ITEM 1. BUSINESS
THE COMPANY
On March 1, 1988, after obtaining shareowner and all the necessary regulatory approvals, Wisconsin Power and Light Company (the "Company" or "WP&L") effected a corporate restructuring which included the formation of a holding company, WPL Holdings, Inc. WPL Holdings, Inc. is the parent company of WP&L and its utility subsidiaries and of Heartland Development Corporation, the parent corporation for nonregulated businesses.
The Company, incorporated in Wisconsin on February 21, 1917, as the Eastern Wisconsin Electric Company, is a public utility predominately engaged in the transmission and distribution of electric energy and the generation and bulk purchase of electric energy for sale. The Company also transports, distributes and sells natural gas purchased from gas suppliers. Nearly all of the Company's customers are located in south and central Wisconsin. The Company operates in municipalities pursuant to permits of indefinite duration which are regulated by Wisconsin law. The Company does not derive a material portion of its revenues from any one customer.
The Company owns all of the outstanding capital stock of South Beloit Water, Gas and Electric Company ("South Beloit"), a public utility supplying electric, gas and water service, principally in Winnebago County, Illinois, which was incorporated on July 23, 1908.
The Company also owns varying interests in several other subsidiaries and investments which are not material to the Company's operations.
REGULATION
The Company is subject to regulation by the PSCW as to retail utility rates and service, accounts, issuance and use of proceeds of securities, certain additions and extensions to facilities, and in other respects. South Beloit is subject to regulation by the Illinois Commerce Commission ("ICC") for similar items. The Federal Energy Regulatory Commission ("FERC") has jurisdiction under the Federal Power Act over certain of the electric utility facilities and operations, wholesale rates and accounting practices of the Company and in certain other respects. Certain of the Company's natural gas facilities and operations are subject to the jurisdiction of the FERC under the Natural Gas Act. The Company is presently exempt from all provisions of the Public Utility Holding Company Act of 1935, except provisions relating to the acquisition of securities of other public utility companies.
An anticipated change in the regulatory environment is the movement towards the deregulation of certain aspects of utility operations. The Company is in the process of evaluating the impacts of such deregulation.
With respect to environmental matters, the United States Environmental Protection Agency administers certain federal statutes; others are delegated to the Wisconsin Department of Natural Resources ("DNR"). In addition, the DNR has jurisdiction over air and water quality standards associated with fossil fuel fired electric generation and the level and flow of water, safety and other matters pertaining to hydroelectric generation.
The Company is subject to the jurisdiction of the Nuclear Regulatory Commission ("NRC") with respect to the Kewaunee nuclear plant and to the jurisdiction of the United States Department of Energy ("DOE") with respect to the disposal of nuclear fuel and other radioactive wastes from the Kewaunee Nuclear Power Plant ("Kewaunee").
EMPLOYEES
At year-end 1993, the Company employed 2,673 persons, of whom 2,136 were considered electric utility employees, 387 were considered gas utility employees and 150 were considered other utility employees. The Company has a three-year contract with members of the International Brotherhood of Electrical Workers, Local 965, that is in effect until June 1, 1996. The contract covers 1,742 of the Company's employees.
ELECTRIC OPERATIONS
General
The Company provides electricity in a service territory of approximately 16,000 square miles in 35 counties in southern and central Wisconsin and four counties in northern Illinois. As of December 31, 1993, the Company provided retail electric service to approximately 360,000 customers in 609 cities, villages and towns, and wholesale service to 25 municipal utilities, 1 privately owned utility, three rural electric cooperatives and to Wisconsin Public Power, Inc. System, which provides retail service to nine communities.
The Company owns 21,579 miles of electric transmission and distribution lines and 351 substations located adjacent to the communities served.
The Company's electric sales are seasonal to some extent with the yearly peak normally occurring in July or August. The Company also experiences a smaller winter peak in December or January.
Fuel
In 1993, approximately 80 percent of the Company's net kilowatthour generation of electricity was fueled by coal and 17 percent by nuclear fuel (provided by the Company's 41 percent ownership interest in Kewaunee). The remaining electricity generated was produced by hydroelectric, oil-fired and natural gas generation.
Coal
The Company anticipates that its average fuel costs will increase in the future, due to cost escalation provisions in existing coal and transportation contracts and increases in the costs of new coal contracts due to emission requirements under federal and state laws.
The estimated coal requirements of the Company's generating units (including jointly-owned facilities) for the years 1994 through 2013 total about 166 million tons. Present coal supply contracts and transportation contracts (excluding extension options) cover approximately 25 percent and 24 percent, respectively, of this estimated requirement. The Company will seek renewals of existing contracts or additional sources of supply and negotiate new or additional transportation contracts to satisfy the requirements of approved environmental regulations.
Nuclear
Kewaunee is jointly owned by the Company (41%), Wisconsin Public Service Corporation (41.2%) and Madison Gas & Electric Company (17.8%). Wisconsin Public Service Corporation is the operating partner. The plant began commercial operation in 1974.
The supply of fuel for Kewaunee involves the mining and milling of uranium ore to uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, enrichment of the uranium hexafluoride and fabrication of the enriched uranium into usable fuel assemblies. The following narrative discusses the nuclear fuel supplies for Kewaunee which requires approximately 250,000 pounds of uranium concentrates per year. Additionally, the Company and the other Kewaunee co-owners formed a limited partnership of subsidiaries in the mid-1970's to secure uranium reserves and maintain a long-term uranium concentrates supply capability.
(a) Requirements for uranium are met through spot market purchases of uranium. In general a four-year supply of uranium is maintained.
(b) Uranium hexafluoride, from inventory and from spot market purchases, was used to satisfy converted material requirements in 1993. Such conversion services will be purchased on the spot market in the future.
(c) In 1993, enriched uranium was procured from COGEMA, Inc. pursuant to a contract executed in 1983 and last amended in 1991. The partnership is obligated to take delivery of additional enriched uranium contracted from COGEMA in 1993 and 1994. The partnership also purchased enriched uranium on the spot market in 1993. Enrichment services were purchased from the DOE under the terms of the utility services contract. This contract is in effect for the life of Kewaunee. The partnership is committed to take 70 percent of its annual requirements in 1994 and 1995, and in alternate years thereafter from the DOE.
(d) Fuel fabrication requirements through 1995 are covered by contract. This contract contains an option to allow the partnership to extend the contract through 1998.
(e) Beyond the stated periods for Kewaunee, additional contracts for uranium concentrates, conversion to uranium hexafluoride, fabrication and spent fuel storage will have to be procured. The prices for the foregoing are expected to increase.
The National Energy Policy Act of 1992 provides that both the Federal government and the nuclear utilities fund the decontamination and decommissioning of the three federal gaseous diffusion plants in the United States. This will require the owners of the Kewaunee to pay approximately $15 million, in current dollars over a period of 15 years. The Company's share amounts to an annual payment of approximately $410,000.
The steam generator tubes at Kewaunee are susceptible to corrosion characteristics seen throughout the nuclear industry. Annual inspections are performed to identify degraded tubes. Degraded tubes are either repaired by sleeving or are plugged with approximately 15 percent heat transfer margin, meaning that full power should be sustainable with the equivalent of 15 percent of the steam generator tubes plugged. Currently, the equivalent of 10 percent of the tubes in the steam generators are plugged. The Company and the other joint owners continue to evaluate appropriate strategies, including replacement, as well as continued operation of the steam generators without replacement. The Company and the joint owners intend to operate Kewaunee until at least 2013, the expiration of the present operating license. The Company and the joint owners are also evaluating initiatives to improve the performance of Kewaunee. These initiatives include funding of the development of welded repair technology for steam generator tubes and numerous cost reduction measures such as the conversion from a 12-month to an 18-month fuel cycle. If the steam generators are not replaced, and excluding the possible affect of the aforementioned repair strategies, a gradual power reduction of approximately 1 percent per year may begin as soon as 1995.
Physical decommissioning is expected to occur during the period 2014 to 2021 with additional expenditures being incurred during the period 2022 to 2050 related to the storage of spent nuclear fuel at the site. The Company's share of the decommissioning costs of this plant is estimated to be $149 million (in 1993 dollars) based on a site specific study, performed in 1992, using immediate dismantlement as the method of decommissioning. Wisconsin utilities operating nuclear generating plants are required by the PSCW to establish external trust funds to provide for the decommissioning of such plants. The market value of the investments in the funds established by the Company at December 31, 1993 totaled $45.1 million.
Pursuant to the Nuclear Waste Policy Act of 1982, the DOE has entered into a contract with the Company to accept, transport and dispose of spent nuclear fuel beginning not later than January 31, 1998. It is likely that the DOE will delay the acceptance of spent nuclear fuel beyond 1998. A fee to offset the costs of the DOE's disposal for all spent fuel used since April 7, 1983 has been assessed by the DOE at one mill per net kilowatthour of electricity generated and sold by the Kewaunee nuclear power plant. An additional one-time fee was paid for the disposal of spent nuclear fuel used to generate electricity prior to April 7, 1983.
