivered to the customers under tariffs approved by respective state commissions. Company policy is to assist any customer in exploring its options relative to purchasing gas directly from the producing sector. The Company owns propane-air gas plants in Albert Lea, Minnesota and Clinton and Mason City, Iowa. The daily output capacities are: 5,500 Mcf, 4,000 Mcf and 9,600 Mcf of propane-air mix gas respectively. The requirement for gas on the peak winter day of the 1993-1994 season was 128,041 Mcf, including both firm and interruptible customers. This peak consisted of 38.2% jurisdictional sales gas, 0.0% spot gas, 37.3% customer purchased gas, 23.7% storage gas and 0.8% propane-air from the company's peak-shaving plant. The maximum daily firm gas sales during the 1993-1994 season were as follows: Albert Lea 15,826 Mcf; Savanna 2,950 Mcf; Clinton 26,523 Mcf; Mason City 33,073 Mcf, or 61.2% of the peak winter day throughput. (Duration and Effect of Gas Patents and Franchises) The company owns no patents. The company has, in the opinion of its legal counsel, all necessary franchises or other rights from the incorporated communities and other governmental subdivisions now served, required for the operation of its properties. With 34 gas franchises in effect in cities and villages, and with the larger majority of such franchises being for a term of 25 years, the renewal of such franchises is a continuing process. Fifty percent (17) of the franchises have been secured since January 1, 1985. (Gas Seasonal Business) The effects of heating sales to the residential and commercial classes of customers have a significant seasonal impact on the business of the registrant. The heating sales in the winter months account for 98% of the total annual sales to these classes of customers. The average consumption for a residential customer during the peak winter months is 18.6 Mcf compared to the average of 2.6 Mcf during the summer. The average consumption for a commercial customer during the peak winter months is 90.6 Mcf compared to the average of 13.2 Mcf during the summer. (Gas Governmental Regulations) Order 636 provides a mechanism under which pipelines can recover prudently incurred transition costs associated with the restructuring process. The company's pipeline suppliers have filed with the FERC to recover transition costs from the local distribution companies. The company incurred $2.1 million of transition costs in 1994 and is currently recovering these costs from customers through the purchased gas adjustment clause. While the ultimate level of transition costs could vary as Order 636 filings are revised and proceedings completed, the company estimates that the remainder will aggregate approximately $5.2 million payable in declining installments from 1995 to 2004. The company anticipates that under customary ratemaking practices, future transition costs will be recovered from customers, and has recorded on its balance sheet a liability and a corresponding regulatory asset in the amount of $5.2 million. (Gas Competitive Conditions) The company has no competition from the same type of public utility service in the sale of gas in any of the incorporated communities serviced by it. Certain major industrial customers of the company purchase their own gas supply from producers and have that gas transported by the company as described in the "Gas Sources and Availability of Raw Materials" section. Laws and statutory regulations in the different states in which service is rendered provide, under varying terms and conditions, for municipal ownership of distribution systems. Certain franchises, under which utility service is rendered, give the municipality the right to purchase the system of the company within said municipality upon certain terms and conditions. However, no such purchase option and no right of condemnation of the company's properties has been exercised and no municipal distribution system has been established in the territory now serviced by the company during the past twenty-five years. (Dependence of Segment Upon a Single Customer) In 1994, 1993 and 1992, the company had no single customer or industry for which electric and/or gas sales accounted for 10% or more of the company's consolidated revenues. In 1994, the company's three largest industrial customers accounted for 1,339,433,851 Kwh of electric sales ($43,779,424) and 22,523,696 Mcf of gas sales and transportation ($2,155,958). The company's largest gas customer, which represents 30% of the company's total gas throughput, is committed by contract for the next seven years. (Research and Development) The company has no full-time professional employees engaged in research activities and had no company-sponsored research programs during 1994, 1993 and 1992. In the public utility industry, research is commonly and traditionally done by manufacturers of equipment, trade organizations to which the company belongs, and university research programs. In 1994 approximately $1,072,871 was paid for research activities compared with $1,090,184 in 1993 and $1,013,003 in 1992. (Electric and Magnetic Fields) The possibility that exposure to electric and magnetic fields emanating from power lines and other electric sources may result in adverse health effects has been a subject of increased public, governmental and media attention. A considerable amount of scientific research has been conducted on this topic with no definitive results. Research is continuing. It is not possible to tell what, if any, impact these actions may have on the company's financial condition. (Environmental Regulations) The company is subject to various federal and state government environmental regulations. The company meets existing air and water regulations. The Federal Clean Air Act Amendments of 1990 requires reductions in certain emissions from power plants. The legislation has two deadlines for compliance, Phase 1 (January 1, 1995) and Phase 2 (January 1, 2000). The company has switched to a low sulfur coal and installed low nitrogen oxide burners at the 217 MW plant affected by Phase 1. Additional capital expenditures of $11 million will be required in 1995 and 1996 to comply with environmental standards applicable to power plants. Management anticipates that additional costs incurred will be recovered through customer rates. The United States EPA, via the Clean Water Act, and the states have promulgated discharge limits necessary to meet water quality standards. A National Pollutant Discharge Elimination System (NPDES) permit is required for all discharges. The company has current NPDES permits for all discharges and meets or or falls within the required discharge limits. Early this century, various utilities including the company operated plants which produced manufactured gas for cooking and lighting. The company's facilities ceased operations approximately 40 years ago when natural gas pipelines were extended into the upper Midwest. Some of the former gasification sites contain coal tar waste products which may present an environmental hazard. In 1957, the company purchased facilities in Mason City, Iowa, from Kansas City Power & Light Company (KCPL) which included land previously used for a coal gasification plant. Coal tar waste was discovered on the property in 1984. A Remedial Investigation and a Feasibility Study have been approved by the U.S. EPA, and the company anticipates that remediation will begin in 1995 following U.S. EPA designation of the clean-up process. The Federal District Court ruled in 1993 that KCPL is liable to the company regarding the response costs at the Mason City site. (KCPL is an A rated company with total assets in excess of $2 billion.) Additional court proceedings will be held in 1995 to determine the extent of that liability. The company anticipates that it may incur additional costs to clean-up the site, but that such costs should be recoverable from KCPL or from gas customers. In 1994, the company recorded an additional $2.3 million liability for the estimated clean-up costs, and based on the current regulatory treatment, an equal regulatory asset. The company did not expense any investigation and remediation costs related to the Mason City site in 1994 or 1993; it has expensed $2.5 million of investigation and remediation costs applicable to the site since the discovery of the coal tar waste. The company formerly operated a manufactured gas plant in Rochester,Minnesota. This facility was sold to another utility, which later demolished the plant. The site is currently owned by a utility and the City of Rochester. Agreements have been reached between the Minnesota Pollution Control Agency and all three parties noted above regarding the clean-up process. The remediation process began in 1994 and is expected to be completed in early 1995. Pursuant to the settlements described above, with total cost not to exceed $9.662 million, the company has agreed to pay approximately two-thirds of the cost of investigation and clean-up. The company accrued (expensed) $0.8, $3.5, $1.2, and $0.2 million in 1994, 1993, 1992, and 1991, respectively. In addition, the company has identified, or has been identified, as an owner or operator of seven other manufactured gas plant sites in the Midwest: sites in Savanna and Galena, Illinois; a site in Clinton, Iowa; and sites in Albert Lea, Austin, New Ulm and Owatonna, Minnesota. The Savanna, Illinois, and Clinton, Iowa, sites are currently owned by the company; the remaining sites are owned by third parties. Potentially hazardous wastes allegedly associated with former coal gasification operations have been identified at all sites. Investigation of site conditions are in various stages at all of the sites. The company's accrued environmental liabilities of $3.5 million at December 31, 1994, will cover known expenses for investigative and remediation work. Additional liabilities, if any, cannot be determined until further investigative work is performed. In 1994, the company filed a lawsuit against certain of its insurers to recover the costs of investigating and cleaning up, as necessary, the former coal gasification plants. Neither the company nor its legal counsel is able to predict the amount of any insurance recovery, and accordingly, no potential recovery has been recorded. Previous actions by Iowa, Illinois, and Minnesota regulators have permitted utilities to recover prudently incurred investigation, remediation and legal costs (response costs). The company anticipates that costs applicable to the Iowa and Illinois jurisdictions will be recovered from customers. Effective February 1993, a representative level of investigation, remediation and legal costs of $0.7 million per year applicable to the two Iowa sites is being recovered from customers through gas rates. Investigation and remediation costs through December 31, 1993, have been charged to expense. In accordance with the established practice of the Iowa Utilities Board (IUB), the 1994 accrual of $2.3 million for future remediation costs has been offset by a regulatory asset. Such costs will be charged to expense as they are incurred in the future. The company's Illinois electric and gas tariffs provide for a rider to recover prudently incurred investigation and remediation costs. In 1994, $0.3 million of costs applicable to Illinois were charged to a regulatory asset and will be amortized to expense as they are recovered from customers beginning in 1995. While the company is currently seeking an accounting order which would allow the deferral of a portion or all of the remediation costs applicable to its Minnesota jurisdiction, it may be difficult for the company to recover all costs applicable to the Minnesota sites. The MPUC has indicated that this type of cost should not be shared by electric customers, and the company has relatively few Minnesota gas customers. To-date, all estimated Minnesota jurisdictional costs have been charged to expense. Under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), a past waste generator can be designated by the United States Environmental Protection Agency (U.S. EPA) as a Potentially Responsible Party (PRP). Certain types of used transformer oil (primarily those containing polychlorinated biphenyls, or "PCBs") have been designated as hazardous substances by the U.S. EPA. The company has been cited as a PRP by the U.S. EPA for the clean-up of the facilities formerly operated by Martha C. Rose Chemicals, Inc. in Holden, Missouri. Clean-up of the site began in 1994, with final completion scheduled for early 1995. The Martha Rose Chemical Steering Committee has estimated that total clean-up cost may be up to $22.8 million. The company's proportionate share of clean-up costs has been $0.3 million to-date. The Steering Committee has indicated that it has more than adequate funds to complete the clean-up. In 1988, the U.S. EPA designated the company a PRP for the clean-up of former salvage facilities operated by the Missouri Electric Works, Inc. (MEW) in Cape Girardeau, Missouri. A portion of the PCB-contaminated equipment found at the site was formerly owned by the company. The company has notified the U.S. EPA that it disclaims responsibility for the site, as the equipment was in proper operating condition when sold by the company to a third party, which subsequently made arrangements to transport this equipment to MEW. The U.S. EPA has not responded to the company's disclaimer. The company has not recorded any liability for the MEW site, and management believes that it will be able to successfully defend itself against any claims applicable to the site. (Employees) The company has 978 regular employees consisting of 940 full-time and 38 part-time employees. (Accounting Matters) The company adopted SFAS No. 106, "Accounting for Postretirement Benefits Other Than Pensions" in 1993. SFAS 106 requires that the cost of providing such future postretirement benefits be accrued over the employees' service periods. The postretirement benefit obligation at January 1, 1993 (transition obligation) was $30.9 million and is being amortized over a 20 year period. The annual SFAS 106 cost for 1994 and 1993 was $4.9 million with the pay-as-you- go