Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
A. GENERAL
Wisconsin Public Service Corporation ("Company"), a Wisconsin corporation, which was incorporated July 17, 1883, is a regulated public utility engaged chiefly in the production, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. On September 1, 1994, the Company became a wholly-owned subsidiary of WPS Resources Corporation ("WPSR") as a result of a one-for-one exchange of common stock shares. Also on September 1, 1994, all of the capital stock of WPS Communications, Inc. and Packerland Energy Services, Inc. was transferred to WPSR as part of a corporate restructuring.
At year end 1994, the Company served at retail 353,893 electric customers and 196,666 gas customers in an 11,000 square mile service territory in Northeastern Wisconsin and an adjacent part of Upper Michigan. Additionally, the Company provides wholesale full or partial requirements electric service, either directly or indirectly, to eleven municipal utilities, and also two Rural Electrification Administration financed electric cooperatives and a privately held utility. About 98% of operating revenues in the year 1994 were derived from Wisconsin customers and 2% from Michigan customers. Of total revenues in 1994, 73% were from electric operations and 27% from gas operations. Of total electric revenues, 91% were from retail sales and 9% were from wholesale sales.
The Company's retail service areas are principally protected in Wisconsin by indeterminate permits secured by statute, and in the state of Michigan by franchises granted by municipalities.
B. ELECTRIC OPERATIONS
GENERAL MATTERS. The largest communities served at retail with electricity are the cities of Green Bay, Oshkosh, Wausau and Stevens Point.
The Company's maximum net demand in 1994 was 1,549,000 kw which occurred on June 16. At that time, system capability was 1,819,900 kw, and after adjustments for firm purchases and sales to other utilities, the Company's reserve capacity was 16.6%. This 1994 maximum net demand was slightly lower than the 1993 summer net peak demand. The Company's future reserves, also adjusted for firm purchases and sales and planned capacity additions, are estimated to be above the planning criteria of a 15% minimum reserve in 1995 and 1996. See Part I, Item 2, PROPERTIES, at page 23 for information concerning generating facilities.
Coordinated planning for generation and transmission is a function of the Wisconsin Upper Michigan Systems of which the Company is a member along with Wisconsin Power and Light Company ("WP&L"), Madison Gas & Electric Company ("MG&E"), Wisconsin Electric Power Company ("WEPCO"), Upper Peninsula Power Company and Wisconsin Public Power, Inc. ("WPPI"). Existing and planned interconnections with other neighboring utilities provide a further means of sharing reserve capacities and interchanging energy.
The Company owns 33.1% of the outstanding capital stock of Wisconsin River Power Company ("River Power"). The business of River Power consists of the ownership and operation of two dams and related hydroelectric plants on the Wisconsin River having an aggregate installed capacity of about 35,000 kw. The output of the hydroelectric plants is sold, at the sites of the plants, to the three companies which own the outstanding capital stock substantially in proportion to their stock ownership interests.
KEWAUNEE NUCLEAR POWER PLANT. The Company is the operator and 41.2% owner of Kewaunee which is owned jointly with WP&L and MG&E. This plant began commercial operation in 1974. The Kewaunee capability factor was 86.6% in 1994, compared to a projected industry average of 73.7%.
The Company is a member of the Institute of Nuclear Power Operations ("INPO"), an organization of nuclear utilities which promotes excellence in all aspects of nuclear plant operations. INPO manages the accreditation process for industry training programs, which includes periodic accreditation of those training programs by an independent organization, the National Nuclear Accrediting Board ("NNAB"). All ten accredited training programs at Kewaunee are currently in good standing with the NNAB.
The steam generator tubes at Kewaunee are susceptible to corrosion characteristics seen throughout the nuclear industry. Inspections are performed to identify degraded tubes. Degraded tubes are either repaired by sleeving or are removed from service by plugging. The steam generators were designed with approximately 15% heat transfer margin, meaning that full power should be sustainable with the equivalent of 15% of the steam generator tubes plugged. Tube plugging and the build-up of deposits on the tubes affect the heat- transfer capability of the steam generators to the point where eventually full power operation is affected. The result will be a gradual decrease in the capacity of the plant. The plant's capacity could be reduced by as much as 20% by the year 2013 when the current operating license expires. Currently, the equivalent of approximately 12% of the tubes in the steam generators are plugged with no loss of capacity. The Company recently completed studies evaluating the economics of replacing the two steam generators at Kewaunee. The studies resulted in the conclusion that the most prudent course of action is to continue operation of the existing steam generators. The Company continues to evaluate appropriate repair strategies, including replacement, as well as continued operation of the steam generators
without replacement. The Company also continues to fund the development of welded repair technology for steam generator tubes.
The Company continues to evaluate and implement initiatives to improve the performance of Kewaunee which already performs at above average levels for the industry. These initiatives include conversion from a twelve-month to an eighteen-month operating cycle beginning in the spring of 1995 and numerous other cost reduction measures. These initiatives have resulted in approximately a 25% reduction in Kewaunee operating and maintenance costs since 1991.
Physical decommissioning of Kewaunee 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. In July of 1994, the Public Service Commission of Wisconsin ("PSCW") issued an order covering all Wisconsin utilities that have nuclear generation. The order standardizes cost escalation assumptions used in determining decommissioning liabilities. Based upon this new methodology, and considering other assumption changes, Kewaunee decommissioning costs are estimated to be $357 million in current dollars and $785 million in year of expenditure dollars. The Company's share of Kewaunee decommissioning costs are estimated to be $147 million in current dollars. These costs are recovered currently in customer rates and deposited in external trusts. As a result of the new order, annual funding is expected to increase from approximately $4.0 million to approximately $8.7 million. On December 31, 1994, the market value of the investments in the trusts was $64.1 million.
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 evaluating options for the storage of additional quantities beyond 2001. Several technologies are available. An investment of approximately $2.5 million in the early 2000s could provide additional storage sufficient to meet spent fuel storage needs until the expiration of the current operating license in 2013.
The Low-Level Radioactive Waste Policy Act of 1980 specifies that states may enter into compacts to provide for regional low level waste disposal facilities. Wisconsin is a member of the Midwest Low Level Radioactive Waste Compact. 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 June of 1994, the Barnwell, South Carolina disposal facility, which had been accepting Kewaunee low level radioactive waste materials, discontinued taking waste materials from outside its region. The Company expects to have sufficient storage space of its own to satisfy low level radioactive waste disposal needs until the Ohio facility accepts low level radioactive waste materials.
FUEL SUPPLY. The Company's electric generation mix in 1994 compared to 1993 was: steam plants (coal), 62.6%, down from 64.7%; steam plant (nuclear), 14.5%, down from 14.6%; hydro, 2.6%, down from 3.2%; combined natural gas and fuel oil, .7%, up from .4%; and purchased power, 19.6%, up from 17.1%. Purchased power represents short-term energy purchases.
The Company has reduced over-all fuel costs for the fifth consecutive year. Fuel costs in 1994 compared with 1993, expressed in dollars per million BTU, were: nuclear, $.49, up from $.45; coal, $1.31, down from $1.38; natural gas, $2.77, down from $3.41; and No. 2 fuel oil, $4.15, up from $3.96.
In 1995, the Company will purchase almost all of the coal for its solely-owned plants from Western sources. Delivery of coal at the Pulliam plant is via railroad or lake vessel and at the Weston, Columbia and Edgewater plants via railroad.
Pulliam and Weston Units 1 and 2 burn Powder River Basin sub- bituminous coal. The Company has a long-term contract with one coal supplier that is expected to provide approximately two-thirds of the projected 1995 coal requirements for Unit 3 at Weston. The coal contract will provide low sulfur Powder River Basin coal for a term ending in 2016. The remainder of the coal for solely-owned generating facilities is purchased under short-term agreements of two years or less.
During 1991, the Company bought-out the coal supply agreement with NERCO Coal Company ("NERCO") and the corresponding rail transportation contracts with the Soo Line and the Wisconsin Central ("Railroads"). The Company paid approximately $34 million to NERCO and the Railroads as compensation for relief of all contractual obligations. The PSCW has ruled that the railroad and coal contract buyout costs may be recovered in customer rates subject to a benefits test. Management believes it will meet the benefits test and, therefore, recover in future rates all of the buyout costs because the cost of replacement coal plus the buyout costs as amortized and a return on the unamortized portion of the buyout costs are less than the costs under the original contracts. In the Wisconsin jurisdiction, the remaining unamortized buyout costs of $15.4 million will be recovered during 1995 and 1996. The Federal Energy Regulatory Commission ("FERC") issued an order on November 15, 1994 allowing recovery of all but approximately $3.6 million of NERCO buyout costs through a monthly surcharge rate over the period January 1993 through December 2005. The portion of the $3.6 million disallowance allocable to the FERC jurisdiction will not be determined until the end of 1995. Management believes that it is likely that the disallowance allocable to the FERC jurisdiction will not exceed the $625,000 write off taken in 1993 in anticipation of the disallowance. The Company will accrue and recover carrying charges on the unrecovered balance.
The Company also has a 31.8% ownership share in Columbia and a 31.8% ownership share in the Edgewater Unit 4, both of which are
operated by WP&L which has coal procurement responsibilities for these units. Columbia, with two 527 megawatt units, uses coal from the Wyoming-Montana coal fields. One hundred percent of the low sulfur coal for Unit 1 is supplied under terms of a contract which expires in 2004. The entire low sulfur coal supply for Unit 2 is supplied from the Southern Powder River Basin under short-term contracts. Edgewater uses a blend of bituminous and sub-bituminous Powder River Basin coal both of which are acquired under short-term contracts.
In 1989, the PSCW concluded that WP&L did not properly administer a coal contract for Columbia, which is owned 31.8% by the Company, 46.2% by WP&L and 22.0% by MG&E, and ordered WP&L to refund $9 million to the customers of the Company, WP&L and MG&E proportionately according to the ownership shares of each utility in Columbia. WP&L appealed the PSCW decision, and that PSCW action was found to represent unlawful retroactive ratemaking by both the Dane County Circuit Court and the Wisconsin Court of Appeals. On February 8, 1994, the Wisconsin Supreme Court upheld the decision of the Wisconsin Court of Appeals.