Spent fuel is currently stored at Kewaunee. The existing capacity of the spent fuel storage facility will enable storage of the projected quantities of spent fuel through April 2001. The Company is currently evaluating options for the storage of additional quantities beyond 2001. Several technologies are available. It is expected that the larger capacity requirements for spent nuclear fuel storage will require a capital investment in the late 2000's.
The Low-Level Radioactive Waste Policy Act of 1980 as amended in 1985 provides that states may enter into compacts to provide for regional low-level waste disposal facilities. The amended Act provides that after January 1, 1993, compact members may restrict the use of regional disposal facilities to waste generated within the region. Wisconsin is a member of the Midwest Interstate Low-Level Radioactive Waste Compact which includes six Midwestern states and was ratified by Congress. A Midwest disposal facility is not expected to be operational until the late 1990's. Presently, the state of Ohio has been selected as the host state for the Midwest Compact and is proceeding with the preliminary phases of site selection. In the meantime, the Company has access to an existing low level waste storage space to temporarily store low level waste generated.
Recovery of Electric Fuel Costs
The Company does not automatically pass changes in electric fuel cost through to its Wisconsin retail electric customers. Instead, rates are based on estimated per unit fuel costs established during rate proceedings and are not subject to change by fuel cost fluctuations unless actual costs are outside specified limits. If actual fuel costs vary from the estimated costs by more than +10 percent in a month or by more than +3 percent for the test year to date, projected annual variances are then estimated. If the projected annual variance is more than +3 percent, rates are subject to hearings and increase or decrease by the PSCW.
The Company's wholesale rates and South Beloit's retail rates contain fuel adjustment clauses pursuant to which rates are adjusted monthly to reflect changes in the costs of fuel.
Environmental Matters
The Company cannot precisely forecast the effect of future environmental regulations by federal, state and local authorities upon its generating, transmission and other facilities, or its operations, but has taken steps to anticipate the future while meeting the requirements of approved environmental regulations of today. The Clean Air Act Amendments of 1977 and subsequent amendments to the Clean Air Act, as well as the new laws affecting the handling and disposal of solid and hazardous wastes along with clean air legislation passed in 1990 by Congress, could affect the siting, construction and operating costs of both present and future generating units (see "Item 3. Legal Proceedings").
Under the Federal Clean Water Act, National Pollutant Discharge Elimination System permits for generating station discharge into water ways are required to be obtained from the DNR, to which the permit program has been delegated. These permits must be periodically renewed. The Company has obtained such permits for all of its generating stations or has filed timely applications for renewals of such permits.
Air quality regulations promulgated by the DNR in accordance with Federal standards impose statewide restrictions on the emission of particulates, sulfur dioxide, nitrogen oxides and other air pollutants and require permits from the DNR for the operation of emission sources. The Company currently has the necessary permits to operate its fossil-fueled generating facilities.
Pursuant to Wisconsin statutes 144.386(2), the Company has submitted data and plans for 1993 sulfur dioxide emissions compliance. The Company will make any necessary operational changes in fuel types and power plant dispatch to comply with the Plan.
The Company's compliance strategy for Wisconsin's 1993 sulfur dioxide law and the Federal Clean Air Act Amendments required plant upgrades at its generating facilities. The majority of these projects were completed in 1992. The Company will be installing continuous emissions monitoring systems at all of its coal fired boilers 1994. Coal handling equipment upgrades will also be made at the Edgewater facility in 1994. Total expenditures for these projects are expected to be $3.5 million. No additional costs for compliance with these acid rain requirements are anticipated at this time.
The Company maintains licenses for all its ash disposal facilities and regularly reports to the DNR groundwater data and quantities of ash landfilled or reused. The landfills are operated according to a Plan of Operation approved by the DNR.
The Company's accumulated pollution abatement expenditures through December 31, 1993, totaled approximately $122 million. The major expenditures consist of about $60 million for the installation of electrostatic precipitators for the purpose of reducing particulate emissions from the Company's coal-fired generating stations and approximately $62 million for other pollution abatement equipment at the Columbia, Edgewater, Kewaunee, Nelson Dewey, Rock River and Blackhawk plants. Expenditures during 1993 totaled approximately $6 million. Estimated pollution abatement expenditures total $.7 million through 1995. The Company's estimated pollution abatement expenditures are subject to continuing review and are revised from time to time due to escalation of construction costs, changes in construction plans and changes in environmental regulations.
See "Electric Operations - Fuel" for information concerning the disposal of spent nuclear fuel and high level nuclear waste.
GAS OPERATIONS
General
As of December 31, 1993, the Company provided retail natural gas service to approximately 136,000 customers in 217 cities, villages and towns in 22 counties in southern and central Wisconsin and one county in northern Illinois.
The Company's gas sales follow a seasonal pattern. There is an annual base load of gas used for heating, cooking, water heating and other purposes, with a large peak occurring during the heating season.
In 1993, the Company purchased significant volumes of lower cost gas directly from producers and marketers and transported those volumes over its two major pipeline supplier's systems. This replaced higher cost gas historically purchased directly from the major pipeline systems. The Company transported gas for 85 end users at year-end 1993.
Gas Supplies
In 1992 the FERC issued Order No. 636 and 636-A which requires interstate pipelines to restructure their services. Under these orders, existing pipeline sales service would be "unbundled" such that gas supplies would be sold separately from interstate transportation services. Both of the interstate pipelines which serve the Company, ANR Pipeline and Northern Natural Pipeline, completed their transition to unbundled services as mandated by the FERC in its Order 636 during 1993. As a result, the Company now contracts with these two parties for various unbundled services such as firm and interruptible transportation, firm and interruptible storage service and "no-notice" service. The Company has benefited from enhanced access to competitively priced gas supplies, and from more flexible transportation services. Pipelines are, however, seeking to recover from their customers certain transition costs associated with restructuring. Any such recovery is subject to prudence hearings at the FERC and state regulatory commissions.
With the pipelines exiting their historic role of selling gas to the Company, the utility has increased its contracting activity with producers and marketers of natural gas correspondingly. The Company's portfolio of gas supply contracts are designed to meet the needs of gas customers and extend from one month to 10 years in term.
The most significant change in the Company's mix of gas contracts for 1993 are: 1) a significant increase in the volume of Canadian gas contracted for, and 2) a large increase in firm storage service from the pipelines.
The new Canadian contract commitments represent the Company's successful negotiations to minimize the "transition costs" of moving to the unbundled, post-Order 636 environment. In mid 1993, the Company was faced with the decision of whether to negotiate with the Canadians to reform the terms of long-term contracts which were in place with the two pipelines and assume the contracts on the renegotiated terms, or pay the pipelines to buy out of these contract commitments with the Canadians. The Company opted for the latter approach at an estimated savings of over $16 million to the Company's customers. In 1993, the Company increased its peak-day entitlements on ANR pipeline by 16,000 dekatherms per day reflecting the need for additional firm capacity in order to meet the load growth of firm customers.
The Company maintains gas storage agreements with ANR Pipeline and a third party storage service provider. The storage agreements allow the Company to purchase a portion of its gas supply between April and October, when natural gas costs usually are lower. The less expensive gas is stored in the storage fields and is withdrawn between November and March when gas costs typically are higher. The agreements have terms extending through March 31, 1995 and March 31, 1997.
The Company's current portfolio of contracts is as follows:
ANR Pipeline
Contract year 1989-90 1990-91 1991-92 1992-93 1993-94 Maximum daily entitlement: (000 Dt per day) Contract demand 120.0 81.5 81.5 81.5 0 Firm transportation 25.5 25.9 25.9 25.9 80.0 Firm storage - 40.1 40.1 40.1 83.5 ------ ------ ------ ------ ------ Total 145.5 147.5 147.5 147.5 163.5 ====== ====== ====== ====== ====== Maximum annual entitlement (000 Dt) 11,400 11,680 11,680 N/A N/A
Northern Natural Pipeline
Contract year 1989-90 1990-91 1991-92 1992-93 1993-94 (a) (a) Maximum daily entitlement: (000 Dt per day)
Contract demand 19.9 19.9 16.9 -- -- Firm transportation 13.7 13.7 26.5 53.6 53.6 Firm storage - - 2.2 1.5 8.5 "Unbundled" sales - - - 16.9 1.4 ------ ------ ------ ------ ------ Total 33.6 33.6 45.6 53.6 53.6 ====== ====== ====== ====== ======
Maximum annual entitlement (000 Dt) 5,815 5,815 N/A N/A N/A
(a) Total no longer equals sum of components. Currently, Northern Natural requires that the Company hold firm transportation equal to its total peak-day requirements. Firm storage, "unbundled" sales from Northern Natural, and third party gas supply (not shown) are all eligible gas sources to be moved to the Company's city gates via this firm transportation. Contract demand services from Northern Natural in its previous form, has been eliminated.