amount of $1.9 and $1.7 million, respectively. Recovery of SFAS 106 costs must be addressed in rate proceedings. The Iowa Utilities Board (IUB) allowed recovery of $0.3 million per year of additional SFAS 106 expense in gas rates effective May 1993, and the recovery of $1.6 million in electric rates effective November 1993. The company has deferred the difference between the SFAS 106 costs and the pay- as-you-go amount applicable to the FERC electric and Minnesota electric and gas jurisdictions until rate cases are filed to recover the additional costs. Based on precedent established by the FERC and Minnesota Public Utilities Commission (MPUC), the company believes that amounts deferred as of December 31, 1994, meet the criteria established by the Financial Accounting Standards Board. SFAS 106 costs in excess of the pay-as-you-go amount included on the balance sheet as regulatory assets were $2.6 million at year-end 1994 and 1993. In Illinois, SFAS 106 costs are expensed currently since deferral accounting is not allowed. ITEM 2. PROPERTIES The principal power plants and other materially important physical properties of the Company are maintained in accordance with sound operating practices. Their general character and location are described below: (Electric Properties) The Company has been a participant in the Mid-Continent Area Power Pool (MAPP) Agreement since March 31, 1972. As a part of this power network the Company is the owner of a 55.0 mile section of the 345 KV transmission line extending from St. Louis, Missouri to Minneapolis, Minnesota; a 15.5 mile section of the 345 KV transmission line between Minneapolis, Minnesota and Kansas City, Missouri; a 5.0 mile 345 KV transmission line from near Clinton, Iowa to near Cordova, Illinois; a 49.8 mile 345 KV transmission line from near Clinton, Iowa to a substation south of Dubuque, Iowa; and three associated 345/161 KV substations. The Company's electric generating stations at year-end consist of six steam plants, three combustion turbine stations, and five internal combustion facilities. Pertinent information regarding each electric generating station is shown on the following page: INTERSTATE POWER COMPANY GENERATING STATIONS Net Generating Units December 31, 1994 Output Nameplate Capability in KWH Unit Capacity Year KW KW (000's) Location Number KW Installed (Gross) (Net) 1994 STEAM: Dubuque, IA 2 15,000 1929 82,500 78,000 151,312 3 25,000 1952 4 33,000 1959 Clinton, IA 1 15,000 1947 254,900 235,000 973,638 (M.L.Kapp Plt.) 2 212,284 1967 Lansing, IA 1 15,000 1948 337,800 320,000 837,454 2 11,500 1949 3 33,000 1957 4 252,649 1977 Sherburn, MN 1 11,500 1950 113,500 108,000 267,653 (Fox Lake Plt.) 2 11,500 1951 3 75,000 1962 Sioux City, IA 4* 125,924 1979 142,000 134,300 1,006,325 (Neal Unit #4) Louisa County, IA 1** 27,400 1983 28,400 27,000 172,353 (Louisa Unit #1) TOTAL STEAM 959,100 902,300 3,408,735 GAS TURBINE: Montgomery, MN 1 26,535 1974 22,200 22,200 611 Sherburn, MN 4 26,535 1974 21,300 21,300 321 (Fox Lake Plt.) Mason City, IA 1 37,520 1991 70,400 70,000 2,073 (Lime Creek Plt.) 2 37,520 1991 TOTAL GAS TURBINE 113,900 113,500 3,005 INTERNAL COMBUSTION: Dubuque, IA 1 2,000 1966 4,600 4,600 (83) 2 2,000 1966 Hills, MN 2 2,000 1960 2,000 2,000 (63) Lansing, IA 1 1,000 1970 2,000 2,000 5 2 1,000 1971 New Albin, IA 1 685 1970 700 700 (34) Rushford, MN 1 2,000 1961 2,000 2,000 (88) TOTAL INTERNAL COMBUSTION 11,300 11,300 (263) TOTAL COMPANY 1,084,300 1,027,100 3,411,477 * Interstate owns 21.528% of a 584,931 KW unit operated by Midwest Re- sources. ** Interstate owns 4.0% of a 685,000 KW unit operated by Iowa-Illinois Gas and Electric Company. (Gas Properties) The company owns and operates natural gas distributing systems in Albert Lea, Minnesota; Savanna, Illinois; Clinton, Mason City and Clear Lake, Iowa and in a number of smaller Minnesota, Illinois and Iowa communities. At Albert Lea, the company owns 14 tanks with a liquid propane storage capacity of 357,000 gallons; at Clinton, there are 12 tanks with 306,000 gallons capacity and at Mason City, 22 tanks with 561,000 gallons capacity. The company also owns 100 gas regulating stations and approximately 966 miles of gas distribution mains. (General Properties) The company owns numerous miscellaneous properties in various parts of its territory which are used for office, service and other purposes. The most important of these are three General Office buildings in Dubuque and the district office buildings at Clinton, Decorah, Dubuque, Mason City and Oelwein, Iowa and Albert Lea, and Winnebago, Minnesota and the distribution service buildings in each of those locations. The company, as lessee, leases office space at various locations. The company also leases a few small parcels of land for storage of poles and miscellaneous temporary uses. (Titles) In the opinion of legal counsel for the company, the company has satisfactory title to its properties for use in its utility businesses subject only to permitted liens as defined in the Bond Indenture and to minor defects and encumbrances customarily found in cases of like size and character and which do not materially interfere with the use of such properties. Properties such as electric transmission and electric and gas distribution lines are constructed principally on rights-of-way which are maintained under franchise or held by easement only. All properties of the company, other than "excepted property" as defined in the Bond Indenture, are subject to the lien of the company's Bond Indenture dated as of January 1, 1948, as supplemented, securing the company's outstanding First Mortgage Bonds. ITEM 3. LEGAL PROCEEDINGS Reference is made to "Electric Governmental Regulations", "Electric Competitive Conditions" and "Environmental Regulations" under "Item 1. Business" for certain pending legal proceedings and proceedings known to be contemplated by governmental authorities. Reference is also made to Note 9 to Financial Statements of the Annual Report to Stockholders, included herein as EX-13. Other than these items, there are no material pending legal proceedings, or proceedings known to be contemplated by governmental authorities, other than ordinary routine litigation incidental to the business, to which the company is a party or of which any of the company's property is the subject. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There was no submission of matters to a vote of security holders during the fourth quarter of the 1994 year. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS For information pertaining to common stock market data required by Item 201 of Regulation S-K please refer to page 32 of Exhibit EX-13 (the Annual Report to Stockholders). ITEM 6. SELECTED FINANCIAL DATA For information pertaining to selected financial data required by Item 301 of Regulation S-K please refer to page 31 of Exhibit EX-13 (the Annual Report to Stockholders). ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS For information pertaining to management's discussion and analysis required by Item 303 of Regulation S-K please refer to pages 1 through 11 of Exhibit EX-13 (the Annual Report to Stockholders). ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Financial statements and supplementary data incorporated by reference to Exhibit EX-13 (the Annual Report to Stockholders for 1994): Statements of Income and Retained Earnings Page 12 Statements of Cash Flows Page 13 Balance Sheets Pages 14 & 15 Statements of Capitalization Page 16 Notes to Financial Statements Pages 17 - 28 Independent Auditors' Report Page 29 ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT Name Age Offices Held Past 5 Years W. H. Stoppelmoor 61 1-1-87 - President & Chief Executive Officer 5-1-90 - President, Chief Executive Officer & Chairman of the Board M. R. Chase 56 1-1-91 - Vice President-Production 5-7-91 - Vice President-Power Production A. D. Cordes 63 1-1-86 - Vice President-District Administration 5-1-90 - Vice President-District Administration & Public Affairs R. R. Ewers 50 5-1-90 - Vice President-Administrative Services D. E. Hamill 58 9-1-80 - Vice President-Budgets & Regulatory Affairs G. L. Kopischke 63 9-1-80 - Vice President-Electric Operations J. C. McGowan 57 2-1-89 - Secretary & Treasurer R. P. Richards 58 1-1-91 - Vice President-Gas Operations W. C. Troy 56 5-1-86 - Controller All officers are elected and serve as such until the next annual meeting of directors. There are no arrangements or understandings with respect to election of any person as an officer. For information pertaining to directors, and other data required by Items 401 and 405 of Regulation S-K, refer to pages 3 through 6 of the company's Official Proxy Statement filed with the Securities and Exchange Commission on March 21, 1995. ITEM 11. EXECUTIVE COMPENSATION Refer to information on pages 8, 9, 10, 11 and 12 of the company's Official Proxy Statement filed with the Securities and Exchange Commission on March 21, 1995 for data required by Item 402 of Regulation S-K. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Refer to information on pages 6 and 7 of the company's Official Proxy Statement filed with the Securities and Exchange Commission on March 21, 1995 for data required by Item 403 of Regulation S-K. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Transactions with Management and Others: In 1994 there were no transactions and there are presently proposed no transactions with management, to which the company or its subsidiary was or is to be a party, of the character as to which answer is called for in response to Item 404(a) of Regulation S-K. Indebtedness of Management: No director or officer, or nominee for election as a director, or any associate of any thereof, was indebted to the company or its subsidiary during 1994, as to which answer is called for in response to Item 404(b) of Regulation S-K. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) List of documents filed as part of this report: 1. The financial statements, including supporting schedules, are listed in the Index to Financial Statements, Schedules and Exhibits filed as part of this Annual Report. 2. Exhibits which are filed herewith, including those incorporated by reference are listed in the Index to Financial Statements, Schedules and Exhibits filed as part of this Annual Report. (b) Reports on Form 8-K: No reports on Form 8-K were filed with the Securities and Exchange Commission during the last quarter of 1994. INDEX TO FINANCIAL STATEMENTS, SCHEDULES AND EXHIBITS The 1994, 1993 and 1992 financial statements, together with the Independent Auditors' Report thereon of Deloitte & Touche LLP, dated February 2, 1995, appearing on pages 12 through 29 of Exhibit EX-13 (the 1994 Annual Report to Stockholders), are incorporated in this Form 10-K Annual Report. The following additional data, as attached on EX-23.a, EX-23.b, and S-1 should be read in conjunction with the financial statements in such Exhibit EX-13. Schedules and other historical financial information not included with this additional financial data have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. Page or Exhibit Reference Exhibit EX-13 Form (Annual Report to 10-K Stockholders) Report of Independent Auditors EX-23.a Consent of Independent Auditors EX-23.b Financial Statements: Statements of Income and Retained Earnings for the years ended December 31, 1994, 1993 and 1992 12 Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992 13 Balance Sheets, December 31, 1994 and 1993 14 & 15 Statements of Capitalization, December 31, 1994 and 1993 16 Notes to Financial Statements 17 - 28 Selected Financial Data 31 Common Stock Market Data 32 Management's Discussion and Analysis 1 - 11 Schedule II: Valuation and Qualifying Accounts and Provisions S-1 INDEX TO FINANCIAL STATEMENTS, SCHEDULES AND EXHIBITS (CONT'D.) Exhibits filed as part of this report: EX-4 Statement regarding availability upon request of Loan Agreement and Pollution Control Indenture. EX-10.a Coal Supply Agreement between Interstate Power Company and Powderhorn Coal Company filed under Form SE as confidential and non-public. EX-13 The Company's 1994 Annual Report to Stockholders. EX-23.a Report of Independent Auditors EX-23.b Consent of Independent Auditors EX-27 Financial Data Schedule EX-99.a Listing of current material contracts, indentures and other exhibits and identified as having been previously filed with the Commission. 