The supply of nuclear fuel for Kewaunee requires the purchase of 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. After a region (approximately one-third of the nuclear fuel assemblies in the reactor) of spent fuel is removed from the reactor, it is placed in temporary storage for cooling in a spent fuel pool at the plant site. Permanent storage is addressed below. There are presently no operating facilities in the United States reprocessing commercial nuclear fuel. A discussion of the nuclear fuel supply for Kewaunee follows:
(a) Requirements for uranium are met through spot or contract purchases. An inventory policy, which takes advantage of economical spot market purchases of uranium, results in the Company maintaining inventories sufficient for three reactor reloads of fuel.
(b) Uranium hexafluoride from inventory and from spot market purchases was used to satisfy converted material requirements in 1994. The Company intends to purchase future conversion services on the spot market.
(c) In 1994, enriched uranium was procured from COGEMA, Inc. pursuant to a contract executed in 1983 and last amended in 1993. Enrichment services were purchased from the United States Enrichment Corporation ("Enrichment Corporation") under the terms of the utility services contract which is in effect for the life of Kewaunee. The Company is committed to take 70% of its annual enrichment requirements in 1995, and in alternate years thereafter, from the Enrichment Corporation.
(d) Fuel fabrication requirements through June 15, 1995 are covered by contract. The Company is finalizing a contract for fuel fabrication extending through 2001.
(e) Beyond the stated periods set forth above, additional contracts for uranium concentrates, conversion to uranium hexafluoride, fabrication and spent fuel storage will have to be procured. The Company anticipates the prices for the foregoing will increase.
Pursuant to the Nuclear Waste Policy Act of 1982 ("Nuclear Policy Act"), the U. S. Department of Energy ("DOE") has entered into a contract with the Company to accept, transport and dispose of spent nuclear fuel beginning no 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 DOE at one mill per net kilowatt hour of electricity generated and sold by Kewaunee. An additional one-time fee was paid to the DOE for the disposal of spent nuclear fuel used to generate electricity prior to April 7, 1983.
The Nuclear Policy Act provides that both the federal government and the nuclear utilities fund the decontamination and decommissioning of the three gaseous diffusion plants in the United States. Utility contributions will be collected through a special assessment based on a utility's percentage of uranium enrichment services purchased through the date of enactment compared to total enrichment sales by the DOE. The owners of Kewaunee are required to pay approximately $19.2 million in current dollars over a period of fifteen years. At December 31, 1994, the remaining liability was $15.4 million of which the Company's share is $6.33 million. The payments are subject to adjustment for inflation.
RHINELANDER ENERGY CENTER. The Company has identified the need for additional power supply late in this decade. To satisfy this need, the Company has signed a thirty-five year steam and electrical sales agreement with Rhinelander Paper Company, Inc. ("Rhinelander Paper") which likely will be amended to reflect continuing negotiations between the parties. This agreement provides for the Company to construct, own and operate the Rhinelander Energy Center ("REC"), a 122 megawatt cogeneration facility, with an estimated cost of $169 million, adjacent to Rhinelander Paper's mill in Rhinelander, Wisconsin. Rhinelander Paper will purchase and use steam from the facility in its paper processes. On September 24, 1993, the Company initiated the filing process for a Certificate of Public Convenience and Necessity ("CPCN") which must be issued by the PSCW to permit construction of the REC. Action by the PSCW on the application is being carried out under a recently developed two-stage CPCN process regulated by the PSCW. In the first stage, the Company requested proposals from electric generating plant project developers and compared them to the proposed REC. On December 21, 1994, the PSCW issued its order approving the Company's REC project as the least cost solution to the Company's capacity needs. One unsuccessful bidder, Polsky Energy Corporation ("Polsky") petitioned for a rehearing of the PSCW's decision. The PSCW has agreed to consider Polsky's allegations
regarding the accuracy of certain computations related to the Company's successful bid. On March 9, 1995, in response to the Polsky petition, the PSCW affirmed their original decision in holding that the REC remains the least cost alternative which will satisfy the Company's additional capacity needs. The Company is proceeding with stage two of the CPCN process to obtain PSCW authorization to construct the REC, a process which is expected to result in a final decision on the CPCN in the second half of 1995 in order to have the facility in service in the summer of 1998.
OTHER MATTERS. On January 14, 1994, the Company submitted its Advance Plan 7 filing to the PSCW. It was updated on April 29, 1994. This plan identifies both the demand side and supply side needs of the Company through the year 2013. Preliminary plans indicate that demand side management programs will reduce the need for additional electric capacity by 269 megawatts. Supply side generation forecasts indicate the need for peaking generating units in 2001, 2002, 2004 and 2005 (combustion turbines of 75 megawatts each), an intermediate generating unit in 2009 (215 megawatt combined-cycle gas-fired unit), and a peaking generating unit in 2013 (75 megawatt combustion turbine). The plan also includes 122 megawatts of cogeneration from the REC as discussed above. Other smaller scale renewable projects are included in the plan. Pulliam Units 3 and 4 are included in the plan as being retired in 1998. They began operating in the 1940s. Advance Plan 7 must go through the regulatory review process. Hearings started in November of 1994 and are scheduled to conclude in May of 1995.
The Company is developing and implementing strategies to deal with issues raised by the National Energy Policy Act of 1992 ("Policy Act"). The Policy Act's provisions for transmission access should have minimal impact on the Company because the Company already has transportation tariffs on file at the FERC. The generation provisions of the Policy Act could create additional competition in that market; however, generation opportunities for the Company also could increase.
Regionally, the member companies of the Mid-America Interconnected Network, of which the Company is a member, are planning the formation of a regional transmission group ("RTG") that will open up the entire transmission grid within the network to member companies and others who choose to participate. It will then be easier than ever to transport electric power from one purchaser to another. FERC must approve the agreement for the formation of a RTG.
The Company faces increased competition in the wholesale power market. This may result in the loss of certain wholesale customers and reduced margins. The Company intends to compete aggressively to retain wholesale load.
In October of 1992, WPPI notified the Company that it was ending its agreement to purchase power effective in October of 1997. WPPI is a wholesale customer which buys 66 megawatts from the Company for resale to municipal utilities in Algoma, Eagle River, New Holstein, Sturgeon Bay and Two Rivers. WPPI has entered into an agreement to buy power from another Wisconsin utility during the period 1997 to
2009. Also, the Company has negotiated a new power supply agreement with the City of Wisconsin Rapids.
Although 12% of electric revenues come from sales to twenty paper mills, resulting in a relatively high and favorable load factor, there is no single customer or small group of customers, the loss of which would have a materially adverse effect on the electric business of the Company.
In August of 1994, the Company received approval from the PSCW to construct a portion of a jointly owned 138 Kv transmission line extending from New London to Stevens Point. The Company's share of the sixty mile transmission project will cost approximately $14.9 million; the remaining $9.6 million cost of the project is the responsibility of WEPCO and WP&L. Completion of the project is expected by early 1997. In the same order, the PSCW denied an application by WPPI to build and own the project facilities as a means to reduce its overall power supply costs. The Company, WEPCO and WP&L offered, and were ultimately ordered, to file Network Transmission Service ("NTS") tariffs with the FERC that would offer comparable use on their transmission systems. The Company tendered its NTS tariff for filing with the FERC in September of 1994. Currently, the NTS tariff is under review by the FERC and intervenors.
The Company also is waiting for a ruling from the PSCW regarding the Wausau to Abbotsford transmission project, which is part of a larger transmission interface project with Northern States Power Company, consisting of the rebuild of approximately twenty-three miles of 115 Kv transmission line. The cost of the project is estimated to be $4.2 million.
Applications for relicensing of the Company's Caldron Falls, High Falls, Johnson Falls, Sandstone Rapids, Potato Rapids, Peshtigo, Grand Rapids and Jersey projects were submitted to the FERC in December of 1991. These licenses, representing 30 megawatts of hydroelectric generating capacity, expired in December of 1993. Since the FERC had not considered the Company's applications at the license expiration dates, the licenses have been extended on an annual basis until FERC acts on the applications. Application to the FERC for relicensing of the Company's Wausau Project was submitted in June of 1993. The license for this project expires in June of 1995 and represents 5,400 kilowatts of capacity.
In the fall of 1994, the PSCW initiated a proceeding to assess the future of utility regulation in Wisconsin and to investigate the structure necessary for utilities to compete in the new electric marketplace. Public meetings have been held to identify the relevant issues. This matter is discussed in more detail in Part I, Item 1E, REGULATORY MATTERS, at page 20.
Electric research and development expenditures totaled $2.3 million for 1994, $2.1 million for 1993 and $2.0 million for 1992. These expenditures were made for Company sponsored projects and were primarily charged to electric operations.
FINANCIAL SUMMARY. The following table sets forth the revenues, operating income and identifiable assets attributable to electric utility operations:
YEAR ENDED DECEMBER 31
1994 1993 1992 (thousands)
Electric Operating Revenues $480,816 $493,256 $477,625
Operating Income, Including Allowance For Funds Used During Construction $ 68,260 $ 75,561 $ 73,026
Identifiable Assets $937,481 $938,951 $951,074
See Note 7 in Notes to Consolidated Financial Statements.
C. GAS OPERATIONS
GENERAL MATTERS. At December 31, 1994, the Company provided natural gas distribution service to 191,551 customers in 138 cities, villages and towns in Northeastern Wisconsin and 4,998 customers in and around Menominee, Michigan. The principal Wisconsin cities served include Green Bay, Oshkosh, Sheboygan, Marinette, Two Rivers, Stevens Point and Rhinelander.
The Company transported 58,508,511 dekatherms of gas of which 34,757,372 dekatherms were for resale during the year ended December 31, 1994. At the end of 1994, the Company had 117 end-user customers who purchased their gas directly from suppliers and contracted with transporters, including the Company, to transport the gas to their points of use. A total of 23,751,139 dekatherms was transported for these customers. During 1994, several transportation customers returned to purchasing their gas requirements from the Company. Load loss due to fuel switching has been minor because customers have been able to purchase transportation gas from suppliers at competitive prices.
Since the Company has a purchased gas adjustment provision as part of its customer rates, it recovers all of its purchased gas costs from customers. This allows the Company to receive the same margin (gas revenues less cost of gas) on therm sales to customers who purchase natural gas from the Company as it receives from transportation customers.
The Company retains a gas supply consultant who assists in creating a gas supply portfolio to match its gas load profile at the lowest reasonable cost. The portfolio is based on twenty-year gas peak day and annual sales forecasts and is structured to place the Company in an optimum gas purchasing position. The Company has entered into seventeen gas supply contracts with fourteen suppliers with terms from five months to six years with domestic suppliers and ten years with Canadian suppliers. There are nine years remaining on the contracts with Canadian suppliers. The large majority of gas is competitively priced based on a monthly spot price index. The gas supply contracts contain a gas inventory charge as well as corporate warranties to assure gas deliverability for the term of the contract.