The future cost of natural gas is expected to be market sensitive. The Company's rate schedules applicable to all retail gas customers provide for adjustments of its rates, upon notice by the Company to the PSCW, to reflect all increases or decreases in the cost of gas purchased for resale. Increases or decreases in such costs are reflected automatically by adjustments to customers' bills commencing with meters read following the effective date of any changes in such costs.
One of the biggest changes which the Company faces in the post-Order 636 environment is dealing with the heightened emphasis placed upon daily balancing of the economic utilization of the Company's two pipelines.
As the natural gas market continues to evolve, The Company continuously evaluates products and services provided by pipelines and gas suppliers to meet the changing needs of its firm and interruptible gas customers.
Environmental Matters
Manufactured Gas Plant Sites. Historically, the Company has owned 11 properties that have been associated with the production of manufactured gas. Currently, the Company owns five of these sites, three are owned by municipalities, and the remaining three are owned by private companies. In 1989, the Company initiated investigation of these manufactured gas plant sites. The Wisconsin Department of Natural Resources ("DNR") has been involved in reviewing preliminary investigation plans and has received reports regarding these investigations. Based on the results of the Company's preliminary investigations, the Company recorded an estimated liability and corresponding deferred charge of approximately $15 million as of December 31, 1991.
In 1992, and into the beginning of 1993, the Company continued its investigations and studies. The Company confirmed that there was no contamination at two of the sites and received a close out letter from the DNR related to one of those sites and requested a close out letter for the other site. Additionally, the investigation of historical records at a third site indicated a minimal likelihood of any significant environmental impacts. In February 1993, the Company completed more current cost estimates for the environmental remediation of the eight remaining sites. The results of this more current analysis indicated that during the next 35 years, the Company will expend approximately $81 million for feasibility studies, data collection, soil remediation activities, groundwater research and groundwater remediation activities, including construction of slurry containment walls and the installation of groundwater pump and treatment facilities. This estimate was based on various assumptions, and is subject to continuous review and revision by management.
Based on the cost estimate set forth above, which assumes a 4 percent average inflation over the 35 year period, the Company will spend approximately $4.2 million, $1.5 million, $2.1 million, $4.4 million and $4.2 million in 1994 through 1998, respectively. The cost estimate also contemplates that primarily groundwater pump and treatment activities will take place after 1998 through and including 2027. During this time, the Company estimates that it will incur average annual costs of $2.0 million to complete the planned groundwater remediation activities.
With respect to rate recovery of these costs, the PSCW has approved a five year amortization of the unamortized balance of incurred environmental costs deferred to date.
Based on the present regulatory record at the PSCW, management believes that future costs of remediating these manufactured gas plant sites will be recovered in rates.
ITEM 2.
ITEM 2. PROPERTIES
GENERAL
The following table gives information with respect to electric generating facilities of the Company (including the Company's portion of those facilities jointly owned).
The maximum net hourly peak load on the Company's electric system was 1,971,000 kwh's and occurred on August 26, 1993. At the time of such peak load, 2,310,000 kwh's were produced by generating facilities operated by the Company (including other Company shared jointly owned facilities) and the Company delivered 812,000 kwh's of power and received 473,000 kwh's of power from external sources. During the year ended December 31, 1993, about 86.4 percent of the Company's total kilowatthour requirements was generated by Company-owned and jointly-owned facilities and the remaining 13.6 percent was purchased. Substantially all of the Company's facilities are subject to the lien of its first mortgage bond indenture.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
There are no material pending legal proceedings, other than ordinary routine litigation incidental to the business, to which the Company or any of its subsidiaries is a party or to which any of their property is subject.
ENVIRONMENTAL MATTERS
The information required by Item 3 is included in this Form 10-K as Item 8 - Notes to Consolidated Financial Statements, Note 10c, incorporated herein by reference.
RATE MATTERS
The information required by Item 3 is included in Item 7 of this Form 10-K within the Management's Discussion and Analysis of Financial Condition and Results of Operations narrative under the caption "Rates and Regulatory Matters."
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
Erroll B. Davis, Jr, 49, was elected President and Chief Executive Officer, effective August 1, 1988 and has been a board member since April 1984. He had been Executive Vice President since May 1984, Vice President - Finance and Public Affairs since November 1982 and Vice President - Finance since August 1978. Mr. Davis was elected President of WPL Holdings, Inc. on January 17, 1990 and Chief Executive Officer of WPL Holdings, Inc. effective July 1, 1990. He has served as a director of WPL Holdings, Inc. since March 1988.
A. J. (Nino) Amato, 42, was appointed Senior Vice President effective October 3, 1993. He previously served as Vice President - Marketing and Strategic Planning since December 1992, Vice President - Marketing and Communications since January 1989 and Director of Electric Marketing and Customer Service since October 1988. He had been President of Forward Wisconsin, Inc. from 1987 to 1988.
Norman E. Boys, 49, was elected Vice President of Power Production effective January 1, 1989. He previously served as the Director of Power Production since October 1987 and Generating Station Manager at the Edgewater Generating Station since August 1984.
Thomas L. Consigny, 59, has been Assistant Vice President - Public Affairs since October 1976.
Daniel A. Doyle, 35, was appointed controller and treasurer effective October 3, 1993. He previously served as controller since July 1992. Prior to joining the Company, he was Controller of Central Vermont Public Service Corporation since December 1988. During the period 1981 to 1988, he was employed by Arthur Andersen & Co. as an Audit Staff Assistant, Audit Senior and Audit Manager with primary responsibilities of auditing and providing financial consulting services to large publicly held corporations.
David E. Ellestad, 53 was appointed Vice President-Electrical Engineering and Operations on August 1, 1992. He previously served as Vice President-Engineering and Operations since 1988; Vice President of Electrical Engineering and Procurement since January 1, 1986; Director of Electrical Engineering & Procurement since May 1985 and Director of Electrical Engineering since November 1979.
Thomas L. Hanson, 40, was elected Assistant Treasurer on May 17, 1989. He had been Financial Relations Supervisor in the Treasury Department since October 1987.
Thomas J. Handziak, 30, was elected Assistant Controller on September 20, 1993. Prior to joining the Company, he was employed by Arthur Andersen & Co. as an Audit Staff Assistant, Audit Senior and Audit Manager with primary responsibilities of auditing and providing financial consulting services to large publicly held corporations.
William D. Harvey, 44, was appointed Senior Vice President effective October 3, 1993. He previously served as Vice President-Natural Gas and General Counsel since August 1992, Vice President-General Counsel since October 1, 1990 and Vice President-Associate General Counsel since July 1986. Prior to joining the Company, he was a member of the law firm of Wheeler, Van Sickle, Anderson, Norman and Harvey.
Steve F. Price, 41, was appointed Assistant Corporate Secretary on April 15, 1992. He had been Cash Management Supervisor since December 1987. He was also appointed Assistant Corporate Secretary and Assistant Treasurer of WPL Holdings, Inc. on April 15, 1992.
Eliot G. Protsch, 40, was appointed Senior Vice President effective October 3, 1993. He previously served as Vice President-Customer Services and Sales since August 1992, Vice President and General Manager-Energy Services since January 1989 and District Manager, Dane County, since October 1986.
Pamela J. Wegner, 46 was elected Vice President-Information Services and Administration on October 13, 1994. Prior to joining the Company, she was the Administrator of the Division of Finance and Program Management in the Wisconsin Department of Administration since 1987. She served as administrator of the Division of Administrative Services in the Wisconsin Department of Revenue from 1983 to 1987.
Kim K. Zuhlke, 40 was elected Vice President - Customer Services and Sales effective October 3, 1993. He previously served as Director of Marketing and Sales Services since 1991, Director of Market Research, Planning and Development since February 1990, Director of Customer Services since 1988 and District Manager at Beaver Dam since April 1984.
NOTE: All ages are as of December 31, 1993. None of the executive officers listed above is related to any director of the Board or nominee for director of the Company.
Executive officers of the Company have no definite terms of office and serve at the pleasure of the Board of Directors.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Effective with the formation of the holding company, all $5 par value common stock of the Company was owned and converted by WPL Holdings, Inc. to $.01 par value common stock of WPL Holdings, Inc. WPL Holdings is now the sole common shareowner of the Company.
The Company's dividend payments for administrative allowance and other costs throughout 1993 and 1992 totaled $1,000,000. Regular cash dividends paid per share of common stock during 1993 and 1992 to WPL Holdings, Inc. were 95 cents and 94 cents, respectively for each quarter.