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. INTERSTATE POWER COMPANY Date March 16, 1995 By /s/ W. H. STOPPELMOOR (W. H. Stoppelmoor, President and Chief Executive Officer) 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 date indicated. Signature Title /s/ W. H. STOPPELMOOR President and Chief Executive (W. H. Stoppelmoor) Officer (Principal Executive Officer and Principal Financial Officer) /s/ W. C. TROY Controller (Principal (W. C. Troy) Accounting Officer) /s/ A. B. ARENDS Director (A. B. Arends) Director (J. E. Byrns) /s/ A. D. CORDES Director (A. D. Cordes) /s/ J. L. HANES Director (J. L. Hanes) /s/ G. L. KOPISCHKE Director (G. L. Kopischke) /s/ N. J. SCHRUP Director (N. J. Schrup) Date March 16, 1995 SCHEDULE II INTERSTATE POWER COMPANY VALUATION AND QUALIFYING ACCOUNTS AND PROVISIONS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 (Thousands of Dollars) COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ADDITIONS BALANCE AT CHARGED CHARGED DEDUCTION BALANCE BEGINNING TO TO OTHER FROM AT END DESCRIPTION OF YEAR INCOME ACCOUNTS RESERVES OF YEAR YEAR ENDED DEC. 31, 1994 Valuation account deducted from caption of which it applies - accumulated provision for doubtful accounts $203 $243 $148 (a) $394 (b) $200 Provision for medical benefits, injuries and damages $4,105 $7,240 $2,757 $9,431 (c) $4,671 YEAR ENDED DEC. 31, 1993 Valuation account deducted from caption of which it applies - accumulated provision for doubtful accounts $206 $225 $134 (a) $362 (b) $203 Provision for medical benefits, injuries and damages $1,506 $4,302 $3,521 $5,224 (c) $4,105 YEAR ENDED DEC. 31, 1992 Valuation account deducted from caption of which it applies - accumulated provision for doubtful accounts $206 $152 $115 (a) $267 (b) $206 Provision for medical benefits, injuries and damages $1,655 $4,103 $838 $5,090 (c) $1,506 (a) Recoveries on accounts previously written off. (b) Accounts written off. (c) Claims and damages paid and expenses in connection therewith. S-1 INDEX OF EXHIBITS EX-4 Statement regarding availability upon request of Loan Agreement and Pollution Control Indenture. EX-10.a Coal Supply Agreement between Interstate Power Company and Powderhorn Coal Company filed under Form SE as confidential and non-public. EX-13 The Company's 1994 Annual Report to Stockholders. EX-23.a Report of Independent Auditors EX-23.b Consent of Independent Auditors EX-27 Financial Data Schedule EX-99.a Listing of current material contracts, indentures and other exhibits and identified as having been previously filed with the Commission. EX-4 2 EX-4 Subject to the Commission's Rule 447 under the Securities Act of 1933 and Rule 12b-32 under the Securities Exchange Act of 1934 exempting the filing of instruments defining rights of the holders of long-term debt not being registered in those cases where the total amount of securities authorized thereunder does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis if there is filed an agreement to furnish a copy of such agreement to the Commission upon request, the company agrees to furnish upon request by the Commission a copy of the following: Clinton Series A Bonds Loan Agreement dated as of June 1, 1994 from Clinton to Interstate Power Company (the "Company"). Indenture of Trust dated as of June 1, 1994 between Clinton and Norwest Bank Iowa, N.A. as trustee (the "Trustee"). Clinton Series B Bonds Loan Agreement dated as of June 1, 1994 between Clinton and the Company. Indenture of Trust dated as of June 1, 1994 between Clinton and the Trustee. Lansing Series A Bonds Loan Agreement dated as of June 1, 1994 between Lansing and the Company. Indenture of Trust dated as of June 1, 1994 between Lansing and the Trustee. Lansing Series B Bonds Loan Agreement dated as of June 1, 1994 between Lansing and the Company. Indenture of Trust dated as of June 1, 1994 between Lansing and the Trustee. INTERSTATE POWER COMPANY /s/ J. C. McGowan J. C. McGowan, Secretary-Treasurer Dated: February 9, 1995 EX-10 3 EX-10.a COAL SUPPLY AGREEMENT BETWEEN INTERSTATE POWER COMPANY AND POWDERHORN COAL COMPANY (A Confidential Agreement) FORM SE FILED ON MARCH 22, 1995 EX-13 4 EX-13 INTERSTATE POWER COMPANY Annual Report to Stockholders 1994 MANAGEMENT'S DISCUSSION AND ANALYSIS The company's results of operations and financial condition are affected by numerous factors, including weather, general economic conditions, and rate changes. The following comments are designed to explain the financial statements on pages 12-28 and the financial and statistical data on pages 31 and 32. LIQUIDITY AND CAPITAL RESOURCES The company's primary capital requirements include construction activities, payment of dividends, and the funding of debt retirements. It is management's opinion that the company has adequate access to capital markets and will be able to satisfy anticipated capital requirements. The dividend of $2.08 per common share annually and $0.52 per quarter has been maintained, however, the Board of Directors will be monitoring future dividend levels and a reduction cannot be ruled out. Uncertainty as to the continuation of the current dividend level, rising interest rates and greater perceived risk associated with increased competition in the electric industry contributed to a decline in the company's stock price from $30.125 at year-end 1993 to $23.75 at year-end 1994. To reduce the need for outside financing in 1995 and raise earnings to an acceptable level, the company cut back its construction program, is reviewing cost control procedures, and plans to file for rate increases in the Iowa, Minnesota, and FERC jurisdictions. Effective December 1994, the company elected to purchase shares of common stock for the Dividend Reinvestment and Stock Purchase Plan on the open market rather than issuing new stock. The company received $4.2 million for 174,446 shares of new common stock issued in the first eleven months of 1994 and $2.8 million for 92,093 shares issued in the third and fourth quarters of 1993. Construction expenditures were $41, $34, and $32 million in 1994, 1993, and 1992, respectively. A major construction project in 1994 included $4.5 million for low nitrogen oxide (NOX) burners (pollution control equipment required to comply with Phase 1 of the Clean Air Act), at the company's Kapp power plant. The 1995 and 1996 construction programs are estimated to be $30 and $41 million, respectively. There will be several pollution control projects, including $3.6 million for additional low NOX burners, $3.5 million for fly ash disposal facility improvements, and $1.6 million for sulfur trioxide conditioning. The company anticipates that approximately 75% of the construction funds for years 1995 and 1996 will be generated internally. For the five year period from 1995 through 1999, construction expenditures are estimated to be $250 million. In mid-1994, the company refinanced $13.25 million of Pollution Control Revenue Bonds at interest rates ranging from 5.75% to 6.35%. The refinancing will reduce annual cash outlays for interest by approximately $120,000. A second quarter 1993 refinancing of first mortgage bonds and preferred stock resulted in lower annual interest charges of approximately $285,000 and reduced annual cash outlays for preferred and preference dividends by approximately $520,000. At December 31, 1994, based upon the most restrictive earnings test contained in the company's Indenture pursuant to which first mortgage bonds are issued, the company could issue in excess of $100 million of additional first mortgage bonds. The company's ratio of earnings before income taxes to interest charges (fixed charge coverage) was 2.7 times for 1994, 1993, and 1992. At December 31, 1994, the ratio of common equity to total capitalization was 46.2%. The company's long-term goal is to increase common equity to approximately 50% of total capitalization. The increase in common equity is expected to be accomplished over time. A common stock public offering of approximately $25 million, originally planned for 1995, has been delayed to 1996. Also, the company intends to resume the issuance of new stock in 1996 to satisfy Dividend Reinvestment and Stock Purchase Plan requirements. Ratings for the company's first mortgage bonds did not change in 1994. The company's bonds are rated A+ by Standard and Poor's rating agency and A1 by Moody's Investors Service. The rating agencies have indicated that future ratings will be more stringent due to changes in the business environment, slow growth in demand, growing cost pressures, and the regulatory climate in which the company operates. The company has authorization from the Federal Energy Regulatory Commission (FERC) to issue up to $70 million in short-term debt. At year-end 1994, a $43.3 million line of credit was available. Lines of credit are generally used in support of commercial paper, which is the primary source of short-term financing. At year-end 1994, the company had $35.6 million of short-term commercial paper payable. The company anticipates that, due to construction outlays and the retirement of $14 million of 4 5/8% First Mortgage Bonds which mature on May 1, short-term debt will increase to approximately $52 million by year-end 1995. The company projects that the short-term debt will decline to $37 million at year-end 1996. Electric and gas rates include a fuel adjustment clause and a purchased gas adjustment clause whereby increases or decreases in fuel and purchased gas costs are included in current revenue without having changes in base rates approved in formal hearings. Under present regulations, electric capacity costs are not recovered from customers through fuel adjustment clauses, but rather must be addressed in base rates in a formal rate proceeding. However, any Iowa jurisdictional revenue from electric capacity sales to other utilities is returned to customers through the fuel adjustment clause. The company is subject to regulation which recognizes only original cost rate base. This may result in economic losses when the effects of inflation are not recovered from customers on a timely basis. ACCOUNTING STANDARD ON POSTRETIREMENT BENEFITS - SFAS No. 106 The company adopted SFAS No. 106, "Accounting for Postretirement Benefits Other Than Pensions" in 1993. SFAS 106 requires that the cost of providing such future postretirement benefits be accrued over the employees' service periods. The postretirement benefit obligation at January 1, 1993 (transition obligation) was $30.9 million and is being amortized over a 20 year period. The annual SFAS 106 cost for 1994 and 1993 was $4.9 million, compared with the pay-as-you-go amount of $1.9 and $1.7 million, respectively. Recovery of SFAS 106 costs must be addressed in rate proceedings. The Iowa Utilities Board (IUB) allowed recovery of $0.3 million per year of additional SFAS 106 expense in gas rates effective May 1993, and the recovery of $1.6 million in electric rates effective November 1993. The company has deferred the difference between the SFAS 106 costs and the pay-as-you-go amount applicable to the FERC electric and Minnesota electric and gas jurisdictions until rate cases are filed to recover the additional costs. Based on precedent established by the FERC and Minnesota Public Utilities Commission (MPUC), the company believes that amounts deferred as of December 31, 1994, meet the criteria established by the Financial Accounting Standards Board. SFAS 106 costs in excess of the pay-as-you-go amount included on the balance sheet as regulatory assets were $2.6 million at year-end 1994 and 1993. In Illinois, SFAS 106 costs are expensed currently since deferral accounting is not allowed. POWER PURCHASE CONTRACTS In 1992, the company entered into three long-term power purchase contracts with other utilities. The contracts provide for the purchase of 230 to 255 MW of capacity over the period from May 1992 through April 2001. Energy is available at the company's option at approximately 100% to 110% of monthly production costs for the designated units. The three power purchase contracts required capacity payments of $24.6, $24.1, and $16.3 million in 1994, 1993, and 1992, respectively. Over the remaining life of the contracts, total capacity payments will be approximately $155 million. The purchased power contract payments are not for debt service requirements of the selling utility, nor do they transfer risk or rewards of ownership. A portion of the purchased power capacity payments is not presently being recovered through rates: A 1992 rate order by the MPUC held that the company had 100 MW of excess capacity. The Minnesota jurisdictional portion of the 100 MW of disallowed capacity is approximately $1.9 million annually. An additional 25 MW of purchased power contracts became effective after 1992. Annual electric rates do not provide for the recovery of $0.8 and $0.2 million, respectively, applicable to the Iowa and Minnesota jurisdictions. The company has not yet filed for rate recovery of the allocable portions of the purchased power payments in the Illinois and FERC jurisdictions. The annual Illinois and FERC jurisdictional portions are approximately $1.7 and $0.9 million, respectively. The amounts which are not being recovered through rates are expensed as incurred. The impact of not recovering the purchased power payments is mitigated to the extent that load growth has occurred since the last rate case. GENERATING CAPABILITY & PROJECTED DEMAND The maximum demand on the company's electric system was 932 MW, which occurred in June 1994. This compares to the prior peak of 927 MW which occurred in August 1993. The company's net effective capability at the time of the 1994 system peak was 1,309 MW. Forecast peak demand for the year 2001 is 1,037 MW (not including a 15% reserve of 156 MW required by the Mid-Continent Area Power Pool). The combination of company-owned capacity and the power purchase contracts will provide the company with adequate electric capacity through April 2001. Planning is currently underway as to the best way to meet the capacity needs thereafter. The capacity planning process will include consideration of additional owned capacity, purchased power, load/demand side management, and unit life extension. Although capacity planning is a continuously changing process, the company does not expect substantial cash outlays for new electric generation over the next four years. CLEAN AIR ACT The company meets the existing federal and state environmental regulations. The Federal Clean Air Act requires reductions in sulfur dioxide and nitrogen oxide emissions from power plants. The most restrictive provisions relate to sulfur dioxide emissions. Phase 1 of the Clean Air Act became effective January 1, 1995, while Phase 2 is effective January 1, 2000. During Phase I, one company unit (with a net effective capacity of 217 MW) is affected. To comply with Phase 1, the company has switched the affected unit to low sulfur coal and installed low nitrogen oxide burners. Although the financial impact of Phase 2 has not been fully determined, Phase 2 regulations will affect approximately 87% of the company's current generating capacity and will require capital, operating and maintenance costs beyond those required for Phase 1. The company anticipates the costs of compliance with the Clean Air Act will be recovered through the ratemaking process. POTENTIALLY RESPONSIBLE PARTY DESIGNATION Under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), a past waste generator can be designated by the United States Environmental Protection Agency (U.S. EPA) as a Potentially Responsible Party (PRP). Certain types of used transformer oil (primarily those containing polychlorinated biphenyls, or "PCBs") have been designated as hazardous substances by the U.S. EPA. The company has been cited as a PRP by the U.S. EPA for the clean-up of the facilities formerly operated by Martha C. Rose Chemicals, Inc. in Holden, Missouri. Clean-up of the site began in 1994, with