Peak day design requirements of 340,777 dekatherms per day is based on a 1994-1995 peak day forecast at -20 degrees Fahrenheit. An additional 11,295 dekatherms per day, or 3.3%, of reserve capacity allows for growth and any unforeseen needs. Peak day requirements will be served by 117,657 dekatherms per day from transportation gas, and 223,120 dekatherms per day from storage gas. The Company has access to eleven BCF of storage capacity in Michigan. Storage gas is purchased and stored during the summer for redelivery during the heating season. The Company has purchased 0.1 BCF of underground salt dome storage in Louisiana to protect against a supply area gas shortage.
The Company transports gas from Louisiana, the Gulf of Mexico, the Texas-Oklahoma Panhandle area and Canada under contracts with ANR Pipeline Company ("ANR") for domestic gas and Viking Gas Transmission Company ("Viking") for Canadian supplies. On November 1, 1993, FERC Order 636 became effective for ANR. Order 636 prohibits pipeline companies, such as ANR, from bundling gas merchant services with transportation services. Thus, Order 636 shifts gas supply responsibilities to local distribution companies, such as the Company, while the pipeline companies continue to transport gas owned by others. Pipeline transportation rates are governed by tariffs which are subject to adjustment by the pipeline companies with the approval of the FERC. As a result of restructuring under Order 636, effective November 1, 1993, the Company contracted for its pro rata share of pipeline capacity from each of ANR's three supply areas: Southeast, Southwest, and Canada. The initial term of each contract was for ten years with the right to extend in five-year increments. In addition, the Company has preexisting capacity on Viking for delivery of Canadian gas with a term of four years with a right to extend.
Order 636 mandates a straight fixed variable rate design which loads all fixed costs into the reservation charge. Based on rates effective May 1, 1994, pipeline company reservation charges for 1995 will total approximately $41.3 million. The Company also has a no- notice service to accommodate load swings caused by unexpected system requirements.
On December 30, 1994, in FERC Docket No. TM 95-3-48-000, ANR filed its sixth annual reconciliation of the take-or-pay buyout/buydown costs recovered through monthly charges. These costs, which represent 75% of ANR's total take-or-pay buyout/buydown costs paid to their gas suppliers, are being passed on to ANR's customers, including the Company. The Company's remaining fixed charge obligation for the two take-or-pay dockets still outstanding is $41,930. Monthly fixed charge payments and volumetric payments are scheduled to be made through April 1998. All such costs are expected to be recovered from customers pursuant to established policies of the PSCW.
ANR, as a result of its FERC Order 636 compliance filing, will recover various transition costs from its customers, including the Company. The Company expects to recover ANR transition costs in future customer rates. These costs include purchased gas adjustment costs of which the Company's share is approximately $3.7 million. In addition, ANR has upstream pipeline capacity costs of between $85 million and $275 million of which the Company's share is approximately 10%. The exact amount cannot be determined at this time.
The Company is currently being billed for ANR's above-market costs of gas purchases from the Dakota Gasification Plant. The potential total amount of these billings is undetermined at this time. The 1994 allocation of these costs was $3.2 million, and the 1995 allocation is expected to be $3.3 million. The Company, as part of the Wisconsin Distributors Group ("WDG"), is contesting the legality
of the Dakota Gasification Plant costs provision and is paying these costs under protest subject to refund. A hearing before the District of Columbia Circuit Court could take place in 1995.
WPSR, the parent of the Company, has established a non-regulated subsidiary, WPS Energy Services, Inc., to market gas supply services to transportation customers.
The Company is a member of the WDG which utilizes a Washington, D.C. legal counsel to monitor FERC activities and advise the group. The group files testimony and interventions in cases that impact its members. The Company is also advised by the same Washington, D.C. legal counsel. The Company files interventions in cases to protect its interests as they may be different from the group.
All of the Company's Wisconsin retail natural gas rates contain a purchased gas adjustment clause which provides for tracking changes for wholesale costs and an annual true-up of such costs. The PSCW reaffirmed this purchased gas adjustment clause/true-up mechanism in the Company s 1994 rate order. The Company's Michigan retail rates include a gas cost recovery plan under procedures authorized by the Michigan Public Service Commission ("MPSC") in 1983. Both the PSCW and the MPSC have approved mechanisms to allow for full recovery of take-or-pay and transition related costs which the FERC has authorized ANR to pass on to its customers.
The Company is aggressively seeking new natural gas customers resulting in the addition of about 6,557 new customers in 1994. Growth in natural gas customers results from adding new customers in existing service areas and from the acquisition of new natural gas distribution franchises. At December 31, 1994, five applications for new gas distribution franchises were pending before the PSCW.
The Company uses gas for power generation in peaking turbines and for ignition and flame stabilization at its Weston Unit 3 and Pulliam generating plants.
One large industrial customer is in a geographical location which would allow for its direct connection to the ANR system. A special rate designed to keep this customer on the Company distribution system has been approved by the PSCW. The customer has requested a bypass to connect directly to the ANR system, but remains a Company transportation customer. There is no single customer or small group of customers, the loss of which would have a materially adverse effect on the natural gas business of the Company.
FINANCIAL SUMMARY. The following table sets forth the amounts of revenues, operating income and identifiable assets attributable to gas utility operations:
YEAR ENDED DECEMBER 31 1994 1993 1992 (thousands)
Gas Operating Revenues $182,058 $187,376 $157,177
Operating Income, Including Allowance For Funds Used During Construction $ 8,016 $ 8,183 $ 6,119
Identifiable Assets $188,554 $184,880 $158,314
See Note 7 in Notes to Consolidated Financial Statements.
D. ENVIRONMENTAL MATTERS
GENERAL MATTERS. The Company is subject to regulation with regard to the impact of its operations on air and water quality and solid waste disposal, and may be subject to regulation with regard to other environmental considerations by various federal, state and local authorities. The application of federal and state restrictions to protect the environment involves or may involve review, certification or issuance of permits by various federal and state authorities, including the U. S. Environmental Protection Agency ("EPA") and the Wisconsin Department of Natural Resources ("DNR"). Such restrictions, particularly in regard to emissions into the air and water and solid waste disposal, may limit, prevent or substantially increase the cost of the operation of the Company's generating facilities and may require substantial investments in new equipment at existing installations. They may also require substantial investments for proposed new projects and may delay or prevent authorization and completion of the projects. The Company cannot forecast other effects of all such regulation upon its generating, transmission and other facilities, or its operations, but believes that it is presently meeting existing requirements.
AIR QUALITY. The plants which the Company operates are in compliance with all current sulfur dioxide and nitrogen oxide emission standards.
The Federal Clean Air Act Amendments of 1990 ("Act") were enacted in 1990. The Act requires reductions in sulfur dioxide in 1995 (Phase I) to meet limitations based on an emission rate of 2.5 pounds per million BTUs multiplied by a historical generation baseline for Pulliam Unit 8 and Edgewater Unit 4 generating units. The Act requires further reductions beginning in the year 2000 (Phase II). These limits are set based on an emission rate of 1.2 pounds per million BTUs multiplied by a historical generation baseline for all generating units. The Company's generating facilities met the year 2000 standard in 1994. The Company has achieved compliance with Wisconsin and federal sulfur dioxide emission limitations by switching to low sulfur coal.
Because of the emission allowance system included in the Act, operations during Phase I are expected to produce surplus allowances which are expected to be available to aid in compliance with the requirements of Phase II. To the extent the Company determines that it will have allowances available beyond its own requirements in both Phase I and Phase II, it will consider the sale of these excess allowances. The PSCW has ordered that profits from the sale of allowances must be used to benefit utility customers.
The Act also requires the installation of low nitrogen oxide burners on several units. Low nitrogen oxide burners were installed at Pulliam Unit 8 early in 1994. Phase I of the Act allows units smaller than 100 megawatts, such as Pulliam Unit 7, to be designated Phase I units, thus building up sulfur dioxide credits. Having made this election, low nitrogen oxide burners were installed at Pulliam
Unit 7 in 1994. Expenditure of $15 million to $25 million are projected through 1999 to assure continued federal and Wisconsin emission compliance under all normal operating conditions at Pulliam and Weston. Based on past experience, it is anticipated that expenditures related to sulfur dioxide and nitrogen oxide emission compliance will be recoverable in customer rates.
Air toxic provisions in the Act will not be applied until the EPA conducts a three-year study to determine if those standards need to be applied to utilities.
WATER QUALITY. The Company is subject to regulation by the EPA and the DNR with respect to thermal and other discharges from the Company's power plants into Lake Michigan and other waters of Wisconsin. Permits were reissued to the Company for its Pulliam and Weston power plants. Various portions of those permits were challenged. These challenges have not been formally resolved, although many of the issues raised in the challenges have been resolved through informal discussions with the DNR, additional testing by the Company and regulatory changes. Under Wisconsin law, the challenged portions of the permits are stayed, and the administrative review process is completed. It is not anticipated that any of the outstanding issues will have a material cost associated with them.
GAS PLANT CLEANUP. The Company is currently investigating the need for environmental cleanup of eight manufactured gas plant sites which it previously operated. The Company engaged an environmental consultant to develop cleanup cost estimates for the two sites at which Phase II site investigations have been completed. The cleanup cost estimates for the Stevens Point and the Oshkosh sites are $1.7 million and $2.6 million, respectively. With respect to Stevens Point, the estimate assumes excavation of contaminated soils, thermal treatment of soils, disposal of treatment residuals, on-site groundwater extraction and treatment and post-cleanup monitoring for twenty-five years. The cost estimate for the Oshkosh site assumes, in addition to those items noted for Stevens Point, removal and disposal of contaminated river sediments. The consultant has yet to perform detailed investigations of the remaining six sites, and comparable information on these sites is not available.
The Company used the estimates for these two sites as a basis for making projections on cleanup costs at the other sites. Six of the eight sites are located adjacent to rivers. Using the Oshkosh cleanup estimate, which includes remediation of contaminated river sediments, and assuming all six sites have sediment contamination, and using the Stevens Point estimate for the two sites not adjacent to rivers, the range of future investigation and cleanup costs for all eight sites is estimated to be from $14.8 million to $29.3 million. Remediation expenditures would be made over the next thirty-four years. The Company has recorded as a liability with an offsetting deferred charge, i.e., a regulatory asset, of $26.9 million, which represents the Company's current estimate of cleanup costs for all eight sites. Based on discussions with regulators and a recent rate order in Wisconsin, management believes that these costs, but not the carrying
costs associated with the deferred charges, will be recoverable in future customer rates.