ITEMS 6 and 7. SELECTED FINANCIAL DATA AND MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
WISCONSIN POWER AND LIGHT COMPANY
Management's Discussion and Analysis of Financial Condition and Results of Operations
1993 COMPARED WITH 1992
OVERVIEW
Wisconsin Power and Light Company's (the "Company") 1993 net income increased 9 percent to $60.2 million compared with $55.4 million in 1992. The principle factors leading to increased earnings include warmer summer weather and lower electric fuel costs per kilowatthour ("kWh") which yielded higher electric gross margins for the Company. These increases were somewhat offset by increased depreciation expense resulting from additional investment in utility plant, a change in the mix of gas sales from higher margin sales to lower margin sales, the increase in the Federal corporate tax rate from 34% to 35% and a one-time 4-cent-per- share charge associated with a voluntary separation program for the executive management group.
The Company's electric margin, in dollars, increased during 1993 compared with 1992 due to increased demand for electricity brought on by warmer summer weather. Residential customers, being the most weather sensitive, experienced the most significant increases. Wisconsin's strong economy kept the Commercial and Industrial classes growing steadily. These increases were coupled with declining electric production fuel costs per kWh. The decrease in electric production fuels is due to the Company's aggressive pursuit of additional spot coal purchase opportunities as its longer term contracts begin to expire. Additionally, a highly competitive rail transportation environment has significantly reduced the cost of transporting the coal. Also, lower cost purchased power became available due to excess capacity in the bulk power market.
The Company's gas revenues for 1992 were affected by the recognition of a $4.9 million, before-tax refund to its natural gas customers resulting from an adjustment in the calculation of the purchased gas adjustment clause. Without the impact of this revenue adjustment, comparative gas margins would have declined for 1993 compared with 1992.
The overall increases in gas revenues and purchased gas expense between years resulted primarily from increased volumes procured on behalf of transportation customers. This had the impact of decreasing margins as a percentage of total revenues. A change in the mix of gas sales from higher margin residential sales to lower margin sales also moved margins downward. Offsetting this decline, Wisconsin's strong economy enabled growth in the Commercial and Industrial classes, and there was also some overall increase in the demand for natural gas due to colder weather.
Other Operation Expense
Other operation expense increased as a result of higher employee benefit expenses (See Notes to Consolidated Financial Statements, Note 8). These increases were offset somewhat by decreases in the Company's conservation program expenditures and decreases in fees associated with the sale of the Company's accounts receivable due to a decline in interest rates. Additionally, the Company's cost management efforts have helped control annual inflationary pressures on general and administrative costs.
Maintenance and Depreciation and Amortization
Maintenance expense increased for 1993 compared with 1992, primarily due to service restoration expenses related to a severe storm in the summer of 1993. Depreciation and amortization expense increased, principally reflecting increased property additions and the commencement of deferred charge amortizations approved in the Company's last two rate orders received in December 1992 and October 1993. The most significant amortizations include the amortization related to an acquisition adjustment which resulted from the purchase of transmission facilities and the amortization of costs incurred related to the remediation of former manufactured gas plant sites (See Notes to the Consolidated Financial Statements, Note 10).
Allowance for Funds Used During Construction ("AFUDC")
Total AFUDC increased in 1993 compared with 1992, reflecting the greater amounts of construction work in progress including the costs associated with the Company's construction of two 86-megawatt combustion-turbine generators.
1992 COMPARED WITH 1991
Company Overview
The Company's 1992 net income decreased 13 percent to $59.2 million compared with $67.9 million in 1991. A combination of an electric rate decrease in March 1992 and significantly cooler summer weather led to lower electric revenues, gross margins and earnings at the Company. The Company's earnings were also affected by the recognition of a $4.9 million, before-tax refund to natural gas customers noted previously.
The Company's electric margin decreased during 1992 compared with 1991 due to decreased demand for electricity brought on by cooler summer weather. Residential customers, being the most weather sensitive, experienced the most significant decreases. However, improved economic conditions in 1992 kept the Industrial customer class growing steadily. Sales to commercial customers remained flat despite the negative weather impact due to increased customer growth in this sector and the improving economy. As a result of significantly lower weather-related peak demands, sales and revenues to other Class A utilities decreased. Electric production fuels expense decreased in response to reduced kWh sales, lower fuel costs and a greater reliance on purchased power. Purchased power expense increased in 1992 due to the greater availability of purchased power at competitive prices.
After adjusting 1992 gas revenues for the customer refund noted previously, both gas revenues and gas margins increased during 1992 compared with 1991. Overall increases in gas revenues between years resulted primarily from the recovery of increased purchased gas costs through the purchased gas adjustment clause. Gas margins benefited from an increase in gas customers. The impacts of weather were comparable between years.
Other Operation Expense
Contributing to the decrease in other operation expense at the Company was a decrease in the Company's conservation program expenditures, a decrease in fees associated with the sale of the Company's accounts receivable due to a decline in interest rates, and reduced employee benefit expenses. Additionally, the Company's cost management efforts have helped control annual inflationary pressures on general and administrative costs.
Maintenance and Depreciation and Amortization Expense
Maintenance expense increased for 1992 compared with 1991, primarily due to an increased tree trimming program, increased costs associated with scheduled overhauls at generating units and major service restoration expenses related to three tornados which caused extensive damage to the Company's service territory during the summer of 1992. Depreciation expense increased, principally reflecting increased property additions.
Allowance for Funds Used During Construction ("AFUDC") and Other, net
Total AFUDC increased in 1992 compared with 1991, reflecting the greater amounts of construction work in progress which includes the costs associated with the Company's construction of two 86-megawatt combustion- turbine generators.
Interest Expense
Interest expense on bonds decreased between years, primarily due to increased debt outstanding to fund construction activity. This increase was somewhat offset by the Company's refinancing activities during 1992. To take advantage of recent low interest rates, the Company issued $279 million principal amount of first mortgage bonds, of which $235 million was used to refinance the aggregate principal amount of existing series. The bonds, which had coupon payments ranging from 8 to 10 percent, were replaced with issues having coupons of 6.125 percent to 8.6 percent.
Income Taxes
Income taxes decreased between years, primarily due to lower taxable income and an increase in tax credits associated with affordable housing investments in 1992 compared with 1991.
LIQUIDITY AND CAPITAL RESOURCES
Rates and Regulatory Matters
On September 30, 1993, the Company received final decisions from the PSCW on its retail rate application filed in early 1993. The final order authorized an annual retail electric rate increase of $15.6 million, or 3.8 percent; a natural gas rate increase of $1.8 million, or 1.4 percent; and a nominal water rate increase. The new rates became effective October 1, 1993 and will remain effective until January 1, 1995. The regulatory return on common equity for the Company was reduced from 12.4 percent to 11.6 percent. The allowed rates of return authorized by the Company's regulators have decreased due to declines in debt capital costs and equity investor rate of return expectations.
On August 6, 1993 the Federal Energy Regulatory Commission ("FERC") approved the Company's request for a $2.1 million, or 2.9 percent increase in wholesale rates. The rates became effective October 1, 1993.
Electric and Gas Sales Outlook
To deal with competitive pressures arising from regulatory changes, the Company is forecasting to hold retail rates flat through 1996. The National Energy Policy Act contains a provision calling for "open transmission access". The Company anticipates that retail wheeling will become a reality within a few years. In order to meet these new competitive challenges and maintain a low cost pricing advantage, the Company's objective is to manage costs to maintain profitability while limiting any rate changes until 1997. These forecasts are subject to a number of assumptions, including the economy and weather. The Company anticipates that its customer base will remain strong in the electric sectors and that favorable gas prices over alternative fuels prices should result in sales growth in gas sectors. Growth in customers' demand for electric service will require capacity additions. Capacity requirements will be met through increased generating capacity (two combustion-turbines in mid-1994), continuation of existing long-term contracts for purchase of capacity, increased efficiency at existing power plants from capital improvements and continued emphasis on cost effective demand-side management programs such as direct load control rate options including interruptible rates and conservation programs.
Financing and Capital Structure
The level of short-term borrowings fluctuates based on seasonal corporate needs, the timing of long-term financing and capital market conditions. To maintain flexibility in its capital structure and to take advantage of favorable short-term rates, the Company also uses proceeds from the sales of accounts receivable and unbilled revenues to finance a portion of its long-term cash needs. The Company also anticipates that short-term debt funds will continue to be available at reasonable costs due to strong ratings by independent utility analysts and rating services. Commercial paper has been rated A-1+ by Standard & Poor's Corp. (S&P) and P-1 by Moody's Investors Service (Moody's). Bank lines of credit of $70 million at December 31, 1993 are available to support these borrowings (see "Notes to Consolidated Financial Statements," Note 11).
The Company's capitalization at December 31, 1993, including the current maturities of long-term debt, variable rate demand bonds and short-term debt, consisted of 50.5 percent common equity, 5.8 percent preferred stock and 43.7 percent long-term debt. The common equity to total capitalization ratio at December 31, 1993 increased to 50.5 percent from 44.2 percent at December 31, 1992 due to the receipt of $61 million of capital contributions from WPL Holdings, Inc. during 1993.