final completion scheduled for early 1995. The Martha Rose Chemical Steering Committee has estimated that total clean-up cost may be up to $22.8 million. The company's proportionate share of clean-up costs has been $0.3 million to-date. The Steering Committee has indicated that it has more than adequate funds to complete the clean-up. In 1988, the U.S. EPA designated the company a PRP for the clean-up of former salvage facilities operated by the Missouri Electric Works, Inc. (MEW) in Cape Girardeau, Missouri. A portion of the PCB-contaminated equipment found at the site was formerly owned by the company. The company has notified the U.S. EPA that it disclaims responsibility for the site, as the equipment was in proper operating condition when sold by the company to a third party, which subsequently made arrangements to transport this equipment to MEW. The U.S. EPA has not responded to the company's disclaimer. The company has not recorded any liability for the MEW site, and management believes that it will be able to successfully defend itself against any claims applicable to the site. COAL TAR DEPOSITS Early this century, various utilities including the company operated plants which produced manufactured gas for cooking and lighting. The company's facilities ceased operations approximately 40 years ago when natural gas pipelines were extended into the upper Midwest. Some of the former gasification sites contain coal tar waste products which may present an environmental hazard. In 1957, the company purchased facilities in Mason City, Iowa, from Kansas City Power & Light Company (KCPL) which included land previously used for a coal gasification plant. Coal tar waste was discovered on the property in 1984. A Remedial Investigation and a Feasibility Study have been approved by the U.S. EPA, and the company anticipates that remediation will begin in 1995 following U.S. EPA designation of the clean-up process. The Federal District Court ruled in 1993 that KCPL is liable to the company regarding the response costs at the Mason City site. (KCPL is an A rated company with total assets in excess of $2 billion.) Additional court proceedings will be held in 1995 to determine the extent of that liability. The company anticipates that it may incur additional costs to clean-up the site, but that such costs should be recoverable from KCPL or from gas customers. In 1994, the company recorded an additional $2.3 million liability for the estimated clean-up costs, and based on the current regulatory treatment, an equal regulatory asset. The company did not expense any investigation and remediation costs related to the Mason City site in 1994 or 1993; it has expensed $2.5 million of investigation and remediation costs applicable to the site since the discovery of the coal tar waste. The company formerly operated a manufactured gas plant in Rochester, Minnesota. This facility was sold to another utility, which later demolished the plant. The site is currently owned by a utility and the City of Rochester. Agreements have been reached between the Minnesota Pollution Control Agency and all three parties noted above regarding the clean-up process. The remediation process began in 1994 and is expected to be completed in early 1995. Pursuant to the settlements described above, with total cost not to exceed $9.662 million, the company has agreed to pay approximately two-thirds of the cost of investigation and clean-up. The company accrued (expensed) $0.8, $3.5, $1.2, and $0.2 million in 1994, 1993, 1992, and 1991, respectively. In addition, the company has identified, or has been identified, as an owner or operator of seven other manufactured gas plant sites in the Midwest: sites in Savanna and Galena, Illinois; a site in Clinton, Iowa; and sites in Albert Lea, Austin, New Ulm and Owatonna, Minnesota. The Savanna, Illinois, and Clinton, Iowa, sites are currently owned by the company; the remaining sites are owned by third parties. Potentially hazardous wastes allegedly associated with former coal gasification operations have been identified at all sites. Investigation of site conditions are in various stages at all of the sites. The company's accrued environmental liabilities of $3.5 million at December 31, 1994, will cover known expenses for investigative and remediation work. Additional liabilities, if any, cannot be determined until further investigative work is performed. In 1994, the company filed a lawsuit against certain of its insurers to recover the costs of investigating and cleaning up, as necessary, the former coal gasification plants. Neither the company nor its legal counsel is able to predict the amount of any insurance recovery, and accordingly, no potential recovery has been recorded. Previous actions by Iowa, Illinois, and Minnesota regulators have permitted utilities to recover prudently incurred investigation, remediation and legal costs (response costs). The company anticipates that costs applicable to the Iowa and Illinois jurisdictions will be recovered from customers. The company's Iowa gas rates currently include a provision for $0.7 million of associated response costs per year. The company's Illinois electric and gas tariffs provide for a rider to recover prudently incurred investigation and remediation costs. While the company is currently seeking an accounting order which would allow the deferral of a portion or all of the remediation costs applicable to its Minnesota jurisdiction, it may be difficult for the company to recover all costs applicable to the Minnesota sites. The MPUC has indicated that this type of cost should not be shared by electric customers, and the company has relatively few Minnesota gas customers. To-date, all estimated Minnesota jurisdictional costs have been charged to expense. A summary of the income statement impact to-date of the coal tar sites is as follows: Total Rate Year Expense Recovery (Millions of Dollars) 1994 $ 1.8 $0.7 1993 3.8 0.6 1992 1.8 0.0 1984-1991 3.5 0.0 Total $10.9 $1.3 CHANGING STRUCTURE OF THE ELECTRIC INDUSTRY Current initiatives at the federal and some state levels propose to increase competition in the electric industry. Under this scenario, customers could purchase energy from alternate power suppliers and then pay the local utility a wheeling fee for delivering the energy. Under certain conditions, the Energy Policy Act of 1992 allows the FERC to grant third party power producers nondiscriminatory access to electric utility transmission systems, and allows wholesale customers (primarily municipal utilities) to purchase energy from alternate power producers. Management believes that its electric wholesale and industrial retail rates compare favorably with those of neighboring utilities and potential independent power producers. The company's favorable rates mitigate the incentive that these customers might otherwise have to relocate, self-generate or purchase electricity from other suppliers. The company anticipates that its generating cost will decline slightly over the next several years as long-term coal purchase and transloading contracts expire and are renegotiated. The company's 24 firm municipal wholesale customers take service under one year contracts. Firm electric sales to municipal utilities account for approximately 3.7% of the company's electric sales and 2.8% of its electric revenue. The company's industrial customers are served on a tariff rate, and are not required to commit to a multiple year contract for service. DEFERRED ENERGY EFFICIENCY COSTS Regulations in Iowa and Minnesota require that utilities conduct energy efficiency programs. The company's long-term forecast anticipates that these programs may offset the need for approximately 115 MW of generating capacity by the year 2000. Program costs and related carrying costs are deferred pending a regulatory prudency review. The company's Minnesota rates recover jurisdictional energy efficiency expenditures and lost revenues. Other operating expenses for 1994, 1993, and 1992 include $0.5, $0.5, and $0.6 million, respectively, for the amortization of Minnesota energy efficiency costs. A May 1994 IUB Order allows recovery of $6.7 million of deferred Iowa energy efficiency costs incurred through December 31, 1992, over a four year period; such recovery began October 1994. Other operating expenses for 1994 include $0.3 million for the amortization of Iowa energy efficiency costs. As of December 31, 1994, and 1993, the total energy efficiency costs deferred were $17.0 and $9.7 million, respectively. Of the $17.0 million total deferred, approximately $11.8 million relates to Iowa energy efficiency costs incurred in calendar 1993 and 1994. The company anticipates filing in late 1995 for recovery of those costs. Management believes that amounts deferred meet the criteria established by the respective commissions for recovery as energy efficiency costs. LARGE ELECTRIC CUSTOMERS The company's six largest electric customers consumed a total of 1,669,835 MWH of electricity in 1994, which accounts for over 31 percent of total MWH sales. These customers are involved in the production of agricultural, chemical, and cement products and their usage is generally not affected by short-term weather variations. The company does not know of any plan by these customers to significantly reduce consumption. Electric consumption by these customers in 1994 was 3.0 percent over 1993, while 1993 consumption was 6.5 percent over 1992. The aggregate 1994 rate for these customers was approximately 3.4 cents per KWH. ORDER 636 FERC Order 636, effective in late 1993, shifted primary responsibility for gas supply acquisition from pipelines to local distribution companies such as the company. The company believes it has taken steps to ensure the acquisition of an adequate supply of natural gas and the associated transportation capacity at reasonable prices. Order 636 effectively eliminated the gas pipelines' bundled supply function, which was historically regulated by the FERC. State regulators now require the company to provide more detailed analyses to justify capacity and gas supply arrangements. Order 636 provides a mechanism under which pipelines can recover prudently incurred transition costs associated with the restructuring process. The company's pipeline suppliers have filed with the FERC to recover transition costs from the local distribution companies. The company incurred $2.1 million of transition costs in 1994 and is currently recovering these costs from customers through the purchased gas adjustment clause. While the ultimate level of transition costs could vary as Order 636 filings are revised and proceedings completed, the company estimates that the remainder will aggregate approximately $5.2 million payable in declining installments from 1995 to 2004. The company anticipates that under customary ratemaking practices, future transition costs will be recovered from customers, and has recorded on its balance sheet a liability and a corresponding regulatory asset in the amount of $5.2 million. INDUSTRIAL AND COMMERCIAL GAS CUSTOMERS Current regulatory rules allow industrial and commercial customers to purchase their gas supply directly from producers and use the company's facilities to transport the gas. Transportation customers pay the company a fee equivalent to the margin on a retail sale. Acting as a gas transporter, rather than as a merchant, reduces the risk applicable to taking ownership of the gas. Eighteen large customers currently purchase a majority of their gas requirements from producers or gas marketers. Consumption for the three largest gas customers was up 2.6% over 1993, and currently accounts for approximately 67% of total system MCF throughput. Their usage is primarily dependent on the overall strength of the economy and other market factors, and is generally not affected by short-term weather variations. The company does not know of any plan by these customers to reduce consumption. The company's largest gas customer, which represents 30% of the company's total gas throughput, is committed by contract for the next seven years. GAS SYSTEM PROFITABILITY Over the last 5 years, gas operating income before income taxes has averaged 1.5% of net gas utility plant. Mild weather, environmental remediation costs, rate treatment which did not compensate the company for customers switching to a more favorable tariff, and the offering of incentive or flexible rates contributed to the low return. The company is seeking recovery of environmental remediation costs from other potentially liable parties as well as through rates and insurance. In addition, more typical heating season weather should improve the gas system profitability. The company's long-term forecast calls for a reduction in gas construction outlays beginning in 1996. RATE MATTERS In August 1993, the company implemented a revised electric tariff structure. The new tariffs give greater weight to the demand component of electric usage, and include a provision for a higher rate during the summer cooling season (June - September), but did not change the company's overall annual electric revenue. The company filed an Iowa electric rate increase application in August 1993. The application requested an annual increase of $11.5 million, including a return on common equity of 12.35%. Interim rates at an annual amount of $11.0 million were placed in effect on October 28, 1993, subject to refund. An IUB order issued in June 1994 allowed an annual increase of $7.4 million based on a return on common equity of 11.0%. A second quarter 1994 entry to record the refund liability included $0.9 million of revenue reduction applicable to the first quarter of 1994 and $0.5 million applicable to the fourth quarter of 1993. Refunds to customers, including $0.2 million of interest, were made in October 1994. In July 1994, the company filed an application with the FERC for an increase in annual firm electric wholesale rates of $1.4 million. In August 1994, in accord with the settlement of a wholesale customer complaint, the company withdrew the rate request. The settlement also required the company to pay the wholesale customers a cash settlement of $0.3 million, and