As additional detailed investigations are completed, three having been initiated in 1994, these estimates will be adjusted to reflect specific site data. These adjustments could be significant. Other factors that can affect these estimates are changes in remedial technology and regulatory requirements. The estimates presented above do not take into consideration any recovery from insurance carriers or other third parties which the Company is pursuing.
See also Part I, Item 3, LEGAL PROCEEDINGS, at page 24, for discussion of the Sheboygan Gas Plant and Oshkosh Gas Plant sites.
OTHER SOLID WASTE DISPOSAL. On December 1, 1986, the Company received notice from EPA-Region V that it was one of 832 potentially responsible parties ("PRP") for the cleanup of the Maxey Flats Waste Disposal Site. Documents obtained to date indicate that the Company contributed 0.0162% of the waste disposed of at the site. A remedial investigation and feasibility study has been completed. At this time, the cost of the remedial action and EPA oversight is estimated to be about $77.5 million. The EPA has offered a buyout agreement to de minimis PRPs. Although a final agreement has not been executed, the Company's buyout cost will be about $28,000. While liability for cleanup under the Comprehensive Environmental Response, Compensation and Liability Act ("Superfund") program is joint and several, the amounts paid by the PRPs are usually related to their volumetric contribution of waste to the site.
In November of 1986, the Company was notified by the DNR that it was one of the several PRPs involved in the Holtz & Krause Landfill located in Wausau, Wisconsin. The Company disposed of 12,516 cubic yards of non-hazardous office waste and construction debris at the site. This represents 1.02% of the total amount of waste at the site. The landfill is currently being addressed only by the DNR. The current work is not being conducted as part of the EPA's Superfund program. The DNR has selected a remedy which is estimated to cost a total of $11 million to $12 million. The DNR has agreed to contribute approximately $4.5 million toward the remedy. Also, the county in which the landfill is located has adopted a surcharge on the waste disposal fee charged at the county's landfill to raise funds to assist in the remediation. Clean Sites, Inc., a neutral cost allocation expert, was retained by the Holtz & Krause PRP Group to develop an allocation. The amount to be allocated to the Company, $37,163, was paid to the cleanup fund in October of 1993. The DNR has indicated that it will pursue a cost-recovery action against entities that do not settle with the Holtz & Krause PRP Group. In 1994, the Company entered into a Consent Decree that acknowledges the payment of the settlement amount, requires the settling parties to clean up the site and requires the state to pay its agreed upon contribution. In addition, the Company entered into a "buyout" agreement with the larger contributors of waste to the site in which the larger contributors agreed to indemnify the Company for any cost overruns up to a total site remedial cost of $20 million. If site remedial costs
exceed $20 million, the cost allocation may be reopened. Most of the site work was completed in 1994.
In March of 1987, the Company was notified by the EPA that it was a PRP for the cost of cleaning up the Rose Chemical site in Holden, Missouri. Based on records that are available, a small amount of polychlorinated biphenyl material, about 39,000 pounds, was sent to the site. At this time, the Company has signed a participation agreement for the cleanup and contributed $60,192 which is based on the volumetric contribution of waste and the expected total cleanup cost.
In November of 1988, the Company received notice from the DNR that the Sherman Street property located in Wausau, Wisconsin, had levels of lead contamination present. Based on an investigation conducted by a neighboring business, Wausau Steel, it appears that this contamination originates on an adjacent Wausau Steel property. The cleanup of the property by Wausau Steel has been completed, pending DNR approval.
In January 1995, the Company was notified that the EPA was seeking to recover $775,442 from several companies, not including the Company, that sent waste drums to the J. K. Drum site in New London, Wisconsin. One of the companies notified by EPA requested the Company to join a group to negotiate a settlement with the EPA. The Company's records indicate that it contributed drums to the site which it believes were empty. The Company is evaluating a response to the notice.
E. REGULATORY MATTERS
GENERAL MATTERS. Utility rates, service and securities issues of the Company are subject to regulation by the PSCW and the MPSC, and the Company is subject to regulation of its wholesale electric rates, hydroelectric projects and certain other matters by the FERC. It is also subject to limited regulation by local authorities. The Company follows Statement of Financial Accounting Standard No. 71, Accounting for the Effects of Certain Types of Regulation, and its financial statements reflect the effects of the different ratemaking principles of the various jurisdictions. These include the PSCW, 89% of revenues, the MPSC, 2% of revenues and FERC, 9% of revenues. The operation of Kewaunee is subject to the jurisdiction of the U. S. Nuclear Regulatory Commission.
In the Wisconsin jurisdiction, the rate process has been changed effective in 1995 such that retail electric and natural gas rates will be set every two years, rather than annually as has been the practice in the past. The earliest that the rates which took effect January 1, 1995 could change would be for the year 1997. Customer rates are set based on forecasted expenses and capital costs.
Wisconsin retail rates include an electric fuel-adjustment clause based on a "cost variance range approach." This range is based on a
specific estimated fuel cost for the next year. If actual fuel costs fall outside this range, a hearing may be held and an adjustment to future rates may result. Automatic fuel-adjustment clauses are used for FERC wholesale-electric and Michigan retail-electric portions of the Company's business. The Company has a purchased gas adjustment clause which allows it to pass on to all classes of gas customers changes in the cost of gas purchased from its suppliers, subject to PSCW and MPSC review.
CUSTOMER RATE MATTERS. In the Wisconsin jurisdiction, a $17.4 million, or 4% electric rate reduction, and a $1 million, or .6% natural gas rate increase, covering a one-year period, became effective on January 1, 1994. Electric revenues were also reduced $2 million, or .5% in May of 1994 as a result of reduced fuel costs. Customer rates for 1994 reflected an authorized rate of return of 11.3% on common equity, down from 12.3% in 1993. The return on common equity, when adjusted to reflect allowed earnings on deferred investment tax credits, amounted to 11.9% and 13.0%, respectively, for the years 1994 and 1993.
On December 19, 1994, the PSCW approved an electric rate reduction of $10.9 million, or 2.6% to be effective on January 1, 1995 for the years 1995 and 1996. Natural gas rates remained unchanged. The rates for 1995 and 1996 reflect an authorized rate of return on common equity of 11.5% which when adjusted to reflect allowed earnings on deferred investment tax credits is 12.18%. A capital structure including 54% common equity was also approved.
No changes were made to Michigan electric and gas rates during 1994 other than through the fuel adjustment clauses. Likewise, wholesale electric rates remained unchanged except for reductions related to fuel costs.
PSCW INDUSTRY RESTRUCTURING PROCEEDING. On September 8, 1994, the PSCW commenced a proceeding to consider the probable costs and benefits of changing the structure and regulation of the electric utility industry in Wisconsin. Changes in federal law, improvements in the electric transmission system and technological advances suggest that now is the time to prepare for, capture and maximize the benefits of a changing and more market-oriented industry.
At its January 24, 1995 meeting, the PSCW identified the primary objectives of the proceeding to be the creation of a system that sends accurate price signals to customers resulting in the most economically efficient use of resources; the creation of a system which maximizes, within the public interest, the number and diversity of service offerings to customers; and the creation of a system in which providers maximize economic efficiency and environmental stewardship.
The PSCW has created an Advisory Committee ("Committee"), consisting of twenty-two members, representing various constituencies, including a Company member, which will examine every aspect of electric service and determine which functions, if any, should be performed by a competitive market and identify specific transitional
mechanisms that may be needed to create a workable competitive market for these services. For services that have natural monopoly characteristics, the Committee will explore whether new institutional or regulatory policies could further benefit the public.
Following a period that includes public comment on the Committee's recommendations, the Committee will submit its recommended alternatives to the PSCW which will review the recommendations along with outside comments before deciding the appropriate public policy and commencing with implementation of its decision. The work of the Committee is intended to be finished in time to allow the PSCW to prepare a final report for the legislature on recommendations for legislative changes by December 1, 1995.
ACCOUNTING DEVELOPMENTS. See Part II, Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION, at page 29, for a discussion of accounting developments.
In addition, the staff of the U. S. Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including those of the Company, regarding the recognition, measurement and classification of nuclear decommissioning costs for nuclear generation facilities in the financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board has agreed to review the accounting for nuclear decommissioning costs. If current electric utility industry accounting practices for such decommissioning are changed: (1) the annual provisions for decommissioning could increase; and (2) the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation. The Company does not believe that such changes, if required, would have an adverse effect on results of operations due to its current and future ability to recover decommissioning costs through customer rates.
The PSCW certified new straight-line depreciation rates which became effective January 1, 1994 concurrent with the implementation of new customer rates. The result was a reduction in annual depreciation expense of approximately $5.8 million.
Regulatory assets represent probable future revenue associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent costs previously collected that are refundable in future rates. At December 31, 1994, regulatory assets and liabilities amounted to $109.1 million and $66.0 million, respectively. Based on prior and current rate treatment of such deferred charges, management believes it is probable that the Company will continue to recover these costs from ratepayers. Pursuant to a PSCW rate order, effective January 1, 1995, the Company is to recover approximately $23.6 million of deferred regulatory costs each year.
DIVIDEND RESTRICTIONS. The Company is restricted by a PSCW order to paying normal dividends of no more than 109% of the previous year's
common stock dividend without prior notice to the PSCW. Also, Wisconsin law prohibits the Company from making loans to WPSR and its non-regulated subsidiaries and from guaranteeing their obligations.
F. CAPITAL REQUIREMENTS
Anticipated construction expenditures for 1995 are $84.2 million, of which $53.1 million, $1.3 million, $24.4 million, and $5.4 million are for electric construction, nuclear fuel, gas construction, and other construction expenditures, respectively. Approximately 60% of the expenditures for 1995, and 97% of the anticipated total capital expenditures of $150.6 million during 1996 and 1997, are expected to be financed through internal sources. The Company does not expect to sell equity or long-term debt during this period. Expenditures related to the REC are not reflected in the above amounts because a subsidiary of the Company anticipates entering into a project financing arrangement with respect to the $169 million facility.
G. EMPLOYEES
At December 31, 1994, the Company employed 2,572 persons. Of this number, 2,093 and 479 were considered electric and gas utility employees, respectively.