A retail rate order effective October 1, 1993, requires the Company to maintain a utility common equity level of 50.31 percent of total utility capitalization during the test year August 1, 1993 to July 31, 1994. In addition, the PSCW ordered that it must approve the payment of dividends by the Company to WPL Holdings, Inc. that are in excess of the level forecasted in the projected test year ($56.8 million), if such dividends would reduce the Company's average common equity ratio below 50.31 percent.
Capital Requirements
The Company is capital-intensive and requires large investments in long-lived assets. Therefore, the Company's most significant capital requirements relate to construction expenditures. Estimated capital requirements of the Company for the next five years are as follows:
Included in the construction expenditure estimates, in addition to the recurring additions and improvements to the distribution and transmission systems, are the following: expenditures for managing and controlling electric line losses and for the electric delivery system which will save electric line losses and enhance the Company's interconnection capability with other utilities; expenditures related to environmental compliance issues including the installation of additional emissions monitoring equipment and coal handling equipment; and expenditures associated with the construction of two 86-megawatt combustion-turbine generators expected to become operational in 1994 through 1996.
In addition, the steam generator tubes at the Kewaunee Nuclear Power Plant ("Kewaunee") are susceptible to corrosion characteristics seen throughout the nuclear industry. Annual inspections are performed to identify degraded tubes. Degraded tubes are either repaired by sleeving or are removed with approximately 15 percent heat transfer margin, meaning that full power should be sustainable with the equivalent of 15 percent of the steam generator tubes plugged. Currently, the equivalent of 10 percent of the tubes in the steam generators are plugged. The Company and the other joint owners continue to evaluate appropriate strategies, including replacement, as well as continued operation of the steam generators without replacement. The Company and the joint owners intend to operate Kewaunee until at least 2013, the expiration of the present operating license. The Company and the joint owners are also evaluating initiatives to improve the performance of Kewaunee. These initiatives include funding of the development of welded repair technology for steam generator tubes and numerous cost reduction measures such as the conversion from a 12-month to an 18-month fuel cycle. If the steam generators are not replaced, and excluding the possible affect of the aforementioned repair strategies, a gradual power reduction of approximately 1 percent per year may begin as soon as 1995.
Capital Resources
One of the Company's objectives is to finance construction expenditures through internally generated funds supplemented, when required, by outside financing. With this objective in place, the Company has financed an average of 71 percent of its construction expenditures during the last five years from internal sources. However, during the next five years, the Company expects this percentage to be reduced primarily due to the continuation of major construction expenditures and due to the maturity of $64 million of first mortgage bonds. External financing sources such as the issuance of long-term debt and short-term borrowings and equity investments from its parent company, WPL Holdings, Inc., will considered by the Company to finance the remaining construction expenditure requirements for this period. Current forecasts are that $71 million of additional equity and $60 million of long-term debt will be issued over the next three years.
The Company's financial condition has enabled it to pay interest charges, preferred stock dividends and common stock dividends out of current earnings. Return on equity for 1993 was 12.4 percent and has averaged 13.6 percent over the last five years.
INFLATION
Under current ratemaking methodologies prescribed by the various commissions that regulate the Company, projected or forecasted operating costs, including the impacts of inflation, are incorporated into the Company's revenue requirements. Accordingly, the impacts of inflation on the Company are currently mitigated.
FINANCIAL ACCOUNTING STANDARDS BOARD (the "FASB") ACCOUNTING STANDARDS
ISSUED BUT NOT YET EFFECTIVE
In November 1992, the FASB issued Statement of Financial Accounting Standards No.112, "Employers' Accounting for Postemployment Benefits" ("SFAS 112"). SFAS 112 requires adoption of the new accounting and disclosure rules effective January 1, 1994. The impact on earnings will not be material.
OTHER EVENTS
In November 1989, the PSCW concluded that the Company did not properly administer a coal contract, resulting in an assessment to compensate ratepayers for excess fuel costs having been incurred. As a result, the Company recorded a reserve in 1989 which had an after-tax affect of reducing 1989 net income by $4.9 million. The PSCW decision was found to represent unlawful retroactive ratemaking by both the Dane County Circuit Court and the Wisconsin Court of Appeals. The case was then appealed to the Wisconsin Supreme Court.
Subsequent to December 31, 1993, the Wisconsin Supreme Court affirmed the decisions of the Dane County Circuit Court and Wisconsin Court of Appeals. Given the continued uncertainty related to the ultimate method of collection of the assessment from ratepayers to be approved by the PSCW, it is management's opinion that the financial impact of the Wisconsin Supreme Court's decision on the Company cannot currently be determined and will require further evaluation. As a result the Company will not adjust the reserve.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Wisconsin Power and Light Company:
We have audited the accompanying consolidated balance sheets and statements of capitalization of WISCONSIN POWER AND LIGHT COMPANY (a Wisconsin corporation and a wholly owned subsidiary of WPL Holdings, Inc.) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, common shareowner's investment and cash flows for each of the three years in the period ended December 31, 1993. 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, the financial statements referred to above present fairly, in all material respects, the financial position of Wisconsin Power and Light Company and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Milwaukee, Wisconsin, ARTHUR ANDERSEN & CO. January 28, 1994.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
WISCONSIN POWER AND LIGHT COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING AND REPORTING POLICIES:
a. Business and Consolidation:
The consolidated financial statements include Wisconsin Power and Light Company (the "Company") and its wholly owned consolidated subsidiaries, the principal of which is South Beloit Water, Gas and Electric Company. All significant intercompany transactions have been eliminated in consolidation. Certain amounts from prior years have been reclassified to conform with the current year presentation.
The Company is a public utility predominantly engaged in the transmission and distribution of electric energy and the generation and bulk purchase of electric energy for sale. The Company also transports, distributes and sells natural gas purchased from gas suppliers. Nearly all of the Company's customers are located in south and central Wisconsin.
b. Regulation:
The Company's financial records are maintained in accordance with the uniform system of accounts prescribed by its regulators. The Public Service Commission of Wisconsin ("PSCW") and the Illinois Commerce Commission have jurisdiction over retail rates, which represent approximately 86 percent of electric revenues plus all gas revenues. The Federal Energy Regulatory Commission ("FERC") has jurisdiction over wholesale electric rates representing the balance of electric revenues. Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" provides that rate-regulated public utilities such as the Company record certain costs and credits allowed in the ratemaking process in different periods than for the unregulated entities. These are deferred as regulatory assets or regulatory liabilities and are recognized in the Consolidated Statements of Income at the time they are reflected in rates.
c. Utility Plant:
Utility plant is recorded at original cost. Utility plant costs include financing costs which are capitalized through the PSCW- approved allowance for funds used during construction ("AFUDC"). The AFUDC capitalization rates approximate the Company's cost of capital. These capitalized costs are recovered in rates as the cost of the utility plant is depreciated.
Normal repairs and maintenance and minor items of utility plant and other property and equipment are expensed. Ordinary utility plant retirements, including removal costs less salvage value, are charged to accumulated depreciation upon removal from utility plant accounts, and no gain or loss is recognized. Upon retirement or sale of other property and equipment, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is included in other income and deductions.
d. Nuclear Fuel:
Nuclear fuel is recorded at its original cost and is amortized to expense based upon the quantity of heat produced for the generation of electricity. This accumulated amortization assumes spent nuclear fuel will have no residual value. Estimated future disposal costs of such fuel are expensed based on kilowatthours ("Kwh") generated.
e. Revenue:
The Company accrues utility revenues for services provided but not yet billed.
f. Fuel and Purchased Gas:
An automatic fuel adjustment clause for the FERC wholesale portion of the Company's electric business operates to increase or decrease monthly rates based on changes in fuel costs. The PSCW retail electric rates provide a range from which actual fuel costs may vary in relation to costs forecasted and used in rates. If actual fuel costs fall outside this range, a hearing may be held to determine if a rate change is necessary, and a rate increase or decrease can result.
The Company's base gas cost recovery rates permit the recovery of or refund to all customers for any increases or decreases in the cost of gas purchased from the Company's suppliers through a monthly purchased gas adjustment clause.
g. Cash and Equivalents:
The Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The carrying amount approximates fair value because of the short maturity of these items.
h. Income Taxes:
The Company is included in the consolidated federal income tax return of its parent, WPL Holdings, Inc. ("WPLH"), and calculates its federal tax provision and makes tax payments to WPLH as if the Company were a separate taxable entity. Beginning in 1993, the Company fully provides deferred income taxes in accordance with Statement of Financial Accounting Standards No.109, "Accounting for Income Taxes" ("SFAS 109"), to reflect tax effects of reporting book and tax items in different periods.