prohibits another firm wholesale rate case with an effective date prior to February 28, 1996. The wholesale customer complaint, which was initially filed in 1992, alleged that the company had been imprudent by entering into certain long-term coal contracts, an associated transloading agreement, and a rail transportation agreement. Electric Sales KWH Sales 1994 Average 1994 1993 Revenue 1994 vs. 1993 vs. 1992 per KWH % of Total % Change % Change Six Largest Industrial 3.4 cents 31.1% 3.0% 6.5% All Other Industrial 4.3 cents 26.4 8.9 5.0 Residential (Non-Heat) 7.6 cents 16.1 2.1 8.1 General Service (Commercial) 6.2 cents 10.6 (5.8) 1.3 Sales for Resale 2.8 cents 8.9 53.6 15.5 Farm 7.5 cents 2.9 (0.9) (0.6) Residential (Electric Heat) 6.2 cents 2.0 (4.3) 6.6 All Other Categories 7.5 cents 2.0 (11.1) (1.1) Total Company 4.8 cents 100.0% 5.8% 5.8% The company anticipates filing for rate increases in 1995 in the Iowa electric, Minnesota electric, Minnesota gas, and the FERC wholesale jurisdictions. Such applications will seek to recover the costs associated with the purchased power contracts, manufactured gas plant clean-up costs, jurisdictional SFAS 106 costs, an increased return on common equity, and attrition due to inflation. In addition, as discussed under Deferred Energy Efficiency Costs, the company anticipates filing in late 1995 for recovery of Iowa energy efficiency costs incurred in 1994 and 1993. RESULTS OF OPERATIONS Earnings per share of common stock were $1.92 for 1994, compared with $1.73 for 1993, and $1.74 for 1992. The return on common equity for 1994 was 9.5%, compared with 8.5% for 1993, and 8.4% in 1992. Electric sales for the past two years have been below expectations due to mild summer weather. KWH use per residential customer was 7,799; 7,816; and 7,341 for years 1994, 1993, and 1992, respectively. Electric "margin" is defined as revenue from all sales, less the cost of fuel and power purchased. Electric margins for years 1994, 1993, and 1992 were $142.0, $137.8, and $135.4 million, respectively. The improved electric margins are primarily attributable to increased sales, the Iowa electric rate increase, and energy efficiency cost recovery. Gas "margin" is defined as the revenue from all sales, less purchased gas cost. The gas margins for 1994, 1993, and 1992 were $15.0, $15.4, and $10.9 million, respectively. The primary reason for the reduced margin is the lower residential and commercial sales due to mild weather. Other operating expenses were $51.9, $48.6, and $42.4 million for 1994, 1993, and 1992, respectively. As discussed under Coal Tar Deposits, other operating expenses for the years 1994, 1993, and 1992, respectively, include $0.8, $3.5, and $1.5 million, for environmental investigation and remediation costs. Other operating expenses for 1994 includes $1.0 million of legal fees relating to coal tar clean-up litigation, compared with $0.3 million in 1993 and 1992. Employee benefits (medical, pensions and other benefits) included in other operating expenses were $9.7, $7.1, and $6.4 million for 1994, 1993, and 1992, respectively. The additional expense applicable to SFAS 106 accounted for $2.1 million of the 1994 increase. Workers compensation costs included in other operating expenses were $0.6, $0.1, and $0.2 million for 1994, 1993, and 1992, respectively, while other injuries and damages were $1.8, $1.3, and $1.4 million, respectively. These costs can vary considerably from year to year, dependent upon actual claims experienced. The States of Iowa and Minnesota enacted legislation effective in 1994 which requires that utilities with electric generating plants pay an emission fee. Other operating expenses for 1994 include emission fees of approximately $0.2 million. In addition, 1994 expense includes $0.2 million of water treatment chemicals applicable to more stringent discharge standards. Depreciation expense was $27.8, $26.3, and $25.2 million, for 1994, 1993, and 1992, respectively. The increase is due to additional plant investment and the implementation of new depreciation rates upon approval of a study performed every five years in accordance with MPUC rules. Property taxes were $13.7, $14.5, and $14.1 million, for 1994, 1993, and 1992, respectively. The majority of the decrease is applicable to a reduction in assessed values in the State of Iowa. Allowance for Funds Used During Construction (AFUDC) totalled $0.5 million in 1994 compared with $0.2 million in 1993. The average 1994 construction work in progress balance was higher, with construction expenditures of $41 million in 1994, compared with $34 million in 1993. In addition, the average AFUDC rate increased from 6.0% in 1993 to 6.3% in 1994. Year-end Construction Work In Progress (CWIP) balances for 1994, 1993, and 1992 were $6.9, $3.2, and $3.5 million, respectively. Miscellaneous income for 1994 includes approximately $1.8 million of energy efficiency carrying costs and energy efficiency direct load control credits. The comparable amounts for 1993 and 1992 were $1.0 and $0.4 million, respectively. As discussed under Rate Matters, other income and deductions for 1994 include $0.3 million of payments to settle a wholesale customer complaint originally filed with the FERC in 1992. The company and the Internal Revenue Service negotiated a settlement of income tax audits in 1994, for tax years through 1991. To reflect the settlement, the company recorded additional interest income and reduced income tax expense. The additional interest income and reduced income tax expense resulted in approximately $2.1 million of additional 1994 income. Interest on long-term debt was $15.4, $16.2, and $16.3 million for 1994, 1993, and 1992, respectively. The 1994 refinancing of Pollution Control Bonds and the 1993 refinancing of First Mortgage Bonds (discussed in the Liquidity and Capital Resources section), coupled with the 1993 maturity of $6 million of 4 3/8% First Mortgage Bonds caused the decrease. The percentage of total capitalization attributable to long-term debt has declined from 47.5% at year-end 1993 to 45.4% at year-end 1994. Other interest charges for 1994 were $1.8 million, compared with $0.6 million for 1993 and 1992, respectively. Interest on commercial paper payable was $0.7, $0.3, and $0.1 million for 1994, 1993, and 1992, respectively. At year-end 1994, the company had $35.6 million of short-term commercial paper payable, compared with $20.1 million at year-end 1993. Other interest charges for 1994 also included interest on the Iowa electric rate refund. The company's investment in coal stockpiles was $19.4, $17.3, and $22.6 million at December 31, 1994, 1993, and 1992, respectively. The company's practice is to build up coal stockpiles during the summer shipping season, and to draw down the stockpiles during the winter. Year-end 1993 stockpiles were unusually low due to flooding of the Mississippi river in mid-1993. The natural gas industry purchases gas during off-peak periods and injects it into underground storage. This gas is withdrawn during peak usage periods when gas purchases are traditionally more costly and interstate pipeline capacity may be constrained. As a result of FERC Order 636, the company now holds title to a greater quantity of storage gas. The company's investment in gas stored underground was $3.7, $4.6, and $2.7 million at December 31, 1994, 1993, and 1992, respectively. Statements of Income and Retained Earnings For the years ended December 31 1994 1993 1992 (Thousands of Dollars) OPERATING REVENUES (Notes 1 and 9): Electric $261,730 $255,759 $239,193 Gas 45,920 53,709 46,105 Total operating revenues 307,650 309,468 285,298 OPERATING EXPENSES: Operation: Fuel for electric generation 61,384 64,059 58,283 Power purchased 58,339 53,936 45,497 Cost of gas sold 30,905 38,309 35,221 Other operating expenses 51,917 48,567 42,390 Maintenance 17,160 16,771 16,966 Depreciation and amortization 28,212 26,955 25,887 Income taxes (Note 8): Federal currently payable 1,395 4,694 6,174 State currently payable 454 1,445 1,923 Deferred taxes - net 7,092 3,856 2,268 Investment tax credit amortization (1,028) (1,028) (1,028) Property and other taxes 16,298 17,080 16,533 Total operating expenses 272,128 274,644 250,114 OPERATING INCOME 35,522 34,824 35,184 OTHER INCOME AND DEDUCTIONS: Equity funds used during construction (Note 1) 166 68 184 Interest income 1,812 718 527 Miscellaneous 1,288 491 374 Income taxes (Note 8) (1,276) (497) (361) Total other income and deductions 1,990 780 724 INCOME BEFORE INTEREST CHARGES 37,512 35,604 35,908 INTEREST CHARGES: Long-term debt (Note 1) 15,405 16,166 16,292 Other interest charges 1,772 596 586 Borrowed funds used during construction (332) (145) (187) (Note 1) Total interest charges 16,845 16,617 16,691 NET INCOME 20,667 18,987 19,217 PREFERRED AND PREFERENCE STOCK DIVIDENDS (2,454) (2,861) (2,975) INCOME AVAILABLE FOR COMMON STOCK 18,213 16,126 16,242 RETAINED EARNINGS BEGINNING OF YEAR 57,397 60,648 63,745 DIVIDENDS ON COMMON STOCK (19,717) (19,377) (19,339) RETAINED EARNINGS END OF YEAR $ 55,893 $ 57,397 $ 60,648 EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING based on 9,478,741; 9,316,387 and 9,297,748 shares, respectively $ 1.92 $ 1.73 $ 1.74 DIVIDENDS PAID PER COMMON SHARE $ 2.08 $ 2.08 $ 2.08 The accompanying notes are an integral part of these financial statements. Statements of Cash Flows For the years ended December 31 1994 1993 1992 (Thousands of Dollars) RECONCILIATION OF NET INCOME TO CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $20,667 $18,987 $19,217 Adjustment for non-cash items: Depreciation and amortization 28,212 26,955 25,887 Deferred income taxes 5,488 5,259 5,170 Investment tax credit amortization (1,028) (1,028) (1,028) Equity funds used during construction (AFUDC) (166) (68) (184) Prepaid pension cost 9 812 322 Changes in assets and liabilities: Accounts receivable - net 3,710 (1,998) 806 Inventories (1,536) 3,751 884 Accounts payable and other current liabilities 4,324 3,686 2,985 Accrued and prepaid taxes (1,011) (2,602) 381 Interest accrued (160) (1,061) 230 Other prepayments and current assets (656) (249) 2,788 Rate refund payable - (4,064) 4,071 Regulatory assets - deferred energy efficiency costs (7,295) (5,005) (3,313) Regulatory assets - other (8,267) - - Other operating activities 721 1,930 1,884 Cash flows from operating activities 43,012 45,305 60,100 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to utility plant (40,600) (33,904) (32,104) Borrowed funds used during construction (AFUDC) (332) (145) (187) Other (658) (231) 925 Cash flows from investing activities (41,590) (34,280) (31,366) CASH FLOWS FROM FINANCING ACTIVITIES: Issuance of common stock 4,237 2,786 - Issuance of preferred stock - 27,250 - Issuance of long-term debt 13,250 94,000 25,000 Retirement of long-term debt (13,487) (88,784) (30,261) Redemption of preferred and preference stock - (25,474) (1,356) Debt and stock discount and financing expenses (357) (8,795) (1,965) Dividends on common, preferred and preference stock (22,111) (22,331) (22,343) Sale of commercial paper - net 15,500 11,100 1,800 Cash flows from financing activities (2,968) (10,248) (29,125) NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $(1,546) $ 777 $ (391) CASH AND CASH EQUIVALENTS: Beginning of year $ 3,083 $ 2,306 $ 2,697 End of year $ 1,537 $ 3,083 $ 2,306 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION: Cash paid during the period for: Interest (net of interest capitalized) $16,773 $17,588 $15,941 Income taxes $ 8,066 $ 8,863 $ 6,438 The accompanying notes are an integral part of these financial statements. Balance Sheets ASSETS As of December 31 1994 1993 (Thousands of Dollars) UTILITY PLANT (Note 1): In Service: Electric: Production $369,828 $362,074 Transmission 178,891 173,373 Other 262,191 245,577 Total Electric 810,910 783,024 Gas 61,447 59,520 872,357 842,544 Less - accumulated depreciation 379,216 358,330 493,141 484,214 Held for future use 592 587 Construction work in progress 6,948 3,163 Net utility plant 500,681 487,964 OTHER PROPERTY AND INVESTMENTS 522 825 CURRENT ASSETS: Cash and cash equivalents 1,537 3,083 Accounts receivable, less reserves of $200 22,350 26,060 Inventories - at average cost: Fuel 24,220 22,985 Materials and supplies 5,208 4,720 Prepaid pension cost (Note 7) 3,702 4,818 Prepaid income tax (Note 8) 6,197 7,994 Other prepayments and current assets 2,252 480 Total current assets 65,466 70,140 DEFERRED DEBITS: Regulatory assets (Notes 1, 2, 7, 8 and 9) 37,997 29,731 Unamortized debt expense (Note 1) 6,116 5,941 Deferred energy efficiency (Note 12) 16,961 9,665 Other 1,102 95 Total deferred debits 62,176 45,432 TOTAL $628,845 $604,361 The accompanying notes are an integral part of these financial statements. Balance Sheets CAPITALIZATION AND LIABILITIES As of December 31 1994 1993 (Thousands of Dollars) CAPITALIZATION, per accompanying statements: Common stock, par value $3.50 per share; authorized - 30,000,000 shares; issued and outstanding - 9,564,287 in 1994 and 9,389,841 in 1993 (Note 4) $ 33,475 $ 32,865 Additional paid-in capital 103,137 99,547 Retained earnings 55,893 57,397 Total common equity 192,505 189,809 Preferred stock (optional sinking fund) 10,819 10,819 Preferred stock (mandatory sinking fund) (Note 4) 23,933 23,837 Long-term debt (Note 5) 189,032 203,170 Total capitalization 416,289 427,635 CURRENT LIABILITIES: Commercial paper (Note 6) 35,600 20,100 Long-term debt maturing within one year (Note 5) 14,000 - Accounts payable 14,133 11,733 Dividends payable - preferred stock 599 599 Payrolls accrued 2,634 2,181 Taxes accrued 13,778 16,586 Interest accrued 2,930 3,090 FERC Order No. 636 transition costs (Note 9) 5,200 - Environmental clean-up cost accrued (Note 2) 3,470 5,754 Other 2,878 4,580 Total current liabilities 95,222 64,623 DEFERRED CREDITS AND OTHER NON-CURRENT LIABILITIES: Accumulated deferred income taxes (Note 8) 88,176 82,438 Accumulated deferred investment tax credits (Note 8) 19,069 20,097 Deferred pension cost (Note 7) 4,827 4,818 Accrued postretirement benefit cost (Note 7) 2,869 2,516 Other 2,393 2,234 Total deferred credits and other non-current liabilities 117,334 112,103 COMMITMENTS AND CONTINGENCIES (Notes 2, 9, 10, 11 and 15) TOTAL $628,845 $604,361 Statements of Capitalization As of December 31 1994 1993 (Thousands of Dollars) COMMON EQUITY (Note 4): $192,505 46.2% $189,809 44.4% CUMULATIVE PREFERRED STOCKS (Note 4): Authorized: Preferred - 2,000,000 shares at $50.00 par value Preference - 2,000,000 shares at $1.00 par value (A) Issued and outstanding (B): Redemption Series Shares Price Preferred with optional sinking fund provisions: 4.36% 60,455 $52.30 $ 3,023 $ 3,023 4.68% 55,926 $51.62 2,796 2,796 7.76% 100,000 $52.03 5,000 5,000 $ 10,819 2.6% $ 10,819 2.5% Preferred with Mandatory sinking fund provisions: 6.40% 545,000 $53.20 27,250 27,250 Unamortized Discount on 6.40% Preferred Stock (2,053) (2,113) Unamortized Issuance Expense on 6.40% Preferred Stock (108) (111) Unamortized Call Premiums on Preferred Stock (1,156) (1,189) $ 23,933 5.8% $ 23,837 5.6% LONG-TERM DEBT (Note 5): First Mortgage Bonds: 4 5/8% Series due 1995 $ - $ 14,000 6 1/8% Series due 1997 17,000 17,000 8 % Series due 2007 25,000 25,000 8 5/8% Series due 2021 25,000 25,000 7 5/8% Series due 2023 94,000 94,000 $161,000 $175,000 Pollution Control Revenue Bonds: 5.95% due 1995 to 1998 $ 6,525 $ 6,750 7 1/4% due 1997 to 2006 - 6,600 6 3/8% due 1998 to 2007 11,400 11,400 7 1/8% due 2001 to 2009 - 6,650 5.75% due 2003 1,000 - 6.25% due 2009 1,000 - 6.30% due 2010 5,600 - 6.35% due 2012 5,650 - $ 31,175 $ 31,400 Other Long-Term Debt $ 115 $ 127 Unamortized Discount on Long-Term Debt $ (3,258) $ (3,357) Total Long-Term Debt - net $189,032 45.4% $203,170 47.5% TOTAL CAPITALIZATION $416,289 100.0% $427,635 100.0% (A) None outstanding. (B) Redeemable at the option of the company upon 30 days notice at the current prices shown. The accompanying notes are an integral part of these financial statements. NOTES TO FINANCIAL STATEMENTS 1. Summary of Accounting Policies GENERAL The financial statements are based on generally accepted accounting principles, which give recognition to the ratemaking and accounting practices of the Federal Energy Regulatory Commission (FERC) and state commissions having regulatory jurisdiction over the company. UTILITY PLANT Utility plant is recorded at original cost. The cost of additions to utility plant and replacement of units of property includes contracted labor, company labor, materials, allowance for funds used during construction and overheads. Repairs of property and replacement of items less than units of property are charged to maintenance expense. The original cost of units retired, plus removal costs, less salvage is charged to accumulated depreciation. Substantially all property is subject to the lien of the First Mortgage Bond Indenture. DEPRECIATION Depreciation is computed on the straight-line method based on net salvage values and the estimated remaining service lives of depreciable property. The provision for book depreciation as a percentage of the average balance of depreciable property in service was 3.5% in 1994 and 3.4% in 1993 and 1992. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AFUDC includes the net cost of borrowed funds and a reasonable rate on equity funds used for construction or deferred energy efficiency purposes. It was capitalized at gross rates of 6.3% for 1994, 6.0% for 1993, and 7.4% for 1992. Gross AFUDC rates are computed in accordance with the FERC regulations, including approval to incorporate deferred energy efficiency costs in the calculation of the formula. AFUDC does not contribute to the current cash flow of the company. Under normal regulatory practices, the company anticipates earning a fair rate of return on such capitalized costs and recovery of those costs in customer rates after completion of the related construction. STATEMENTS OF CASH FLOWS For purposes of the statements of cash flows, the company considers all liquid investments with a maturity of three months or less to be cash equivalents. REVENUES AND FUEL COSTS Annual revenues do not include unbilled revenues for service rendered from the date of the last meter reading to year-end. The company's electric and gas tariffs contain fuel adjustment clauses and a purchased gas adjustment clause whereby increases or decreases in fuel costs are included in current revenue without having changes in base rates approved in formal hearings. Purchased capacity costs are not recovered from electric customers through fuel adjustment clauses, but rather must be addressed in base rates in a formal rate proceeding. DEBT REACQUISITION PREMIUM In accordance with normal regulatory practices, the company defers debt redemption premiums and amortizes such costs over the life of the replacement bonds. RECLASSIFICATIONS Certain reclassifications have been made to the prior years financial statements to conform with the presentation for 1994. Such reclassifications had no impact on net income or stockholders' equity. REGULATORY ASSETS The company is subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation". The regulatory assets represent probable future revenue associated with certain incurred costs. At December 31, 1994, regulatory assets were comprised of the following items: Regulatory Assets (Millions of Dollars) Deferred income taxes (Note 8) $27.5 FERC Order No. 636 transition costs (Note 9) 5.2 Employee/retiree benefits (Note 7) 2.6 Environmental liabilities (Note 2) 2.6 Other 0.1 Subtotal 38.0 Deferred energy efficiency costs (Note 12) 17.0 Total $55.0 2. Environmental Regulations The company is subject to various federal and state government environmental regulations. The company meets existing air and water regulations. The Federal Clean Air Act Amendments of 1990 requires reductions in certain emissions from power plants. The legislation has two deadlines for compliance, Phase 1 (January 1, 1995) and Phase 2 (January 1, 2000). The company has switched to a low sulfur coal and installed low nitrogen oxide burners at the 217 MW plant affected by Phase 1. Additional capital expenditures of $11 million will be required in 1995 and 1996 to comply with environmental standards applicable to power plants. Management anticipates that additional costs incurred will be recovered through customer rates. The company has identified nine sites which may contain hazardous waste from former coal gasification plants. Remediation of one site is currently underway, while the other sites are in the investigative stage. The company has recorded a liability for its pro rata share of all known expenses applicable to the former coal gasification plants. Investigation and future remediation costs applicable to the two Illinois sites are being recovered from electric and gas customers through an environmental rate clause. In 1994, $0.3 million of costs applicable to Illinois were charged to a regulatory asset and will be amortized to expense as they are recovered from customers beginning in 1995. Effective February 1993, a representative level of investigation, remediation and legal costs of $0.7 million per year applicable to the two Iowa sites is being recovered from customers through gas rates. Investigation and remediation costs through December 31, 1993, have been charged to expense. In accordance with the established practice of the Iowa Utilities Board (IUB), the 1994 accrual of $2.3 million for future remediation costs has been offset by a regulatory asset. Such costs will be charged to expense as they are incurred in the future. At present, the company is not recovering coal tar costs applicable to Minnesota. The company is currently seeking an accounting order which would allow the deferral of the investigation and remediation costs applicable to its Minnesota jurisdiction. Pending action by the Minnesota Public Utilities Commission (MPUC), all costs applicable to the Minnesota sites have been charged to expense. The company is taking steps to recover portions of the investigation, remediation, and legal costs from insurance carriers and other responsible parties. The Federal District Court ruled in 1993 that Kansas City Power and Light Company (KCPL) is liable to the company regarding the response costs at the Mason City site. Additional court proceedings will be held in 1995 to determine the extent of that liability. In 1994, the company filed a lawsuit against certain of its insurers to recover the costs of investigating and cleaning up, as necessary, the former coal gasification plants. Neither the company nor its legal counsel is able to predict the amount of any insurance recovery, and accordingly, no potential recovery has been recorded. 3. Fair Value of Financial Instruments The estimated fair values of the company's financial instruments as of December 31, 1994, and 1993, are shown in the table below. The estimated fair values were based on quoted market prices for the same or similar issues or on the current rates for debt of the same remaining maturities. The preferred stock carrying amounts for 1994 and 1993 excludes $1.3 million of unamortized call premium and issuance expense. Fair Value of Financial Instruments (Millions of Dollars) 1994 1993 Carrying Fair Carrying Fair Amount Value Amount Value Long-term debt $189.0 $178.4 $203.2 $215.4 Preferred stock (mandatory sinking fund) $ 25.2 $ 23.0 $ 25.1 $ 25.3 4. Preferred, Preference and Common Stock In May 1993, the company issued 545,000 shares of 6.40% $50 par value preferred stock with a final redemption date of May 1, 2022. Under the provisions of the mandatory sinking fund, beginning in 2003 the company is required to redeem annually $1.4 million of 6.40% preferred stock (27,250 shares). The discount and other issuance expenses in an aggregate amount of $2.2 million as of December 31, 1994, are reflected as an offset to preferred stock and are being amortized to common equity. Such amortization transfers the discount and other issuance expenses from preferred stock to common stock over the life of the issue, but does not affect net income. Call premiums related to the 1993 retirement of the preferred and preference stock in the amount of $1.2 million as of December 31, 1994, are reflected as an offset to preferred stock and are being amortized to common equity. The amortization transfers the amount of the call premiums from preferred stock to common stock over the life of the refunding 6.40% issue, but has no effect on net income. In June 1993, the company retired certain preferred and preference stock as detailed below: Number of Shares Total Redemption Issue Retired Price (Thousands) 8% Preferred, $50 par 63,000 $ 3,206 9% Preferred, $50 par 116,643 $ 6,113 9%-A Preferred, $50 par 128,000 $ 6,652 $2.28 Preference, $1 par 400,000 $10,712 In 1992, the company retired the following preferred stock through the provisions of the sinking fund: Number of Shares Total Redemption Issue Retired Price (Thousands) 8.00% 7,000 $ 350 9.00% 4,117 $ 206 9.00%-A 16,000 $ 800 The company's Common Stock Dividend Reinvestment and Stock Purchase Plan gives the company the option of issuing new stock or purchasing shares on the open market. The Dividend Reinvestment Plan acquired 44,868; 60,299 and 113,735 shares of common stock on the open market during 1994, 1993, and 1992, respectively. The company received $4.2 million for 174,446 shares of new common stock issued in the first eleven months of 1994 and $2.8 million for 92,093 shares of new common stock issued in the third and fourth quarters of 1993. None of the authorized shares of preferred, preference or common stock are reserved for officers and employees, or for options, warrants, conversions, and other rights. 5. Long-Term Debt $14 million of 4 5/8% First Mortgage Bonds mature on May 1, 1995, and are classified as a current liability on the December 31, 1994, balance sheet. Annual sinking fund requirements are $0.8, $2.0, $1.8, $1.8, and $1.8 million for the years 1995 through 1999, respectively. Such sinking fund requirements for first mortgage bonds may be satisfied with property additions at the rate of 167% of such requirements. Total debt maturities for the years 1995 through 1999 are $14.2, $0.2, $17.2, $6.3, and $0.4 million, respectively. 6. Short-Term Borrowings The company had available bank lines of credit aggregating $43.3 million at December 31, 1994. There are no compensating balances required, but some of the banks require commitment fees; such fees were not significant. The maximum amount of short-term borrowing at any month end in 1994, 1993, and 1992 was $35.6, $20.1, and $12.2 million, respectively, all in commercial paper, with the average outstanding borrowing during the year of $15.6, $9.4, and $4.2 million, respectively. The average interest rate on borrowings was 4.73%, 3.29%, and 3.56% for the years 1994, 1993, and 1992, respectively. At December 31, 1994, 1993, and 1992, the interest rate was 6.07%, 3.36%, and 3.79%, respectively. 