Approximately 1,070 the Company employees are represented by Local 310 of the International Union of Operating Engineers ("Union"). During 1994, the Union ratified a new contract with the Company which provides for work force flexibility in that, for the duration of the contract, Union employees can perform traditional union work across craft lines, perform non-union work and perform work traditionally performed by contractors; and non-union employees can perform some union work. The current contract runs through October of 1997. There has never been a strike against the Company by its employees.
PAGE
ITEM 2.



ITEM 2. PROPERTIES
The following table includes information about electric generation facilities of the Company (including those jointly owned):
RATED CAPACITY(a) TYPE NAME LOCATION FUEL (KILOWATTS)
Steam Pulliam Green Bay, WI Coal 397,000 (b) Weston Wausau, WI Coal or Gas 493,800 (c) Kewaunee Kewaunee, WI Nuclear 216,300 (d) Columbia - Units 1 & 2 Portage, WI Coal 334,000 (d) Edgewater Unit 4 Sheboygan, WI Coal 104,600 (d) ---------- Total Steam 1,545,700
Hydro Various 68,900 (15 Plants)
Combustion Various Gas or Oil 264,400 (e) Turbine (6 Plants) & Diesel ---------- Total System 1,879,000 ==========
(a) Based on 1994 winter capacity.
(b) This plant contains six units.
(c) This plant contains three units. Two units burn only coal and the other can burn coal or natural gas.
(d) These facilities are jointly-owned. Kewaunee is operated by the Company; WP&L is operator of the Columbia and Edgewater units. The capacity indicated is the Company's portion of total plant capacity based on percent of ownership.
(e) The Company and the Marshfield Electric and Water Department jointly own 113,300 kilowatts of combustion turbine peaking capacity which the Company operates. The capacity included is the Company s portion of total plant capacity based on percent of ownership.
The Company owns 51 transmission substations with a transformer capacity of 5,253,000 kva; 107 distribution substations with a transformer capacity of 2,821,000 kva; and 20,316 route miles of electric transmission and distribution lines. Gas properties include
approximately 3,532 miles of main, 70 gate and city regulator stations and 181,078 services. All gas facilities are located in Wisconsin except for distribution facilities in and near the city of Menominee, Michigan.
Substantially all of the Company's utility plant is subject to a first mortgage lien.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
SHEBOYGAN GAS PLANT. In November of 1990, the Company was notified by the DNR that it may be a PRP for environmental contamination found on property next to the Sheboygan River previously used by the Company for the gasification of coal in the City of Sheboygan, Wisconsin (the "Sheboygan II Gas Plant"). The Company last used the property for this purpose in approximately 1930. In 1966, the property was sold and is now owned by the City of Sheboygan. The DNR has offered the Company the opportunity to investigate and remediate the property under an agreement with the State of Wisconsin as opposed to having the site handled by the EPA as part of the larger Sheboygan River and Harbor Superfund site. The Company, the City of Sheboygan and the State of Wisconsin have negotiated an agreement for performing the work, and therefore, Wisconsin, and not the EPA, will be handling this matter.
An initial study was completed on the site which confirmed the presence of contaminants that appear to be related to the Sheboygan II Gas Plant. A follow-up investigation was recommended by the environmental consultant to determine more precisely the scope of the contamination and to determine if any contamination is migrating from off-site. The Company is awaiting approval from the DNR for the additional work. After the follow-up investigation is completed, the City of Sheboygan and the Company will negotiate an allocation of the costs associated with cleanup of the site. Based on the initial study, and a more detailed investigation of the Company's former Oshkosh site, it is believed that the cost of cleanup for the Sheboygan II Gas Plant site could be as much as $2.6 million. The estimates presented above do not take into consideration any recovery from insurance carriers or other third parties which the Company is pursuing.
OSHKOSH GAS PLANT. In April of 1992, the Company received an order from the DNR directing it to complete an investigation and implement remedial activities on property owned by the Company in the City of Oshkosh, Wisconsin. Previously, the Company had operated a manufactured gas plant on the property from 1883 until 1946. A challenge to the order was filed on May 8, 1992, and the Company and the DNR have negotiated the terms of a consent order. An environmental consultant conducted an investigation in late 1993 and a more detailed investigation in 1994. Based on the more detailed investigation, the cost of remediation is estimated to be as much as $2.6 million. Additional studies are planned to define further the area of contamination (primary river sediments). The results of these
studies may affect the cost estimate for remediation based on the nature and extent of contamination. The City of Oshkosh has claimed that contaminated groundwater from the former gas plant property has migrated onto city-owned land. The Company has agreed to stay the statute of limitations that may be applicable to the City of Oshkosh's claim in order to avoid the filing of a lawsuit by the City of Oshkosh. The Company is continuing to evaluate the validity of the City of Oshkosh's claim as additional data is received. The estimates presented above do not take into consideration any recovery from insurance carriers or other third parties which the Company is pursuing.
Incorporated herein by reference are the descriptions of the various proceedings relating to environmental matters described under D. ENVIRONMENTAL MATTERS, at pages 16 through 19, Item 1.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year.
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information about outside directors is omitted for the reason that such information will be included in a proxy statement for the annual meeting of the shareholders of the parent company, WPSR, which is scheduled to be held on May 4, 1995.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of the Company has been wholly owned by WPSR since the reorganization which was effective September 1, 1994 as described in Part I, Item 1A, GENERAL, at page 1.
The Company is restricted by a PSCW order to paying normal dividends of no more than 109% of the previous year's common stock dividend without prior notice to the PSCW. Also, Wisconsin law prohibits the Company from making loans to WPSR and its non-regulated subsidiaries and from guaranteeing their obligations.
WPSR paid a normal dividend for the fourth quarter of 1994 in the amount of $.455 per share. In addition, WPSR paid special dividends in September and December of 1994 of $3.9 million and $13.0 million, respectively.
COMMON STOCK Two-Year Comparison (1)
Share Data Dividends Per Share Price Range High Low
1994 1st Quarter $ .445 33-5/8 28 2nd Quarter .445 30-3/4 27-3/8 3rd Quarter (2) .455 30-3/8 27 4th Quarter (2) .455 Not Publicly Traded Total $1.80
1993 1st Quarter $ .435 34-3/4 30-1/8 2nd Quarter .435 35-3/8 32-1/8 3rd Quarter .445 36-1/2 33-3/4 4th Quarter .445 36 31-3/4 Total $1.76
- ---- (1) The dividends for all of 1993 and the first three quarters of 1994 were paid by the Company to public shareholders. As a result of the reorganization, the fourth quarter dividend for 1994 was paid to public shareholders by WPSR.
(2) Special dividends are described in the third paragraph of this Item.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
A. SELECTED FINANCIAL DATA
B. FINANCIAL STATISTICS
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
RESULTS OF OPERATIONS
OVERVIEW OF 1994 COMPARED TO 1993
Earnings on common stock declined from $58.9 million in 1993 to $52.7 million in 1994, or 10.5%. The most significant reason for this decrease was a Public Service Commission of Wisconsin ("PSCW") order decreasing the authorized return on common equity for the Company from 12.3% to 11.3%, thereby reducing earnings approximately $3.8 million.
1994 COMPARED TO 1993
Electric margins (revenues less electric fuel expense and purchased power) declined by $17.3 million, or 5.0%, due primarily to reduced electric rates.
Electric operating revenues decreased $12.4 million, or 2.5%, primarily due to a 4.2% reduction in Wisconsin retail rates that took effect January 1, 1994. Electric rates also were reduced .5% in May 1994 as a result of reduced fuel costs. These decreases were partially offset by a 4.0% increase in kilowatt-hour ("kwh") sales. Residential, commercial and industrial kwh sales increased 2.4% and 4.9%, respectively, due to a warmer summer and customer growth. Wholesale kwh sales increased 3.0%.
Electric fuels and purchases increased $4.9 million, or 3.4%, reflecting increased sales, offset in part by reduced production costs. Electric production fuels decreased $3.0 million, or 2.7%, even though generation was up 1.3%. This decrease in fuel costs per kwh of 5.4% primarily was the result of purchasing less expensive coal on the spot market. Purchased power costs were higher by $7.9 million, or 25.8%. This was the result of a 19.9% increase in kwh purchases, due to the severe cold weather in the first quarter of the year, which forced WPSC to purchase expensive spot market electricity, and the Soo Line railroad strike during the second half of the year which impacted WPSC s ability to operate its coal-fired units.
Gas margins (revenues less the cost of gas) increased by $1.7 million, or 3.6%, due to customer growth. The PSCW allows WPSC to pass on to its customers, through a purchased gas adjustment clause, changes in the cost of gas.
Maintenance expense decreased $1.6 million, or 3.1%, due to lower maintenance activity at the Kewaunee Nuclear Power Plant ("Kewaunee") and to less electric transmission and distribution maintenance. Depreciation and decommissioning expense decreased $4.2 million, or 7.0%. The primary cause was a rate order from the PSCW which took effect January 1, 1994 reducing the annual depreciation provision by
an estimated $5.8 million. This was offset by higher decommissioning expense of approximately $1.1 million.
Federal and state income taxes decreased $3.0 million, or 9.1%, due to lower earnings.
1993 COMPARED TO 1992
Electric operating revenues increased $15.6 million, or 3.3%. This increase was the result of a 4.2% increase in kwh sales and a 2.1% rate increase for WPSC's Wisconsin retail customers that was effective January 1, 1993. This was partially offset by rate reductions totaling $1.1 million in September and November 1993 for Wisconsin retail customers due to reduced fuel costs. Residential sales increased $8.9 million, or 5.7%, due primarily to warmer summer weather. Commercial and industrial sales rose $13.3 million, or 5.3%, reflecting customer growth and the impact of the warmer weather. Wholesale sales decreased $4.5 million, or 7.4%, due to an average rate reduction for this customer class of 6.7%.
Electric production fuel costs decreased $9.8 million, or 7.9%, even though electric generation was up 2.1%. This decrease primarily was the result of less expensive coal which was purchased on the spot market. Such purchases decreased overall coal-related costs per kwh by 11.8% and reduced coal costs by approximately $14.2 million between years.
Gas operating revenues increased $30.2 million, or 19.2%. This increase primarily is due to a 10.1% increase in the cost of gas ($12.2 million), reflecting spot market volatility, a 3.2% increase in heating-degree days ($12.5 million) and a 2.3% Wisconsin retail rate increase ($5.5 million) effective January 1, 1993. Residential gas revenues increased $17.3 million, and commercial and industrial gas revenues increased $14.6 million.
Gas purchased for resale increased $23.5 million, or 21.3%, due to higher gas volumes of 10.4% and to a 10.1% higher average cost of gas per therm.