NOTE 2. DEPRECIATION:
The Company uses the straight-line method of depreciation. For utility plant, straight-line depreciation is computed on the average balance of depreciable property at individual straight-line PSCW approved rates as follows:
Electric Gas Water Common -------- --- ----- ------ 1993 3.6% 3.7% 2.5% 7.3% 1992 3.4 3.7 2.6 7.1 1991 3.4 3.7 2.6 6.9
NOTE 3. NUCLEAR OPERATIONS:
Depreciation expense related to the jointly-owned Kewaunee Nuclear Power Plant includes a provision for the decommissioning of the plant which totaled $6.1 million, $3.9 million and $4.1 million in 1993, 1992 and 1991, respectively. Wisconsin utilities with ownership of nuclear generating plants are required by the PSCW to establish external trust funds to provide for plant decommissioning. The market value of the investments in the funds established by the Company at December 31, 1993 and 1992, totaled $45.1 million and $42.8 million, respectively. The Company's share of the decommissioning costs is estimated to be $149 million (in 1993 dollars, assuming the plant is operating through 2013) based on a 1992 study, using the immediate dismantlement method of decommissioning.
Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy ("DOE") is responsible for the ultimate storage and disposal of spent nuclear fuel removed from nuclear reactors. Interim storage space for spent nuclear fuel is currently provided at the Kewaunee Nuclear Power Plant. Currently there is on-site storage capacity for spent fuel through the year 1999. Nuclear fuel, net, at December 31, 1993 and 1992 consists of (In Thousands of Dollars):
1993 1992 ---- ---- Original cost of nuclear fuel $147,325 $140,652 Less--Accumulated amortization 129,325 123,729 -------- -------- Nuclear fuel, net $ 18,000 $ 16,923 ======== ========
The Price Anderson Act provides for the payment of funds for public liability claims arising from a nuclear incident. Accordingly, in the event of a nuclear incident, the Company, as a 41 percent owner of the Kewaunee Nuclear Power Plant, is subject to an overall assessment of approximately $32.5 million per incident for its ownership share of this reactor, not to exceed $4.1 million payable in any given year.
Through its membership in Nuclear Electric Insurance Limited, the Company has obtained property damage and decontamination insurance totaling $1.4 billion for loss from damage at the Kewaunee Nuclear Power Plant. In addition, the Company maintains outage and replacement power insurance coverage totalling $99 million in the event an outage exceeds 21 weeks.
NOTE 4. PROPERTY:
a. Jointly Owned Utility Plants:
The Company participates with other Wisconsin utilities in the construction and operation of several jointly owned utility generating plants. The chart below represents the Company's proportionate share of such plants as reflected in the Consolidated Balance Sheets at December 31, 1993 and 1992 (In Thousands of Dollars):
Each of the respective joint owners finances its portion of construction costs. The Company's share of operations and maintenance expenses is included in the Consolidated Statements of Income.
b. Capital Expenditures:
The Company's capital expenditures for 1994 are estimated to total $142.6 million. Substantial commitments have been incurred for such expenditures.
NOTE 5. NET ACCOUNTS RECEIVABLE:
The Company has a contract with a financial organization to sell, with limited recourse, certain accounts receivable. These receivables include customer receivables resulting from sales to other public utilities as well as from billings to the co-owners of the jointly owned electric generating plants that the Company operates. The contract allows the Company to sell up to $100 million of receivables at any time. Consideration paid to the financial organization under this contract includes, along with various other fees, a monthly discount charge on the outstanding balance of receivables sold that approximated a 4.14 percent annual rate during 1993. These costs are recovered in retail utility rates as an operating expense. All billing and collection functions remain the responsibility of the Company. The contract expires August 19, 1995, unless extended by mutual agreement.
As of December 31, 1993 and 1992, proceeds from the sale of accounts receivable totaled $74 million and $69 million, respectively. During 1993, the Company sold an average of $75.9 million of accounts receivable per month, compared with $68.8 million in 1992.
As a result of its diversified customer base and the Company's sale of receivables, the Company does not have any significant concentrations of credit risk in the December 31, 1993 net accounts receivable balance.
NOTE 6. DEFERRED CHARGES AND OTHER:
Certain costs are deferred and amortized in accordance with authorized or expected rate-making treatment. As of December 31, 1993 and 1992, deferred charges and other include regulatory created assets and other noncurrent items representing the following (In Thousands of Dollars):
1993 1992 ---- ---- Unamortized debt redemption expense $13,178 $15,384 Decontamination and decommissioning costs of Federal enrichment facilities 6,181 6,150 Prepaid pension costs 26,128 21,226 Conservation loans to the Companys' customers (at cost which approximates market) 12,236 12,257 Tax related (see Note 7) 28,608 - Emission allowance credits receivable 5,335 5,335 Other 35,919 20,024 -------- ------- $127,585 $80,376 ======== ======= NOTE 7. INCOME TAXES:
The following table reconciles the statutory Federal income tax rate to the effective income tax rate: 1993 1992 1991 ---- ---- ---- Statutory Federal income tax rate 35.0% 34.0% 34.0% State income taxes, net of federal benefit 6.1 6.0 4.7 Investment tax credits restored (2.0) (2.4) (2.1) Amortization of excess deferred taxes (1.5) (1.6) (1.5)
Other differences, net (1.9) (2.0) (2.3) ---- ---- ---- Effective income tax rate 35.7% 34.0% 32.8% ==== ==== ====
Items which resulted in deferred income tax expense are as follows (In Thousands of Dollars): 1991 1992 ---- ---- Utility plant timing differences $4,104 $4,317 Qualified nuclear decommissioning trust contribution 709 709 Employee benefits 2,081 2,105 Other, net (755) (3,292) ------ ------ $6,139 $3,839 ====== ======
The temporary differences that resulted in accumulated deferred income tax assets and liabilities as of December 31, 1993 are as follows (In Thousands of Dollars):
Deferred Tax (Assets) Liabilities ------------ Accelerated depreciation and other plant related $171,993 Excess deferred taxes 22,744 Unamortized investment tax credits (22,812) Allowance for equity funds used during construction 13,518 Regulatory liability 19,179 Other 6,140 -------- $210,762 ========
Changes in the Company's deferred income taxes arising from the adoption of SFAS 109 represent amounts recoverable or refundable through future rates and have been recorded as net regulatory assets totalling approximately $29 million on the Consolidated Balance Sheets. These net regulatory assets are being recovered in rates over the estimated remaining useful lives of the assets to which they pertain.
NOTE 8. EMPLOYEE BENEFIT PLANS:
a. Pension Plans:
The Company has noncontributory, defined benefit retirement plans covering substantially all employees. The benefits are based upon years of service and levels of compensation. The Company's funding policy is to contribute at least the statutory minimum to a trust.
The projected unit credit actuarial cost method was used to compute net pension costs and the accumulated and projected benefit obligations. The discount rate used in determining those benefit obligations was 7.25 percent for 1993, and 8 percent for 1992 and 1991. The long-term rate of return on assets used in determining those benefit obligations was 9.75 percent for 1993 and 10 percent for 1992 and 1991.
The following table sets forth the funded status of the Companys' plans and amounts recognized in the Consolidated Balance Sheets at December 31, 1993 and 1992 (In Thousands of Dollars):
1993 1992 ---- ---- Accumulated benefit obligation-- Vested benefits $(135,303) $(119,883) Nonvested benefits (2,962) (869) --------- --------- $(138,265) $(120,752) ========= ========= Projected benefit obligation $(164,271) $(144,760) Plan assets at fair value, primarily common stocks and fixed income securities 183,881 164,771 --------- --------- Plan assets in excess of projected benefit obligation 19,610 20,011 Unrecognized net transition asset (21,823) (24,270) Unrecognized prior service cost 7,691 9,510 Unrecognized net loss 20,650 15,975 --------- --------- Prepaid pension costs, included in deferred charges and other $ 26,128 $ 21,226 ========= =========
The net pension (benefit) recognized in the Consolidated Statements of Income for 1993, 1992 and 1991 included the following components (In
Thousands of Dollars): 1993 1992 1991 ---- ---- ---- Service cost $ 4,263 $ 3,912 $ 3,167 Interest cost on projected benefit obligation 11,614 10,615 9,469 Actual return on assets (24,759) (12,143) (30,035) Amortization and deferral 8,430 (5,317) 14,603 -------- -------- -------- Net pension (benefit) $ (452) $ (2,933) $ (2,796) ======== ======== ========
b. Postretirement Health-care and Life Insurance:
Effective January 1, 1993, the Company prospectively adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("SFAS 106"). SFAS 106 establishes standards of financial accounting and reporting for the Company's postretirement health-care and life insurance benefits. SFAS 106 requires the accrual of the expected cost of such benefits during the employees' years of service based on actuarial methodologies that closely parallel pension accounting requirements. The Company has elected delayed recognition of the transition obligation and is amortizing the discounted present value of the transition obligation to expense over 20 years. The cost of providing postretirement benefits, including the transition obligation, is being recovered in retail rates and wholesale rates under current regulatory practices.