7. Employee/Retiree Benefits The company has a non-contributory defined benefit pension plan for all full-time employees. Plan benefits are based primarily on years of service and employee compensation. The company uses the "projected unit credit" actuarial method in computing pension costs for accounting purposes. Plan assets consist of high-grade bonds, commercial mortgages and other fixed income investments. Company policy is to fund the plan under the "aggregate" actuarial cost method to the extent deductible under tax regulations. Contributions to the plan for the years ended December 31, 1994, 1993, and 1992, were $3.4, $2.8, and $0.1 million, respectively. Contributions in 1991 included $2.6 million applicable to the 1992 plan year. In addition to the pension plan, the company has a non-qualified supplemental retirement plan which, as amended in 1994, provides a retirement benefit for certain officers of the company. The company is collecting an annual funding amount in customer rates and anticipates that it will continue to do so. The $4.8 million cumulative difference between the higher funded amount and the accounting pension cost amount is a deferred credit on the balance sheet. Pension Cost Components: 1994 1993 1992 (Thousands of Dollars) Service cost $ 2,668 $ 1,888 $ 1,894 Actual return on plan assets (1,707) (2,214) (4,330) Interest cost on projected benefit obligation 3,710 3,504 3,294 Net amortization and deferral (953) (1,270) 1,476 Net pension cost $ 3,718 $ 1,908 $ 2,334 Discount rate for obligation 7.5% 7% 8% Discount rate for expense 7.0% 8% 8% Assumed rate of compensation increase 5.0% 5% 6% Expected long-term rate of return 7.0% 8% 8% Reconciliation of Funded Status as of November 1: Plan assets at fair value $49,282 $48,827 $47,365 Vested benefit obligation $36,626 $34,242 $27,127 Nonvested benefit obligation 2,365 1,728 384 Accumulated benefit obligation 38,991 35,970 27,511 Additional benefits based on estimated future salary levels 13,547 13,872 17,855 Projected benefit obligation $52,538 $49,842 $45,366 Plan assets greater or (less) than the projected benefit obligation $(3,256) $(1,015) $ 1,999 Unrecognized net obligation at October 31, 1986 being amortized over 16.1 years 2,753 3,094 3,435 Unrecognized prior service cost 3,487 399 2,126 Unrecognized net (gain)loss 718 2,340 (3,554) Prepaid pension cost $ 3,702 $ 4,818 $ 4,006 In addition to providing pension benefits, the company provides life insurance for retired employees and health care benefits for 910 retirees and spouses. Substantially all of the company's 940 full-time employees become eligible for these benefits if they reach retirement age while working for the company. The company adopted Statement of Financial Accounting Standards (SFAS) No. 106, "Accounting for Postretirement Benefits Other Than Pensions" on January 1, 1993. Under the provisions of SFAS 106, the estimated future cost of providing these postretirement benefits is accrued during the employees' service periods. The accumulated postretirement benefit obligation at January 1, 1993 (transition obligation) was $30.9 million and is being amortized over a 20 year period. The annual SFAS 106 cost for both 1994 and 1993 was $4.9 million, compared with the pay-as-you-go amount of $1.9, $1.7, and $1.6 million in 1994, 1993, and 1992 respectively. Except for the State of Illinois, the company defers the difference between the SFAS 106 costs and the pay-as-you-go amount until rate cases are filed to recover the additional costs. Funding of the benefit obligation is concurrent with recovery in customer rates. Effective May 1993, the IUB allowed the company to recover $0.3 million of additional annual SFAS 106 expense in gas rates. Effective November 1993, the IUB allowed recovery of $1.6 million of additional annual SFAS 106 expense in electric rates. On the basis of generic hearings or specific rate orders issued to other utilities by the MPUC and the FERC, the company believes that the amounts deferred meet the criteria for deferral established by the Financial Accounting Standards Board. As of December 31, 1994, $2.6 million of SFAS 106 costs in excess of the pay-as-you-go amount have been deferred. Assuming a one percent increase in the medical cost trend rate, the company's 1994 cost of postretirement benefits would increase by $0.5 million and the accumulated benefit obligation would increase by $3.7 million. The table below sets forth the postretirement health care plan's accumulated benefit obligation (in thousands): December 31, 1994 January 1, 1994 Retirees $18,902 $19,414 Active plan participants 12,642 15,690 Total accumulated benefit obligation 31,544 35,104 Less fair value of plan assets 4,072 814 Accumulated postretirement benefit obligation in excess of plan assets 27,472 34,290 Unrecognized net gain or (loss) 1,756 (2,454) Unrecognized transition obligation (25,253) (29,320) Accrued postretirement benefit cost $ 3,975 $ 2,516 The components of the estimated cost of postretirement benefits other than pensions for the twelve months ended December 31, 1994, and 1993, are as follows (in thousands): 1994 1993 Service cost $ 1,205 $ 979 Return on plan assets (48) - Interest cost on accrued postretirement benefit obligation 2,345 2,383 Amortization of transition obligation 1,543 1,543 Net amortization and deferral (159) - Net cost $ 4,886 $ 4,905 The assumptions used for measurement purposes are as follows: 1995 1994 Discount rate for obligations 7.5% 7.0% Discount rate for expense 7.0% 8.0% Initial medical cost trend rate 9.0% 9.0% Ultimate medical cost trend rate 6.0% 6.0% Year that the medical cost trend rate is assumed to decrease to the ultimate rate 1997 1997 8. Income Taxes The company adopted SFAS No. 109, "Accounting for Income Taxes", on January 1, 1993. The new standard required a deferred tax asset or liability to be recognized for each temporary book/tax difference, including timing differences flowed through and items not previously considered timing differences (primarily Deferred Investment Tax Credits and Equity AFUDC). Corresponding regulatory assets or liabilities, reflecting the anticipated future rate treatment, have also been recognized. The balance sheet as of December 31, 1994, includes additional regulatory assets and deferred tax liabilities of $27.5 million as a result of the adoption of SFAS 109. Investment tax credits have been deferred and are credited to operating income over the lives of the property which gave rise to the credits. The principal components of the company's deferred tax (assets) liabilities recognized in the December 31, 1994, and 1993, balance sheet are shown below: Item: Thousands of Dollars 1994 1993 Property $80,484 $76,956 Energy Conservation Costs 5,195 2,782 Environmental Clean-up Costs (210) (2,366) Call Premiums on Reacquired Bonds 2,005 1,988 Unbilled Revenue (3,310) (3,681) Other (2,186) (1,235) Total $81,978 $74,444 Gross deferred assets $(6,197) $(7,994) Gross deferred liabilities 88,175 82,438 Total $81,978 $74,444 The total income tax expense produces the overall effective income tax rate shown in the table. The percentages are computed by dividing total income tax expense by the sum of such tax expense and net income. 1994 1993 1992 Federal statutory tax rate 35.0% 35.0% 34.0% Increases (reductions) in taxes resulting from: State income taxes net of federal income tax benefit 4.0% 4.7% 4.3% Investment tax credit amortization (3.4%) (3.6%) (3.6%) Additional depreciation deducted for book purposes 2.0% 2.0% 2.2% Other (6.8%) (4.8%) (3.4%) Overall effective income tax rate 30.8% 33.3% 33.5% The current and deferred tax expense is comprised of (Thousands): Federal and state currently payable $ 1,849 $ 6,139 $ 8,097 Deferred income tax - federal and state: Additional tax depreciation - net 3,270 3,256 3,012 Coal contract buyout - (526) (149) Energy efficiency costs 2,413 1,466 773 Environmental clean-up 2,010 (1,166) (353) Other (601) 826 (1,015) Investment tax credit amortization (1,028) (1,028) (1,028) Federal and state currently payable - other income and deductions 1,276 497 361 Total $ 9,189 $ 9,464 $ 9,698 9. Rate Matters IOWA The company filed an Iowa electric rate increase application in August 1993. The application requested an annual increase of $11.5 million, including a return on common equity of 12.35%. Interim rates in an annual amount of $11.0 million were placed in effect on October 28, 1993, subject to refund. An IUB Order issued in June 1994 allowed an annual increase of $7.4 million, including a return on common equity of 11.0%. Electric revenues for 1994 are reduced by approximately $0.5 million of overcollection which relates to 1993. FERC In 1992, sixteen municipal wholesale customers filed a Complaint and Request for Investigation and Hearing with the FERC. The complaint alleged that the company had been imprudent by entering into certain long-term coal contracts, an associated transloading agreement, and a rail transportation agreement and sought recovery of approximately $4 million. In July 1994, the company filed an application with the FERC for an increase in firm electric wholesale rates in an annual amount of $1.4 million. On August 3, 1994, in accord with a settlement of the wholesale customer complaint, the company withdrew the rate request. The settlement also provided for the company to pay the wholesale customers a cash settlement of $0.3 million, and that the company will not file another firm wholesale rate case with an effective date prior to February 28, 1996. FERC Order 636, issued in 1992, provides for nondiscriminatory access to interstate pipeline capacity. Order 636 includes a mechanism under which gas pipelines can recover from local distribution companies prudently incurred transition costs. The company's pipeline suppliers have filed with the FERC to recover such transition costs. The company estimates its remaining share of transition costs will aggregate approximately $5.2 million payable in declining annual installments from 1995 to 2004. The company anticipates that under customary regulatory practices, such transition costs will be recovered from customers, and has recorded on its balance sheet a liability and a corresponding regulatory asset in the amount of $5.2 million. 10. Jointly-Owned Utility Plant The company has a 21.528% (134,300 KW) interest in a 624,000 KW coal-fired unit (Neal #4), completed in 1979; the company provided financing for its share. Amounts at December 31, 1994, and 1993, included in utility plant were $82.0 and $81.7 million, respectively, and the accumulated provision for depreciation was $38.6 and $36.1 million, respectively. In addition, the company has a long-term participation power purchase for 25,000 KW of Neal #4 generating capacity which expires 2003. Minimum future capacity payments under the participation power purchase agreement are approximately $17.9 million. The 21.528% ownership share and the long-term participation purchase provide the company with an aggregate of 159,300 KW of Neal #4 generating capacity. The company also has a 4% (27,000 KW) interest in a 675,000 KW coal-fired unit (Louisa #1), completed in 1983. $24.8 million was included in utility plant at December 31, 1994, and 1993, and the accumulated provision for depreciation was $8.8 and $8.1 million, respectively. The company's share of direct expenses of Neal #4 and Louisa #1 is included in the appropriate operating expenses in the statements of income and retained earnings. 11. Purchased Power Contracts The company has three long-term power purchase contracts with other electric utilities. The contracts provide for the purchase of 230 to 255 megawatts of capacity over the period from May 1992 through April 2001. The company is obligated to pay the capacity charges regardless of the actual electric demand by the company's customers. Energy is available at the company's option at approximately 100% to 110% of monthly production costs for the designated units. The three power purchase contracts required capacity payments of $24.6, $24.1, and $16.3 million in 1994, 1993, and 1992 respectively. Over the remaining period of the contracts, total capacity payments will be approximately $155 million. A portion of the purchased power capacity payments is not being recovered through rates: A 1992 rate order by the MPUC held that the company had 100 MW of excess capacity. The Minnesota jurisdictional portion of the 100 MW of disallowed capacity is approximately $1.9 million annually. An additional 25 MW of purchased power contracts became effective after 1992. Annual electric rates do not provide for the recovery of $0.8 and $0.2 million, respectively, applicable to the Iowa and Minnesota jurisdictions. The company has not yet filed for rate recovery of the allocable portions of the purchased power payments in the Illinois and the FERC jurisdictions. The annual Illinois and the FERC jurisdictional portions are approximately $1.7 and $0.9 million, respectively. The amounts which are not being recovered through rates are expensed as incurred. The impact of not recovering the purchased power payments is mitigated to the extent that load growth has occurred since the last rate case. The purchased power contract payments are not for debt service requirements of the selling utility, nor do they transfer risk or rewards of ownership. 12. Deferred Energy Efficiency Costs Minnesota and Iowa regulations require that utilities conduct energy efficiency and demand side management programs. Each utility recovers program costs as well as related carrying costs subject to a periodic prudency review by the state public utility commission. Demand side management expenditures applicable to the Minnesota jurisdiction in an annual amount of approximately $0.5 million are currently being recovered through rates. A May 1994 IUB Order allows recovery of Iowa energy efficiency expenditures incurred through December 31, 1992. New tariffs, which provide for the recovery of approximately $6.7 million of energy efficiency costs over a four year period were placed in effect in October 1994. Management believes that the amounts deferred meet the criteria established by the respective commissions for recovery of demand side management costs. As of December 31, 1994, and 1993, the amounts deferred were $17.0 and $9.7 million, respectively. 