Other operating expenses increased $12.7 million, or 9.3%, primarily due to increased amortization of 1991 coal and associated rail contract buy-out costs of $2.9 million and increased electric and gas conservation expenses of $9.7 million.
Maintenance expense increased $5.1 million, or 11.1%, primarily due to additional maintenance activities at WPSC's coal-fired power plants.
Federal and state income taxes increased $5.9 million, or 21.7%, due to higher pre-tax income and the effect of an increase in the federal income tax rate from 34% to 35%, as provided in the Revenue Reconciliation Act of 1993.
BALANCE SHEET
1994 COMPARED TO 1993
Accrued utility revenues decreased $8.5 million as a result of unseasonably warm weather experienced in December 1994.
Long-term liabilities increased $20.6 million primarily due to higher estimates for environmental remediation of $10.4 million and post- retirement health care costs of $7.0 million.
FINANCIAL CONDITION
The Company requires large investments in capital assets used to deliver electric and gas services. The Company maintains good liquidity levels and a financial condition considered to be strong by analysts. Internally generated funds closely approximate the utility's cash requirements. No external funding difficulties are anticipated in the future. Pre-tax interest coverage was 4.2 times for the year ended December 31, 1994. WPSC's bond ratings are AA+ (Standard & Poor's), Aa2 (Moody's) and AA+ (Duff & Phelps).
The Company is restricted by a PSCW order to paying normal dividends of no more than 109% of the previous year's common stock dividend without prior notice to the PSCW. Also, Wisconsin law prohibits the Company from making loans to WPS Resources Corporation (WPSR), the Company's parent, and its subsidiaries and from guaranteeing their obligations.
For the three-year period 1995 to 1997, internally-generated funds at the Company are expected to lag behind construction expenditures, which total $235 million, by $38 million. The Company currently expects to finance this shortfall in internally generated funds with short-term debt. These expenditures are comprised of $148 million for electric construction, $20 million for nuclear fuel, $48 million for gas construction and $19 million for other construction expenditures. These construction costs exclude the Rhinelander Energy Center ("REC") which will be substantially funded with non-recourse project financing debt.
The PSCW has approved the REC as the preferred electric generating project to meet the Company's expanding capacity and energy needs. This approval followed a competitive bidding process. The REC will be built and operated by non-regulated subsidiaries of the Company. REC will be a coal-fired, 122-megawatt, $169 million cogeneration facility which will produce steam and electricity for sale to the Rhinelander Paper Company and electricity for sale to utility customers. Before construction commences, the PSCW must certify that the REC satisfies a public need. PSCW approval is expected in the second half of 1995. The plant is expected to be placed in service in 1998.
Kewaunee is currently licensed through the year 2013. Physical decommissioning is expected to occur during the period 2014 to 2021
with additional expenditures being incurred during the period 2022 to 2050. Decommissioning costs in current dollars are $147 million, and the undiscounted amount is $785 million. As of December 31, 1994, $64.1 million has been placed in external trusts to cover these future costs. Management does not anticipate decommissioning to have any negative impacts on the Company's liquidity or capital resources, since these costs are currently recovered from customers and funded through external decommissioning trusts.
The Company received a two-year rate order from the PSCW which became effective January 1, 1995. This rate order decreased electric retail rates by 2.6% and kept retail gas rates at current levels. This order also increased the authorized rate of return on common equity from 11.3% to 11.5%.
Statement of Financial Accounting Standards ("SFAS") No. 112, Employers Accounting for Post-Employment Benefits, became effective in 1994. This statement establishes the accounting and reporting standard for the estimated cost of benefits provided by an employer to former or inactive employees after employment but before retirement. The effect of this statement was not material.
SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, became effective in 1994. This statement establishes the accounting and reporting standard for investments in debt and marketable equity securities. This standard primarily impacts nuclear decommissioning investments. The effect of this statement was not material.
SFAS No. 119, Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments, also became effective in 1994. This statement establishes disclosure requirements for derivatives. As of December 31, 1994, the Company had no derivatives.
TRENDS
The Company follows SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating the utility. These include the PSCW, 89% of revenues, the Michigan Public Service Commission, 2% of revenues, and the Federal Energy Regulatory Commission ("FERC"), 9% of revenues. In addition, Kewaunee is regulated by the Nuclear Regulatory Commission. Environmental matters are primarily governed by the Environmental Protection Agency and the Wisconsin Department of Natural Resources.
The single most important development in the electric utility industry is the trend toward increased competition brought about by a combination of new legislation, changing regulation and market forces. Transmission access, mandated by the Energy Policy Act of 1992, increased competition in the wholesale power segment of the business and put pressure on profit margins. Certain segments of the industry
could become deregulated. Low-cost energy producers, such as the Company, are in a position to benefit from competitive markets.
The PSCW has initiated a proceeding to consider restructuring electric utility regulation in Wisconsin. Matters to be addressed include:
- Whether generation, transmission and distribution functions will be allowed to exist together in the same company.
- Whether retail wheeling should be allowed.
- Whether utilities should be obligated to serve those customers who have the ability to choose between alternate suppliers.
- Whether utilities will be given the ability to price services based on market factors rather than the traditional regulatory-pricing model.
- The treatment of stranded investment in utility plant and regulatory assets.
The Company has accrued $26.9 million for the future environmental remediation of eight manufactured gas plant sites which it operated previously. This accrual is based on studies at two sites and was used as the basis for projecting costs on the remaining six sites. The range of cleanup costs for all eight sites is estimated to be from $14.8 million to $29.3 million.
These estimates will be adjusted as additional site-specific studies are completed, three of which are anticipated in 1995. Factors that can impact future cost estimates include the volume of contaminated soil and changes in remedial technology and regulatory requirements. A recent Wisconsin rate order provides that these costs may be recovered from customers over a five-year period after expenditures are incurred, but that no return on unrecovered costs is permitted.
The estimated cleanup costs presented do not take into consideration recovery from insurance carriers or other third parties. In June 1994, the Wisconsin Supreme Court ("Court") held that insurance coverage was not available for environmental cleanup costs to the extent the clean up is done to prevent or mitigate future injury. The Court also held that a notification letter from a government agency about an environmental situation did not constitute a suit, triggering the insurers' duty to defend. The Company is exploring alternative approaches for pursuing claims against carriers in light of the decision.
In addition, the Company has been notified that it is a minor participant in a number of waste disposal site cleanup efforts. However, no significant costs are anticipated to clean up these sites.
Federal Clean Air Act Amendments ("Act") were enacted in 1990. The Act establishes stringent sulfur dioxide and nitrogen oxide emission
limitations. Wisconsin previously had enacted laws to limit sulfur emissions. The Company meets the sulfur dioxide emission standards scheduled to take effect in the year 2000 as a result of switching to lower-sulfur fuels. However, some additional capital expenditures will be required to upgrade existing equipment and to monitor emission levels. These expenditures are estimated to be in the range of $15 million to $25 million between 1995 and 1999.
The steam generator tubes at Kewaunee are susceptible to corrosion characteristics seen throughout the nuclear industry. Annual inspections are performed to identify degraded tubes which are either repaired by sleeving or are removed from service by plugging. The steam generators were designed with approximately a 15% heat-transfer margin, meaning that full power should be sustainable with the equivalent of 15% of the steam generator tubes plugged. Tube plugging and the build-up of deposits on the tubes affect the heat-transfer capability of the steam generators to the point where eventually full power operation is not possible, and there is a gradual decrease in the capacity of the plant. The plant s capacity could be reduced by as much as 20% by the year 2013. To date, approximately 12% of the tubes have been plugged, with no reduction in capacity. The Company continues to evaluate the operation of the steam generators without replacement and appropriate repair strategies, including replacement. The Company also continues to evaluate and implement initiatives to improve the performance of Kewaunee which already performs at above- average levels for the industry. These initiatives include conversion from a twelve-month to an eighteen-month refueling and major maintenance cycle, beginning in the spring of 1995, and numerous other cost-reduction measures. These initiatives have resulted in approximately a 25% reduction in Kewaunee operating and maintenance costs since 1991. The Company intends to operate Kewaunee until at least the expiration of the present operating license in 2013.
In 1995, the Company is initiating a new demand-side management ("DSM") program which involves loans and shared savings. Prior to 1995, DSM expenditures were recovered from all customers. The new program provides that those who benefit from energy-saving programs will finance them. As of December 31, 1994, the Company had $46.5 million of deferred DSM expenditures which will be recovered in future rates.
Local 310 of the International Union of Operating Engineers, representing 1,070 of the Company's employees, ratified a new three- year contract with the Company. The agreement provides for work force flexibility in that, for the duration of the contract, Union employees can perform traditional union work across craft lines, perform non- union work and perform work traditionally performed by contractors; and non-union employees can perform some union work. The flexibility that this contract provides will allow the Company to more easily adapt to the changing utility environment.
IMPACT OF INFLATION
Current financial statements are prepared in accordance with generally accepted accounting principles and report operating results in terms of historic cost. They provide a reasonable, objective and quantifiable statement of financial results, but they do not evaluate the impact of inflation. Under rate treatment prescribed by the utility s regulatory commissions, projected operating costs are recoverable in revenues. Because forecasts are prepared assuming inflation, the majority of inflationary effects on normal operating costs are recoverable in rates. However, in these forecasts, the Company is allowed to recover the historical cost of plant via depreciation.
Although new rates will not be implemented in 1996 due to the two-year rate order in the Wisconsin jurisdiction, management believes inflation will be offset by the impact of customer growth and increased productivity.
F. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) BUSINESS - Wisconsin Public Service Corporation ("Company") is a public utility operating company engaged in supplying electrical energy and natural gas to its customers who are located primarily in northeastern Wisconsin and Upper Michigan. The Company follows Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation, and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating the company. These include the Public Service Commission of Wisconsin ("PSCW"), 89% of revenues, the Michigan Public Service Commission ("MPSC"), 2% of revenues, and the Federal Energy Regulatory Commission ("FERC"), 9% of revenues.
(b) CORPORATE REORGANIZATION - On September 1, 1994, WPS Resources Corporation ("WPSR"), pursuant to a one-for- one share exchange, acquired all of the common stock of the Company. As a result, the Company became a wholly-owned subsidiary of the WPSR.
(c) CONSOLIDATION - The consolidated financial statements include the Company and its wholly-owned subsidiary, WPS Leasing, Inc. All significant intercompany transactions and accounts have been eliminated.