For 1993, the annual net postretirement benefits costs recognized in the Consolidated Statements of Income consist of the following components (In Thousands of Dollars):
Service cost $ 1,463 Interest cost on projected benefit obligation 3,151 Actual return on plan assets (696) Amortization of transition obligation 1,560 Amortization and deferral (27) ------- Net postretirement benefits cost $ 5,451 =======
The following table sets forth the plans' funded status recognized in the Consolidated Balance Sheets (In Thousands of Dollars):
---- Accumulated postretirement benefit obligation-- Retirees $ (27,358) Fully eligible active plan participants (5,429) Other active plan participants (9,980) --------- Accumulated benefit obligation (42,767) Plan assets at fair value 7,073 --------- Accumulated benefit obligation in excess of plan assets (35,694) Unrecognized transition obligation 29,638 Unrecognized loss 2,025 --------- Accrued postretirement benefit liability $ (4,031) =========
The postretirement benefits cost components for 1993 were calculated assuming health care cost trend rates ranging from 12.5 percent for 1993 and decreasing to 5 percent by the year 2002. The health care cost trend rate considers estimates of health care inflation, changes in utilization or delivery, technological advances, and changes in the health status of the plan participants. Increasing the health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1993 by $2.54 million and the aggregate of the service and interest cost components of postretirement expense by $.4 million.
The assumed discount rate used in determining the accumulated postretirement obligation was 7.25 percent. The long-term rate of return on assets was 9.50 percent. Plan assets are primarily invested in common stock, bonds and fixed income securities. The Company's funding policy is to contribute the tax advantaged maximum to a trust.
The costs for the postretirement health-care and life insurance benefits, based on an actuarial determination, were $1,335,000 and $1,078,000, respectively, for 1992 and 1991.
c. Other Postemployment Benefits:
In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" ("SFAS 112"). SFAS 112 establishes standards of financial accounting and reporting for the estimated cost of benefits provided by an employer to former or inactive employees after employment but before retirement. The effect of adopting SFAS 112, which must be adopted January 1, 1994, will not be material.
NOTE 9. CAPITALIZATION:
a. Common Shareowner's Investment:
A retail rate order effective October 1, 1993, requires the Company to maintain a utility common equity level of 50.31 percent of total utility capitalization during the projected test year August 1, 1993 to July 31, 1994. In addition, the PSCW ordered that it must approve the payment of dividends by the Company that are in excess of the level forecasted in the projected test year ($56.8 million), if such dividends would reduce the Company's average common equity ratio below 50.31 percent.
b. Preferred Stock:
On October 27, 1993, the Company issued two new series of preferred stock through two separate public offerings. The 6.2 percent Series is non-redeemable for ten years and the 6.5 percent Series is non- redeemable for five years. The proceeds from the sale were used to retire 150,000 shares of 7.56 percent Series and 149,865 shares of 8.48 percent Series preferred stock.
c. First Mortgage Bonds:
During 1992, the Company issued $279 million of first mortgage bonds, of which $235 million was used to refinance the principal amount of existing series in order to take advantage of lower interest rates. The remaining proceeds were used for the payment of short-term debt and general corporate purposes.
Substanitially all of the Company's utility plant is secured by its first mortgage bonds. Current maturities on first mortgage bond issues outstanding are as follows: none in 1994 through 1996, $55 million in 1997 and $8.9 million in 1998.
The fair value of the Company's first mortgage bonds is estimated at $428,841,000 and $406,281,000 as of December 31, 1993 and 1992, respectively, and is based on the quoted market prices for similar issues or on the current rates offered to the Company for similar debt.
NOTE 10. COMMITMENTS AND CONTINGENCIES:
a. Coal Contract Commitments:
To ensure an adequate supply of coal, the Company has entered into certain long-term coal contracts. These contracts include a demand or take-or-pay clause under which payments are required if contracted quantities are not purchased. Purchase obligations on these coal and related rail contracts total approximately $263 million through December 31, 2004. The Company's management believes it will meet minimum coal and rail purchase obligations under the contracts or recover in rates any demand or take-or-pay costs if minimum purchase obligations are not met. Minimum purchase obligations on these contracts over the next five years are estimated to be $67 million in 1994 and $27 million in 1995, 1996, 1997 and 1998, respectively.
b. Purchased Power:
Under firm purchase power contracts, the Company is obligated to pay $11 million, $8 million, $5 million, $7 million and $14 million in 1994, 1995, 1996, 1997 and 1998, respectively. For 1994, this represents 2,515 megawatts of capacity. Purchase obligations on these purchase power contracts total approximately $169 million through December 31, 2007.
c. Manufactured Gas Plant Sites:
Historically, the Company has owned 11 properties that have been associated with the production of manufactured gas. Currently, the Company owns five of these sites, three are owned by municipalities, and the remaining three are owned by private companies. In 1989, the Company initiated investigation of these manufactured gas plant sites. The Wisconsin Department of Natural Resources ("DNR") has been involved in reviewing preliminary investigation plans and has received reports regarding these investigations. Based on the results of the Company's preliminary investigations, the Company recorded an estimated liability and corresponding deferred charge of approximately $15 million as of December 31, 1991.
In 1992, and into the beginning of 1993, the Company continued its investigations and studies. The Company confirmed that there was no contamination at two of the sites and received a close out letter from the DNR related to one of those sites and requested a close out letter for the other site. Additionally, the investigation of historical records at a third site indicated a minimal likelihood of any significant environmental impacts. In February 1993, the Company completed more current cost estimates for the environmental remediation of the eight remaining sites. The results of this more current analysis indicated that during the next 35 years, the Company will expend approximately $81 million for feasibility studies, data collection, soil remediation activities, groundwater research and groundwater remediation activities, including construction of slurry containment walls and the installation of groundwater pump and treatment facilities. This estimate was based on various assumptions, and is subject to continuous review and revision by management.
Based on the cost estimate set forth above, which assumes a 4 percent average inflation over the 35 year period, the Company will spend approximately $4.2 million, $1.5 million, $2.1 million, $4.4 million and $4.2 million in 1994 through 1998, respectively. The cost estimate also contemplates that primarily groundwater pump and treatment activities will take place after 1998 through and including 2027. During this time, the Company estimates that it will incur average annual costs of $2.0 million to complete the planned groundwater remediation activities.
With respect to rate recovery of these costs, the PSCW has approved a five year amortization of the unamortized balance of incurred environmental costs deferred to date.
Based on the present regulatory record at the PSCW, management believes that future costs of remediating these manufactured gas plant sites will be recovered in rates.
d. FERC Order No. 636:
In 1992 the FERC issued Order No. 636 and 636-A which requires interstate pipelines to restructure their services. Under these orders, existing pipeline sales service would be "unbundled" such that gas supplies would be sold separately from interstate transportation services (pipelines serving the Company implemented new services November 1, 1993). Pipelines will, however, seek to recover from their customers certain transition costs associated with restructuring. Any such recovery would be subject to prudence hearings at the FERC and state regulatory commissions.
NOTE 11. SHORT-TERM DEBT AND LINES OF CREDIT:
The Company maintains bank lines of credit, most of which are at the bank prime rates, to obtain short-term borrowing flexibility, including pledging lines of credit as security for any commercial paper outstanding. The carrying amount approximates fair value because of the short maturity of these items. Amounts available under these lines of credit totaled $70 million at December 31, 1993 and 1992 and $52.5 million at December 31, 1991. Information regarding short-term debt and lines of credit is as follows (In Thousands of Dollars):
NOTE 12. SEGMENT INFORMATION:
The following table sets forth certain information relating to the Company's consolidated operations (In Thousands of Dollars).
NOTE 13. CONSOLIDATED QUARTERLY FINANCIAL DATA (Unaudited):
Seasonal factors significantly affect the Company and, therefore, the data presented below should not be expected to be comparable between quarters nor necessarily indicative of the results to be expected for an annual period.
The amounts below were not audited by independent public accountants, but reflect all adjustments necessary, in the opinion of the Company, for a fair presentation of the data (In Thousands of Dollars).
Operating Net Operating Quarter Ended Revenues Income Net Income ------------- --------- ------------- ----------
1993: March 31 $182,023 $26,405 $17,740 June 30 141,049 16,936 8,237 September 30 144,440 21,045 13,096 December 31 177,986 31,091 21,104
1992: March 31 $169,015 $26,415 $18,001 June 30 129,038 14,731 6,445 September 30 137,530 19,359 11,917 December 31 165,236 27,730 19,045
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by Item 10 relating to directors and nominees for election as directors at the Company's 1994 Annual Meeting of Shareowners is incorporated herein by reference to the information under the caption "Election of Directors" in the Company's Proxy Statement (the "1994 Proxy Statement") filed with the Securities and Exchange Commission. The information required by Item 10 relating to executive officers is set forth in Part I of this Annual Report on Form 10-K. The information required by Item 10 relating to delinquent filers is incorporated herein by reference to the information under the caption "Compliance with Section 16(a) of the Securities Exchange Act of 1934" in the 1994 Proxy Statement.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated herein by reference to the information under the caption "Compensation of Executive Officers" in the 1994 Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is incorporated herein by reference to the information under the caption "Ownership of Voting Securities" in the 1994 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 is incorporated herein by reference to the information under the caption "Election of Directors" in the 1994 Proxy Statement.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) Consolidated Financial Statements
Included in Part II of this report:
Report of Independent Public Accountants on Schedules
Consolidated Statements of Income for the Years Ended December 31, 1993, 1992 and 1991
Consolidated Balance Sheets, December 31, 1993 and 1992
Consolidated Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991
Consolidated Statements of Capitalization, December 31, 1993 and
Consolidated Statements of Common Shareowner's Investment
Notes to Consolidated Financial Statements
(a) (2) Financial Statement Schedules
For each of the years ended December 31, 1993, 1992 and 1991
Schedule V. Property Plant and Equipment Schedule VI. Accumulated Provision for Depreciation and Accumulated Amortization of Nuclear Fuel Schedule VIII. Valuation and Qualifying Accounts and Reserves Schedule X. Supplementary Income Statement Information
All other schedules are omitted because they are not applicable or not required, or because that required information is shown either in the consolidated financial statements or in the notes thereto.