13. Segments of Business Information about the company's operations in different segments of business for 1994, 1993 and 1992 are shown in the table below. Electric Gas Total (Thousands of Dollars) 1994 Revenue $261,730 $ 45,920 $307,650 Operating income (Before income taxes) $ 42,881 $ 554 $ 43,435 Depreciation and amortization expense $ 26,156 $ 2,056 $ 28,212 Capital expenditures $ 38,129 $ 2,969 $ 41,098 Utility plant - net $461,245 $ 39,436 $500,681 1993 Revenue $255,759 $ 53,709 $309,468 Operating income (Before income taxes) $ 44,573 $ (782) $ 43,791 Depreciation and amortization expense $ 24,732 $ 2,223 $ 26,955 Capital expenditures $ 29,030 $ 5,087 $ 34,117 Utility plant - net $449,430 $ 38,534 $487,964 1992 Revenue $239,193 $ 46,105 $285,298 Operating income (Before income taxes) $ 46,854 $ (2,333) $ 44,521 Depreciation and amortization expense $ 23,844 $ 2,043 $ 25,887 Capital expenditures $ 26,276 $ 6,199 $ 32,475 Utility plant - net $446,380 $ 35,676 $482,056 14. Quarterly Information (Unaudited) The quarterly information has not been audited but, in the opinion of the company, reflects all adjustments necessary for the fair statement of the results of operations for each period. The quarterly data shown below reflects seasonal and timing variations which are common in the utility industry. (Thousands of Dollars) (Except Earnings Per Share) 1994 March 31 June 30 Sept. 30 Dec. 31 Operating revenues $85,575 $71,863 $79,808 $70,404 Operating income 13,051 5,460 10,607 6,404 Net income 9,251 1,354 6,867 3,195 Earnings per share of common stock .91 .07 .65 .27 1993 March 31 June 30 Sept. 30 Dec. 31 Operating revenues $84,989 $70,107 $77,248 $77,124 Operating income 12,417 6,331 7,089 8,987 Net income 8,389 1,980 3,519 5,099 Earnings per share of common stock .82 .11 .31 .47 Net income for the fourth quarter of 1994 was $3.2 million, compared with $5.1 million in 1993. Mild weather, coal tar clean-up costs, additional depreciation and other employment benefits expense depressed fourth quarter of 1994 earnings. These factors were partially offset by increased fourth quarter 1994 industrial sales and a favorable IRS tax audit settlement. In addition, an overcollection of electric rates in Iowa tended to boost 1993 earnings as discussed in Note 9. The gas margin for the fourth quarter of 1994 (revenue minus cost of gas sold) was $2.8 million compared with $3.5 million for the same period of 1993. The decrease is primarily attributable to reduced residential and commercial sales due to mild weather. Other operating expense for the fourth quarter of 1994 includes $0.9 million of estimated coal tar clean-up costs. The 1993 provisions for clean-up costs were recorded in the first and third quarters. Depreciation expense for the fourth quarter of 1994 increased $0.8 million over the same period of 1993. The increase is primarily attributable to new depreciation rates approved by the MPUC retroactive to January 1, 1994. Other deductions for the fourth quarter of 1994 include a $0.3 million cash settlement for the FERC municipal complaint. Income tax expense for the fourth quarter of 1994 declined $1.7 million, due to lower net income and the favorable settlement of an IRS audit for tax years 1988-1991. 15. Commitments and Contingencies The company has a coal supply contract, a rail transportation contract, and a coal transloading agreement applicable to its power plants. Such contracts, the last of which expires in 1999, require estimated minimum future payments of $132.6 million. The company has three natural gas supply contracts, six natural gas transportation contracts, and four natural gas storage contracts, which collectively obligate the company for a minimum annual commitment of approximately $7.8 million. Such agreements individually expire from 1995 through 2001. Reference is also made to Notes 2, 9, 10, and 11 for a discussion of Environmental Matters, Rate Matters and Purchased Power Contracts. Independent Auditors' Report DELOITTE & TOUCHE LLP 101 West Second Street Davenport, Iowa 52801 To the Stockholders and Board of Directors of Interstate Power Company: We have audited the accompanying balance sheets and statements of capitalization of Interstate Power Company as of December 31, 1994 and 1993 and the related statements of income and retained earnings and of cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with 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 financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1994 and 1993 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. As discussed in notes 7 and 8 to the financial statements, in 1993 the Company changed its method of accounting for postretirement benefits other than pensions and for income taxes, respectively. /s/ Deloitte & Touche LLP Deloitte & Touche LLP February 2, 1995 REPORT OF MANAGEMENT ON FINANCIAL STATEMENT RESPONSIBILITY Company management has prepared and is responsible for the integrity and objectivity of the financial statements and related financial information included in this Annual Report to Stockholders. These statements have been prepared in conformity with generally accepted accounting principles and necessarily include amounts based on informed judgements and estimates with appropriate consideration to materiality of events pending at year-end. In meeting its responsibility, management has implemented an internal accounting system designed to safeguard the assets of the company and assure that transactions are executed in accordance with its directives. An organizational structure has been developed that provides for appropriate functional responsibilities. A qualified internal audit staff is responsible for monitoring the system of policies, procedures and methods of operation. The company believes its system of internal controls appropriately balances the cost/benefit relationship, and that errors or irregularities will be detected and corrected on a timely basis. The Audit Committee of the Board of Directors, comprised of three directors who are not employees, periodically meets with management and with the independent certified public accountants to discuss and evaluate auditing, internal control and financial reporting matters. Management believes that these policies and procedures provide reasonable assurance that the operations of the company are in accordance with the standards and responsibilities entrusted to management. /s/ Wayne H. Stoppelmoor Wayne H. Stoppelmoor Chairman of the Board, President and Chief Executive Officer Selected Financial Data 1994 1993 1992 1991 1990 (Thousands of Dollars) Operating revenues $307,650 $309,468 $285,298 $291,805 $273,597 Operation 202,545 204,871 181,391 172,709 160,206 Maintenance 17,160 16,771 16,966 17,567 15,529 Depreciation and amortization 28,212 26,955 25,887 25,303 24,420 Income taxes 7,913 8,967 9,337 17,113 18,132 Property and other taxes 16,298 17,080 16,533 15,315 14,785 272,128 274,644 250,114 248,007 233,072 Operating income 35,522 34,824 35,184 43,798 40,525 Other income (deductions) - net 1,990 780 724 1,269 1,429 Income before interest charges 37,512 35,604 35,908 45,067 41,954 Interest charges 16,845 16,617 16,691 15,557 14,928 Net income 20,667 18,987 19,217 29,510 27,026 Preferred and preference dividends 2,454 2,861 2,975 3,075 3,158 Earnings available for common stock $ 18,213 $ 16,126 $ 16,242 $ 26,435 $ 23,868 Average number of common shares outstanding 9,478,741 9,316,387 9,297,748 9,297,748 9,297,748 Earnings per common share $ 1.92 $ 1.73 $ 1.74 $ 2.84 $ 2.56 Common dividends declared per share $ 2.08 $ 2.08 $ 2.08 $ 2.04 $ 2.00 Total assets $628,845 $604,361 $558,100 $550,631 $539,103 Long-term debt and mandatory sinking fund preferred stock $212,965 $227,007 $207,958 $220,818 $197,969 Common Stock Market Data The company's common stock (IPW) is listed on the New York, Midwest and Pacific Stock Exchanges. The company's preferred stock and first mortgage bonds are traded in the over-the-counter market. The company was reorganized as of March 31, 1948, and dividends on common stock have been paid each quarter since September 20, 1948, with the annual payments rising from $0.60 per share to the February 4, 1992, level of $2.08 per share. As of December 31, 1993, there were 16,256 holders of common stock and 200 holders of preferred stock. Historical quarterly data for the company's common stock is shown below: Avg. Shares Outstanding Price Range 12 Months Quarter Ended Dividends Paid High Low Ended March 31, 1992 $0.52/Share 34 3/4 - 31 5/8 9,297,748 June 30, 1992 $0.52/Share 34 3/8 - 30 5/8 9,297,748 Sept. 30, 1992 $0.52/Share 32 3/8 - 31 9,297,748 Dec. 31, 1992 $0.52/Share 31 7/8 - 28 3/8 9,297,748 March 31, 1993 $0.52/Share 34 1/8 - 30 3/8 9,297,748 June 30, 1993 $0.52/Share 32 3/4 - 29 9,297,748 Sept. 30, 1993 $0.52/Share 31 3/4 - 29 9,301,030 Dec. 31, 1993 $0.52/Share 30 3/4 - 29 1/8 9,316,387 March 31, 1994 $0.52/Share 30 1/4 - 26 3/8 9,341,751 June 30, 1994 $0.52/Share 29 - 22 1/4 9,379,249 Sept. 30, 1994 $0.52/Share 24 3/4 - 21 9,428,183 Dec. 31, 1994 $0.52/Share 23 3/4 - 20 7/8 9,478,741 EX-23 5 EX-23.a DELOITTE & TOUCHE LLP Northwest Bank Building Telephone: (319) 322-4415 101 West Second Street Facsimile: (319) 322-2002 Davenport, Iowa 52801-1813 INDEPENDENT AUDITORS' REPORT Interstate Power Company: We have audited the financial statements of Interstate Power Company as of December 31, 1994 and 1993, and for each of the three years in the period ended December 31, 1994, and have issued our report thereon dated February 2, 1995, which report includes an explanatory paragraph as to a 1993 change in accounting for postretirement benefits other than pensions and for income taxes; such financial statements and report are included in your 1994 Annual Report to Stockholders and are incorporated herein by reference. Our audits also included the financial statement schedule of Interstate Power Company, listed in Item 14. This 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. /s/ Deloitte & Touche LLP February 2, 1995 EX-23 6 EX-23.b DELOITTE & TOUCHE LLP Northwest Bank Building Telephone: (319) 322-4415 101 West Second Street Facsimile: (319) 322-2002 Davenport, Iowa 52801-1813 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in Registration Statement No. 33-59352 on Form S-3 and Registration Statement No. 33-32529 on Form S-8 of Interstate Power Company of our reports dated February 2, 1995, appearing in and incorporated by reference in the Annual Report on Form 10-K of Interstate Power Company for the year ended December 31, 1994. /s/ Deloitte & Touche LLP March 17, 1995 EX-27 7
UT 12-MOS DEC-31-1994 DEC-31-1994 PER-BOOK 500,681 522 65,466 62,176 0 628,845 33,475 103,137 55,893 192,505 23,933 10,819 189,032 0 0 35,600 14,000 0 115 17 162,824 628,845 307,650 7,913 264,215 272,128 35,522 1,990 37,512 16,845 20,667 2,454 18,213 19,717 15,124 (1,546) $1.92 $1.92
EX-99 8 EX-99.a ITEM 11(a)(2). EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. Those financial statement schedules required to be filed by Item 8 of this Form and the financial statements required by Regulation S-X (17 CFR 210) which are excluded from the annual report to stockholders by Rule 14a-3(b)(1). Listed below are current documents incorporated by reference and identified as having been previously filed with the Commission. The Original through the Nineteenth Supplemental Indentures of Interstate Power Company to The Chase Manhattan Bank and Carl E. Buckley and C. J. Heinzelmann, as Trustees, dated January 1, 1948 securing First Mortgage Bonds (physically filed in Registration Statement No. 33-59352 dated March 11, 1993 under the Securities Act of 1933 as Exhibits (4)(b) through (4)(t)). Twentieth Supplemental Indenture of Interstate Power Company to The Chase Manhattan Bank and C. J. Heinzelmann, as Trustees, dated May 15, 1993 (physically filed in Registration Statement No. 33-59352 dated March 11, 1993 under the Securities Act of 1933 as Exhibit (4)(u)). Dividend Reinvestment and Stock Purchase Plan filed on Form S-3 covering the registration of 500,000 shares of Common Stock, dated May 11, 1993 (physically filed in Registration Statement No. 33-66244 under the Securities Act of 1933). Guaranty Agreement between Interstate Power Company and Commerce Union Bank as Trustee dated as of December 1, 1973 (City of Dubuque, Iowa $4,400,000 Pollution Control Revenue Bonds) (physically filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.1a). Security Agreement dated as of December 1, 1973 between Interstate Power Company (Guarantor) and Commerce Union Bank (Trustee) (City of Dubuque, Iowa $4,400,000 Pollution Control Revenue Bonds) (physically filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.1b). Guaranty Agreement between Interstate Power Company and Commerce Union Bank as Trustee dated as of December 1, 1973 (Town of Lansing, Iowa $3,700,000 Pollution Control Revenue Bonds) (physically filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.2a). Security Agreement dated as of December 1, 1973 between Interstate Power Company (Guarantor) and Commerce Union Bank (Trustee) (Town of Lansing, Iowa $3,700,000 Pollution Control Revenue Bonds) (physically filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.2b). Guaranty Agreement between Interstate Power Company and Commerce Union Bank as Trustee dated as of December 1, 1973 (City of Clinton, Iowa $900,000 Pollution Control Revenue Bonds) (physically filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.3a). Security Agreement dated as of December 1, 1973 between Interstate Power Company (Guarantor) and Commerce Union Bank (Trustee) (City of Clinton, Iowa $900,000 Pollution Control Revenue Bonds) (physically filed in Registration Statement No. 2-50685 as EXHIBIT 5-GG.3b). Registration Statement No. 33-32529 on Form S-8 covering the registration of $10,000,000 of participation interests, including the registration of up to 402,010 shares of Common Stock, par value $3.50 per share, of Interstate Power Company pursuant to its 401(k) Plan (filed with the Commission on December 12, 1989). IPC Development Co. Articles of Incorporation, State of Iowa dated May 24, 1978 (physically filed in Form 10-K for the Year Ended December 31, 1978 as EXHIBIT G). IPC Development Co. By-Laws adopted May 10, 1978 (physically filed in Form 10-K for the Year Ended December 31, 1978 as EXHIBIT H). By-Laws of Interstate Power Company as adopted April 20, 1925 and as amended May 7, 1991 (physically filed in Form 10-K for the Year Ended December 31, 1991 as EXHIBIT W). Restated Certificate of Incorporation of Interstate Power Company as originally filed April 18, 1925 and as amended effective through October 21, 1993 (filed in Form 10-K for the Year Ended December 31, 1993 as EX-3.a). Summary Plan Description for the Interstate Power Company 401(k) Plan dated November 30, 1993 (filed in Form 10-K for the Year Ended December 31, 1993 as EX-99.c). Interstate Power Company Supplemental Retirement Plan dated October 8, 1990 (filed in Form 10-K for the Year Ended December 31, 1993 as EX-99.d). Interstate Power Company Irrevocable Trust Agreement dated April 30, 1990 (filed in Form 10-K for the Year Ended December 31, 1993 as EX-99.f). Interstate Power Company Amended Deferred Compensation Plan as amended through January 30, 1990 (filed in Form 10-K for the Year Ended December 31, 1993 as EX-99.e). -----END PRIVACY-ENHANCED MESSAGE-----