(d) UTILITY PLANT - Utility plant is stated at the original cost of construction which includes an allowance for funds used during construction ("AFUDC"). Approximately 50% of retail jurisdictional construction work in progress ("CWIP"), except for major new generating facilities which earn AFUDC on the full amount, is subject to AFUDC using a rate based on the Company's overall cost of capital. For 1994, the retail AFUDC rate was approximately 10.1%.
AFUDC is recorded on wholesale jurisdictional electric construction work in progress at debt and equity percentages specified in the FERC Uniform System of Accounts. For 1994, this rate was approximately 4.3%.
Substantially all of the Company's utility plant is subject to a first mortgage lien.
(e) PROPERTY ADDITIONS, MAINTENANCE AND RETIREMENTS - The cost of renewals and betterments of units of property (as distinguished from minor items of property) is charged to utility plant accounts. The cost of units of property retired, sold or otherwise disposed of, plus removal costs, less salvage, is charged to the accumulated provision for depreciation. No profit or loss is recognized in connection
with ordinary retirements of utility property units. Maintenance and repair costs and replacement and renewal of items less than units of property are generally charged to operating expense.
In October 1993, the Company sold, at cost, a 32% interest in a combustion turbine to a municipality for $7.8 million.
(f) DEPRECIATION - Straight-line composite depreciation expense is recorded over the estimated useful life of the property and includes estimated salvage and cost of removal. These rates have been approved by the PSCW. Effective January 1, 1994, depreciation rates were revised based on new estimates which decreased annual depreciation expense by approximately $5.8 million. This decrease was considered in setting customer rates.
============================================================= 1994 1993 1992 ------------------------------------------------------------- ANNUAL COMPOSITE DEPRECIATION RATES Electric 3.41% 3.89% 3.87% Gas 3.37% 3.81% 3.81% =============================================================
(g) NUCLEAR DECOMMISSIONING - Nuclear decommissioning costs are accrued over the estimated service life of the Kewaunee Nuclear Power Plant ("Kewaunee"), currently recovered from customers in rates and deposited in external trusts. Such costs totaled $4.0, $2.4 and $2.4 million for 1994, 1993 and 1992, respectively. In July 1994, the PSCW issued a generic order covering utilities with nuclear generation. This order standardizes the escalation assumptions used in determining nuclear decommissioning liabilities. The undiscounted amount of decommissioning costs estimated to be expended between the years 2014 to 2050 are $785 million. Long-term after-tax earnings of 5.5% are assumed. As a result of this change, annual decommissioning costs recovered in customer rates in 1995 will be approximately $8.7 million. As of December 31, 1994, the accumulated provision for depreciation and decommissioning included accumulated provisions for decommissioning totaling $64.1 million.
The Company's share of Kewaunee decommissioning costs are estimated to be $147 million in current dollars based on a site-specific study, performed in 1992, using immediate dismantlement as the method of decommissioning. As of December 31, 1994, the external trusts totaled $64.1 million and were valued at market.
Depreciation expense includes decommissioning costs recovered in customer rates and a charge to offset earnings from the external trusts. Trust earnings totaled $2.4, $3.5 and $3.3 million for the years ended December 31, 1994, 1993 and 1992, respectively.
(h) NUCLEAR FUEL - The cost of nuclear fuel is amortized to electric production fuel expense based on the quantity of heat produced for the generation of electric energy by Kewaunee. The costs amortized to electric fuel expense (which assume no salvage values for uranium or plutonium) include an amount for ultimate disposal and are recovered through current rates. As required by the Nuclear Waste Policy Act of 1982, a contract with the Department of Energy ("DOE") has been signed, and quarterly payments are being made to the DOE for the fuel storage based on generation. Interim storage space for spent nuclear fuel is provided at Kewaunee, and expenses associated with this storage are recognized as current operating costs. Currently, there is on-site storage capacity for spent fuel through the year 2013. As of December 31, 1994 and 1993, the accumulated provisions for nuclear fuel totaled $136.5 million and $130.0 million, respectively.
(I) CASH AND EQUIVALENTS - The Company considers short-term investments with an original maturity of three months or less to be cash equivalents.
(j) REVENUE AND CUSTOMER RECEIVABLES - The Company accrues revenues related to electric and gas service, including estimated amounts for service rendered but not billed.
As of December 31, 1994, energy conservation loans to customers amounting to $1.7 million are included in customer receivables and in investments and other assets. The carrying amount of the loans closely approximates their market value.
Automatic fuel-adjustment clauses are used for FERC wholesale-electric and MPSC retail-electric portions of the Company s business. The PSCW retail-electric portion of the business uses a cost variance range approach. This range is based on a specific estimated annual fuel cost. If the Company's actual fuel costs fall outside this range, a hearing may be held and an adjustment to future rates may result. The Company has a purchased gas adjustment clause which allows it to pass on to all classes of gas customers changes in the cost of gas purchased from its suppliers, subject to PSCW and MPSC review.
The Company is required to provide service and grant credit to customers within its defined service territory and is precluded from discontinuing service to residential customers during certain periods of the year. The Company continually reviews its customers' credit-worthiness and obtains deposits or refunds deposits accordingly. The Company is permitted to recover bad debts in utility rates.
Approximately 8% of the Company's total revenues are from companies in the paper products industry.
(k) REGULATORY ASSETS AND LIABILITIES - The Company is subject to the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets represent probable future revenue associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent costs previously collected that are refundable in future rates. The following regulatory assets and liabilities were reflected in the Consolidated Balance Sheets as of December 31:
============================================================ (Thousands) 1994 1993 ------------------------------------------------------------ REGULATORY ASSETS DSM expenditures $46,510 $ 46,219 Coal and rail contract buy-out costs 18,228 24,269 Environmental remediation costs 27,361 16,667 Debt refinancing costs 5,314 7,725 Enrichment facility fee 6,744 5,830 Natural gas obligations 1,856 3,713 Other 3,122 6,327 ------------------------------------------------------------ TOTAL $109,135 $110,750 ============================================================ REGULATORY LIABILITIES Income tax related $38,599 $33,030 Pensions 17,342 22,021 Conservation costs 7,221 3,494 Other 2,833 2,889 ------------------------------------------------------------ TOTAL $65,995 $61,434 ============================================================
As of December 31, 1994, most of the Company's regulatory assets are being recovered through rates charged to customers over periods ranging from two to ten years. Pursuant to a PSCW rate order, effective January 1, 1995, the Company is to recover approximately $23.6 million of regulatory costs in 1995 and 1996.
Based on prior and current rate treatment of such costs, management believes it is probable that the Company will continue to recover from ratepayers the deferred charges described above.
See notes (1)(m) and (1)(n) for specific discussion of pension and deferred tax regulatory liabilities, and note 6 for discussion of environmental-remediation deferred costs.
(l) INVESTMENTS AND OTHER ASSETS - Investments include various immaterial affiliates whose income is included in other income and deductions using the equity method of accounting.
Other assets include prepaid pension assets, operating deposits for jointly-owned plants, the cash surrender value of life insurance policies and the long-term portion of energy conservation loans to customers.
(m) EMPLOYEE BENEFIT PLANS - The Company has non-contributory retirement plans covering substantially all employees under which annual contributions are made to an irrevocable trust established to provide retired employees with a monthly payment if conditions relating to age and length of service have been met. The plans are fully funded, and no contributions were made in 1994, 1993 or 1992. Prior to January 1, 1993, the PSCW required the recognition of the funded amounts for ratemaking purposes. Concurrent with a rate order, effective January 1, 1993, the Company began recovering pension costs in customer rates under SFAS No. 87, Employers Accounting for Pensions, and began returning to ratepayers, over five years, the cumulative excess of amounts recovered from customers over SFAS No. 87 costs.
The tables below set forth the plans' funded status and expense (income).
The Company also offers medical, dental and life insurance benefits to employees, retirees and their dependents. The expenses for active employees are expensed as incurred.
Prior to 1993, the Company expensed amounts related to post- retirement health and welfare plans to the extent that such amounts were funded to external trusts.
Effective January 1, 1993, and concurrent with a rate order, the Company adopted SFAS No. 106, Employers' Accounting for Post-Retirement Benefits Other Than Pensions, which requires the cost of post-retirement benefits for employees to be accrued as expense over the period in which the employee renders service and becomes eligible to receive benefits. In adopting SFAS No. 106, the Company elected to recognize the transition obligation for current and future retirees over twenty years.
Since 1981, the Company has been funding amounts to irrevocable trusts as allowed for income tax purposes. These funded amounts have been expensed and recovered through customer rates. The investments in the trust covering administrative employees are subject to federal income taxes at a 39.6% tax rate, while the non- administrative trust is tax-exempt.
The tables below set forth the plans' accrued post- retirement benefit obligation ("APBO") as of December 31, 1994 and 1993 and the expense provision for the years then ended.
The assumed expected long-term return on investments and the discount rate used to measure the APBO under SFAS No. 106 are consistent with rates used to calculate the pension plans funded status and expense under SFAS No. 87. The assumed health care cost trend rates for 1995 are 11.5% for medical and 8.5% for dental, decreasing to 7.0% and 5.0%, respectively, by the year 2006. Increasing each of the medical and dental cost trend rates by 1% in each year would increase the total APBO as of December 31, 1994 by
$24.7 million and the total net periodic post-retirement benefit cost for the year then ended by $4.1 million.
During 1992, the cost of post-retirement health care benefits was $2.7 million. As of December 31, 1994, the Company had approximately 1,000 retirees eligible to receive health care benefits.
Concurrent with a rate order which was effective January 1, 1994, the Company adopted SFAS No. 112, Employers' Accounting for Post-Employment Benefits, which establishes accounting and reporting standards for post-employment benefits other than those covered by SFAS Nos. 87 and 106. In connection therewith, the Company expensed in 1994 the transition obligation of $1.8 million and recovered this cost through its customer rates.
The Company has a leveraged Employee Stock Ownership Plan and Trust ("ESOP") that held 2,240,500 shares of WPSR common stock (market value of approximately $59.9 million) at December 31, 1994. At that date, the ESOP also had loans guaranteed by the Company and secured by the common stock. At December 31, 1994, these loans had recorded values of $1.8 million (bearing an interest rate of 73.5% of prime rate) and $18.2 million (bearing an interest rate of 9.33%). The estimated market value of these loans at December 31, 1994 totaled $20.5 million.