(a)(3) Exhibits Required by Securities and Exchange Commission Regulation S-K
The following Exhibits are filed herewith or incorporated herein by reference. Documents indicated by an asterisk (*) are incorporated herein by reference.
3A* Restated Articles of Organization, as amended, of the Company (including the Articles of Amendment to the Company's Restated Articles of Organization creating the New Preferred Stock) (Exhibit 4.1 to the Company's Form 8-K/A, Amendment No.1 to Current Report, dated October 20, 1993)
3B* By-Laws of the Company as revised to January 1, 1993
4A* Indenture of Mortgage or Deed of Trust dated August 1, 1941, between the Company and First Wisconsin Trust Company and George B. Luhman, as Trustees, filed as Exhibit 7(a) in File No. 2-6409, and the indentures supplemental thereto dated, respectively, January 1, 1948, September 1, 1948, June 1, 1950, April 1, 1951, April 1, 1952, September 1, 1953, October 1, 1954, March 1, 1959, May 1, 1962, August 1, 1968, June 1, 1969, October 1, 1970, July 1, 1971, April 1, 1974, December 1, 1975, May 1, 1976, May 15, 1978, August 1, 1980, January 15, 1981, August 1, 1984, January 15, 1986, June 1, 1986, August 1, 1988, December 1, 1990, September 1, 1991, October 1, 1991, March 1, 1992, May 1, 1992, June 1, 1992 and July 1, 1992 (Second Amended Exhibit 7(b) in File No. 2-7361; Amended Exhibit 7(c) in File No. 2-7628; Amended Exhibit 7.02 in File No. 2-8462; Amended Exhibit 7.02 in File No. 2-8882; Second Amendment Exhibit 4.03 in File No. 2-9526; Amended Exhibit 4.03 in File No. 2-10406; Amended Exhibit 2.02 in File No. 2-11130; Amended Exhibit 2.02 in File No. 2-14816; Amended Exhibit 2.02 in File No. 2-20372; Amended Exhibit 2.02 in File No. 2-29738; Amended Exhibit 2.02 in File No. 2-32947; Amended Exhibit 2.02 in File No. 2-38304; Amended Exhibit 2.02 in File No. 2-40802; Amended Exhibit 2.02 in File No. 2-50308; Exhibit 2.01(a) in File No. 2-57775; Amended Exhibit 2.02 in File No. 2-56036; Amended Exhibit 2.02 in File No. 2-61439; Exhibit 4.02 in File No. 2-70534; Amended Exhibit 4.03 File No. 2-70534; Exhibit 4.02 in File No. 33-2579; Amended Exhibit 4.03 in File No. 33-2579; Amended Exhibit 4.02 in File No. 33-4961; Exhibit 4B to the Company's Form 10-K for the year ended December 31, 1988, Exhibit 4.1 to the Company's Form 8-K dated December 10, 1990, Amended Exhibit 4.26 in File No. 33-45726, Amended Exhibit 4.27 in File No.33-45726, Exhibit 4.1 to the Company's Form 8-K dated March 9, 1992, Exhibit 4.1 to the Company's Form 8-K dated May 12, 1992, Exhibit 4.1 to the Company's Form 8-K dated June 29, 1992 and Exhibit 4.1 to the Company's Form 8-K dated July 20, 1992)
10A*# Executive Tenure Compensation Plan as revised November 1992
10B*# Form of Supplemental Retirement Plan, as revised November 1992
10C*# Forms of Deferred Compensation Plans, as amended June, 1990 (Exhibit 10C to the Company's Form 10-K for the year ended December 31, 1990)
10C.1*# Officer's Deferred Compensation Plan II, as adopted September 1992
10C.2*# Officer's Deferred Compensation Plan III, as adopted January 1993
10F*# Pre-Retirement Survivor's Income Supplemental Plan, as revised November 1992
10H*# Management Incentive Plan
10I*# Deferred Compensation Plan for Directors, as adopted June 27,
12 Computation of ratio of earnings to fixed charges and preferred dividend requirements after taxes
21 Subsidiaries of the Company
99 1994 Proxy Statement for the Annual Meeting of Shareowners to be held May 18, 1994
Pursuant to Item 601(b)(4)(iii) of Regulation S-K, the Company hereby agrees to furnish to the Securities and Exchange Commission, upon request, any instrument defining the rights of holders of unregistered long-term debt not filed as an exhibit to this Form 10-K. No such instrument authorizes securities in excess of 10 percent of the total assets of the Company.
# - A management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K.
1. The Company filed a report on Form 8-K dated October 20, 1994, which reported, under "Item 5. Other Events", the agreement to sell: (i) 150,000 shares of its 6.2% Preferred Stock, with a stated value of $100, in a public offering through Goldman, Sachs & Co.; and (ii) 599,460 shares of its 6.5% Preferred Stock, with a stated value of $25 in a public offering through Robert W. Baird & Co. Incorporated.
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 on the 23rd day of February 1994.
WISCONSIN POWER AND LIGHT COMPANY
By: /s/ Erroll B. Davis, Jr. Erroll B. Davis, Jr. 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 indicated on the 23rd day of February 1994.
/s/ Erroll B. Davis, Jr. President, Chief Executive Officer Erroll B. Davis, Jr. and Director (principal executive officer)
/s/ Daniel A. Doyle Controller and Treasurer Daniel A. Doyle (principal financial and accounting officer)
/s/ L. David Carley Director /s/ Milton E. Neshek Director L. David Carley Milton E. Neshek
/s/ Rockne G. Flowers Director /s/ Henry C. Prange Director Rockne G. Flowers Henry C. Prange
/s/ Donald R. Haldeman Director /s/ Henry F. Scheig Director Donald R. Haldeman Henry F. Scheig
/s/ Katharine C. Lyall Director /s/ Carol T. Toussaint Director Katharine C. Lyall Carol T. Toussaint
/s/ Arnold M. Nemirow Director Arnold M. Nemirow
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
To Wisconsin Power and Light Company:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in Wisconsin Power and Light Company's annual report to shareowners incorporated by reference in this Form 10-K, and have issued our report thereon dated January 28, 1994. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. Supplemental Schedules V, VI, VIII and X are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
Milwaukee, Wisconsin, ARTHUR ANDERSEN & CO. January 28, 1994.
INDEX TO SCHEDULES
WISCONSIN POWER AND LIGHT COMPANY INDEX TO FINANCIAL STATEMENT SCHEDULES FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
FINANCIAL STATEMENT SCHEDULES:
V. Property Plant and Equipment VI. Accumulated Provision for Depreciation and Accumulated Amortization of Nuclear Fuel VIII. Valuation and Qualifying Accounts and Reserves X. Supplementary Income Statement Information
NOTE: All other schedules are omitted because they are not applicable or not required, or because that required information is shown either in the financial statements or in the notes thereto.
SCHEDULE X
WISCONSIN POWER AND LIGHT COMPANY AND SUBSIDIARIES SUPPLEMENTARY INCOME STATEMENT INFORMATION
Year Ended December 31, 1993 1992 1991
Real estate and personal property. $16,316 $16,685 $15,488 Payroll............. 8,680 8,440 7,733 Other............... 1,149 1,045 1,160 ------- ------ ------ $26,145 $26,170 $24,381 ======= ======= =======
The amounts of maintenance and repairs, depreciation and taxes charged to other expense accounts are not significant. The amounts charged to the respective accounts for advertising aggregated less than one percent of total consolidated revenues, and no royalty expenses were incurred.
WISCONSIN POWER AND LIGHT COMPANY Exhibit Index for the Year Ended
December 31, 1993
Item Description
12 Computation of ratio of earnings to fixed charges and preferred dividend requirements after taxes
21 Subsidiaries of the Company
99 1994 Proxy Statement for the Annual Meeting of Shareowners to be held May 18, 1994 (To be filed with the Securities and Exchange Commission under Regulation 14A within 120 days after the end of the Company's fiscal year)