Principal and interest on the loans are to be paid through the Company contributions and through dividends on WPSR common stock held by the ESOP. Shares in the ESOP are allocated to participants as the loans are repaid. Tax benefits from dividends paid to the ESOP are recognized as a reduction in the Company's cost of providing service to customers. The PSCW has allowed the Company to include in cost of service an additional employer contribution to the plan. The net effect of the tax benefits and of the employee contribution is an approximately equal sharing of benefits of the program between customers and employees.
(n) INCOME TAXES - Effective January 1, 1993, the Company adopted the liability method of accounting for income taxes as prescribed by SFAS No. 109, Accounting for Income Taxes. Under the liability method, deferred income tax liabilities are established based upon enacted tax laws and rates applicable to the periods in which the taxes become payable. The adoption of this accounting standard had an insignificant impact on the Company s net income. The excess deferred income taxes, resulting from taxes provided at rates greater than current rates, and the previously unrecorded deferred income taxes, have been recorded as a net regulatory liability to be refunded to customers in future years. Such net regulatory liability totaled $38.6 million as of December 31, 1994.
The effective income tax rates are computed by dividing total income tax expense, including investment credit restored, by the sum of such expense and net income. Previously deferred investment tax credits are being restored over the life of the related utility plant. The components of income tax expense are set forth in the tables below.
As of December 31, 1994 and 1993, the Company had the following significant temporary differences that created deferred tax assets and liabilities:
(2) COMMERCIAL PAPER AND LINES OF CREDIT
To support outstanding commercial paper, the Company maintains unused bank lines of credit. Some of these lines may be withdrawn at the discretion of the lenders. While some cash balances represent compensating balances for credit lines and bank services, there are no legal restrictions as to withdrawal of these funds. The majority of the lines of credit require a fee based on the unused balance.
The following information relates to short-term borrowings and lines of credit for the years indicated:
Included in the above lines of credit are agreements with commercial banks that permit the Company to borrow up to $16 million at any time provided there is compliance with certain financial covenants. These agreements extend for thirteen months or more. As of December 31, 1994, no borrowings were outstanding under these agreements.
(3) JOINTLY-OWNED FACILITIES
Information regarding the Company's share of major jointly-owned electric generating facilities in service at December 31, 1994 is as follows:
The Company's share of direct expenses for these plants is included in the corresponding operating expenses in the consolidated statements of income, and the Company has supplied its own financing for all jointly-owned projects.
(4) LONG-TERM DEBT
Sinking fund requirements on first mortgage bonds may be satisfied by the deposit of cash or reacquired bonds with the
trustee and, for certain series, by the application of net expenditures for bondable property in an amount equal to 166-2/3% of the annual requirements.
All series requiring the deposit of cash or reacquired bonds for sinking fund purposes have been satisfied to maturity. For those series requiring unpledged property to satisfy sinking fund requirements, the Company has adequate unpledged property to satisfy the requirement for at least ten years.
In 1998, $50 million of 5-1/4% bonds will mature.
As of December 31, 1994, the market value of the Company's first mortgage bonds was $273.0 million. These bonds have a recorded value of $291.1 million. Historically, gains or losses resulting from the settlement on long-term debt obligations have been deferred as required by regulators.
(5) COMMON EQUITY
At December 31, 1994, the Company had $279.8 million of retained earnings available for dividends; however, the Company is restricted by a PSCW order to paying normal dividends of no more than 109% of the previous year's common stock dividend without prior notice to the PSCW. Also, Wisconsin law prohibits the Company from making loans to WPSR and its subsidiaries and from guaranteeing their obligations. The Company's equity capitalization ratio at December 31, 1994 was 54% which is the same rate approved by the PSCW for ratemaking purposes.
(6) COMMITMENTS AND CONTINGENCIES
COAL CONTRACTS
To ensure a reliable, low-cost supply of coal, the Company entered into certain long-term contracts that have take-or-pay obligations totaling $323.7 million from 1995 through 2016. The obligations are subject to force majeure provisions which provide the Company other options if the specified coal does not meet emission limits which may be mandated in future legislation. In the opinion of management, any amounts paid under the take-or-pay obligations described above would be legitimate costs of service subject to recovery in customer rates.
GAS COSTS
The Company also has natural gas supply and transportation contracts that require total demand payments of $412.3 million through October 2003. Management believes that these costs will be recoverable in future customer rates.
ANR Pipeline Company ("ANR"), the Company's primary pipeline supplier, filed with the FERC for approval to recover a portion of certain take-or-pay costs it incurred from renegotiating its long-term gas contracts. As a result of the filing, ANR was allowed to recover a portion of these costs from its customers. The Company began paying its share of these take-or-pay costs to ANR in 1989 and recovering these costs directly from customers through its purchased-gas-adjustment clause. In March 1991, the FERC approved the settlement under which the Company will pay ANR monthly take-or-pay amounts. Additional take-or-pay claims by ANR may be filed with FERC. To date, the PSCW has granted the Company recovery of all take-or-pay costs.
In April 1992, the FERC issued Order No. 636 ("Order") which requires natural gas pipelines to restructure their sales and transportation services. As a result of this Order, the Company is obligated to pay for a portion of ANR's transition costs incurred to comply with the Order. At December 31, 1994, the Company has an accrued liability with an offsetting regulatory asset in the amount of $1.9 million for a portion of these transition costs. Though there may be additional costs, which could be significant, the amount and timing of these costs are unknown at this time. Management expects to recover these costs in future customer rates.
The Company will be billed $3.3 million in 1995 for their allocation of ANR's above-market costs of gas purchases from the Dakota Gasification Plant. The Company is protesting the legality of these costs which could total $49.0 million through 2009.
NUCLEAR LIABILITY
The Price-Anderson Act provides for the payment of funds for public liability claims arising out of a nuclear incident. In the event of a nuclear incident involving any of the nation's licensed reactors, the Company is subject to a proportional assessment which is approximately $32.7 million per incident, not to exceed $4.1 million per incident, per calendar year. These amounts represent the Company's 41.2% ownership share in Kewaunee.
CLEAN AIR REGULATIONS
In 1990, the Federal Clean Air Act Amendments ("Act") were signed into law. The Act requires the Company to meet new emission limits for sulfur dioxide and nitrogen oxide in 1995 (Phase I) and in the year 2000 (Phase II). Since Wisconsin had already mandated reduced sulfur dioxide emissions by 1993, which were lower than the Federal levels mandated for 1995, the Company was already working on lowering emissions. The Company has complied with both the Federal and Wisconsin sulfur dioxide laws primarily through fuel-switching. The Company was in compliance with the
Wisconsin sulfur dioxide limits and the Federal Phase II limits in 1994.
The final Federal regulations for nitrogen oxide are not known at this time; however, based on draft rules, the Company expects to make additional capital expenditures in the range of $15 million to $25 million between 1995 and 1999 for Wisconsin and Federal air quality compliance. Management believes that all costs incurred to comply with these laws will be recoverable in future customer rates.
MANUFACTURED GAS PLANT REMEDIATION
The Company currently is investigating the need for environmental clean up of eight manufactured gas plant sites which it previously operated. An environmental consultant has been engaged to develop cost estimates. These estimates are based upon an investigation of two of the sites and assumes excavation of impacted soils, thermal treatment of soils, on-site groundwater extraction and treatment and post-clean up and monitoring for twenty-five years. The consultant has not yet performed detailed investigations of the remaining six sites and, therefore, comparable information on these sites is not available.
The Company used the estimates for these two sites as a basis for making projections on cleanup costs at the other sites because of certain similar characteristics at the other sites. Thus, for all sites, cleanup costs reflecting anticipated inflation, current technology and no change in regulatory requirements are estimated to be in the range of $14.8 million to $29.3 million. Management has accrued $26.9 million for future cleanup costs for all eight sites which will be spent over the next thirty-four years. However, as further investigations are performed on all sites, this estimate may change significantly.
The $26.9 million estimate has been recorded as a liability with an offsetting deferred charge (regulatory asset). Based on a recent rate order, these costs (less any insurance recoveries) will be recoverable in future rates as expenditures are made. However, carrying costs are not recoverable.
As additional site-specific studies are completed (three are anticipated in 1995), these estimates will be adjusted to reflect site-specific data. Other factors that can impact these estimates are the volume of contaminated soil, changes in remediation technology and regulatory requirements.
In June, the Wisconsin Supreme Court ("Court") issued a decision regarding recoveries from insurance companies for environmental remediation costs. The Court held that insurance coverage was not available for environmental cleanup costs to the extent the clean up is done to prevent or mitigate future injury. In addition, the Court held that a notification letter from a
government agency about an environmental situation did not constitute a suit which triggers the insurers' duty to defend. The Company is exploring alternative approaches to pursuing claims against its carriers in light of the decision.
The Company has made minor payments for the investigation and potential clean up of certain other waste disposal sites. Management believes the Company has been a minor contributor to the total contamination at these sites and, accordingly, does not believe its share of cleanup costs to be material.
LONG-TERM POWER SUPPLY
The Company has signed a contract to build a 122-megawatt cogeneration facility with Rhinelander Paper Company and has filed an application for a Certificate of Public Convenience and Necessity with the PSCW requesting approval for the project. Estimated cost for the project is $169 million.
Management estimates 1995 utility plant construction expenditures to be approximately $84.2 million. DSM expenditures are estimated to be $25.8 million, of which approximately $15.0 million will be deferred and amortized over the next ten years consistent with rate recovery.
(7) SEGMENTS OF BUSINESS
The following table presents information for the respective years pertaining to the Company's operations segmented by lines of business.
(8) QUARTERLY FINANCIAL INFORMATION
G. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ----------------------------------------
To Wisconsin Public Service Corporation:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Wisconsin Public Service Corporation (a Wisconsin corporation) and subsidiary as of December 31, 1994 and 1993, and the related consolidated statements of income, retained earnings and 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Wisconsin Public Service Corporation and subsidiary as of December 31, 1994 and 1993, and the results of their operations and their 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 (1)(m) and (1)(n) to the financial statements, effective January 1, 1993, Wisconsin Public Service Corporation changed its method of accounting for post-retirement benefits other than pensions and income taxes.
Milwaukee, Wisconsin, January 26, 1995 ARTHUR ANDERSEN LLP
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
All information required by Part III, with the exception of information concerning executive officers which appears in Item 4A of Part I hereof, is incorporated by reference to WPSR's proxy statement for the annual meeting of the shareholders which is scheduled to be held on May 4, 1995 [File No. 1-11337].
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
(1) The following financial consolidated statements are included in Part II at Item 8