Annual Report (Form 10-K), fiscal year 1993

ITEM 1. BUSINESS
A. GENERAL
The Company, a Wisconsin corporation, which was incorporated July 17, 1883, is a public utility engaged chiefly in the production, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. At year end 1993, the Company served at retail approximately 347,000 electric customers and 190,000 gas customers in 10,000 square miles 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 REA financed electric cooperatives and a privately held utility. About 98% of operating revenues in the year 1993 were derived from Wisconsin customers and 2% from Michigan customers. Of total revenues in 1993, 72% were from electric operations and 28% from gas operations. Of total electric revenues, 92% were from retail sales and 8% were from wholesale sales.
The retail service areas of the Company 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. 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 1993 was 1,548,000 kw which occurred on August 25. At that time, system capability was 1,845,000 kw and after adjustments for firm purchases and sales to other utilities, the Company's reserve capacity was 18.8%. This 1993 maximum net demand was slightly higher than the 1992 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 15% in 1994 and 1995. See Part I, Item 2, PROPERTIES, for information concerning generating facilities.
Coordinated planning for future generating capacity is a function of the Wisconsin Upper Michigan Systems of which the Company is a member along with WP&L, MG&E, WEPCO, Upper Peninsula Power Company and WPPI. Existing and planned interconnections with other neighboring utilities provide further means of sharing reserve capacities and interchanging energy. The Company identified a requirement for additional peaking
capacity starting in the summer of 1993 and has completed construction of a combustion turbine peaking facility at Marinette, Wisconsin which added 75,000 kw of new generating capacity when it was placed in commercial operation in May of 1993. The facility is jointly owned with Marshfield.
The Company owns 33.1% of the outstanding capital stock of 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 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 availability factor since going commercial in 1974 is 84.7%.
The most recent NRC inspection of Kewaunee found plant operations and plant support to be "superior". Maintenance and engineering received "good" ratings. The inspection is part of the NRC's Systematic Assessment of Licensee Performance review.
The Company is a member of the INPO, an organization of nuclear utilities. INPO manages the accreditation process for industry training programs, which includes periodic accreditation of those training programs by an independent organization, the NNAB. All ten accredited training programs at the Kewaunee Nuclear Power Plant are currently in good standing with the NNAB.
The steam generator tubes at Kewaunee are susceptible to corrosion characteristics seen throughout the nuclear industry. Annual inspections are performed to identify degraded tubes. Degraded tubes are either repaired by sleeving or are 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 is a gradual decrease in the capacity of the plant. Currently, the equivalent of 10% of the tubes in the steam generators are plugged. The Company continues to evaluate appropriate repair strategies, including replacement, as well as continued operation of the steam generators without replacement.
The Company is engaged in ongoing discussions with its Kewaunee co-owners (WP&L and MG&E) respecting steam generator
replacement. A number of studies have been undertaken by the co- owners respecting steam generator replacement, but no final decision has been reached. Although the Company believes the continued operation of Kewaunee will be cost effective and intends to operate Kewaunee until at least 2013, the expiration of the operating license, the Company's Kewaunee co-owners (WP&L and MG&E) have indicated their unwillingness to proceed with an additional major investment in Kewaunee unless they are also satisfied that the continued operation of Kewaunee thereafter would be cost effective. If the Company is unable to reach an agreement with its Kewaunee co-owners on any such investment, it is likely that Kewaunee would continue to operate at reduced capacity until license expiration.
The Company is also evaluating initiatives to improve the performance of Kewaunee. These initiatives include funding of the development of welded repair technology for steam generator tubes and numerous cost reduction measures such as the conversion from a twelve-month to an eighteen-month fuel cycle. If the steam generators are not replaced, and excluding the possible affect of the aforementioned repair strategies, the Company projects a gradual power reduction of approximately 1% per year which may begin as soon as 1995.
Physical decommissioning is expected to occur during the period 2014-2021 with additional expenditures being incurred during the period 2022-2050 related to the storage of spent nuclear fuel at the site. The Company's current funding plan assumes that the current costs to decommission will escalate at a small premium to general inflation. The cost of decommissioning the Kewaunee plant is estimated to be $361 million, in current dollars, based on a 1992 site specific study using immediate dismantlement as the method of decommissioning. The Company's share of this total is estimated to be $149 million. These costs are recovered currently in customer rates. Annual contributions to external trusts established to accumulate funds to cover decommissioning costs were $2.4 million in 1993 and will increase to $4 million in 1994 and future years based on a revised funding plan recently approved by the PSCW. On December 31, 1993, the market value of the investments in the trusts was $60.6 million.
Spent fuel is currently stored at the Kewaunee plant. The existing capacity of the spent fuel storage facility will enable storage of the projected quantities of spent fuel through April 2001. The Company is currently evaluating options for the storage of additional quantities beyond 2001. Several technologies are available. An investment of $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.
The Waste Policy Act specifies that states may enter into compacts to provide for regional low level waste disposal facilities. The Act set January 1, 1986 as a deadline when compact members may restrict the use of regional disposal facilities to waste generated within the region. Additional legislation enacted by Congress since the Waste Policy Act has allowed generators of low level waste continued access to disposal facilities provided certain milestones are met by states participating in regional compacts. Presently, the state of Ohio has been selected as the host state for the Midwest Compact and is proceeding with the preliminary phases of site selection. In the meantime, the Company has access to an existing low level waste storage site through June of 1994. The Company expects to have sufficient storage space to store temporarily store low level waste generated between 1994 and the time that the Ohio facility is opened.
FUEL SUPPLY. The Company's electric generation mix in 1993 compared to 1992 was: steam plants (coal), 64.7%, down from 65.3%; steam plant (nuclear), 14.6%, down from 15.6%; hydro 3.2%, up from 3.1%; combined natural gas and fuel oil, .4%, up from .3%; and purchased power, 17.1%, up from 15.7%. Purchased power represents short-term energy purchases.
The Company has reduced fuel costs for the fourth consecutive year. Fuel costs in 1993 compared with 1992, expressed in dollars per million BTU, were: nuclear, $.45 up from $.40; coal, $1.38, down from $1.59; natural gas, $3.41, up from $3.37; and No. 2 fuel oil, $3.96, down from $5.66. The over-all downward trend in fuel costs is expected to continue.
The Company diversifies its coal sources by purchasing from eastern, midwestern and 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.
During 1993, the fuel supply for the Pulliam plant and Weston Units 1 and 2 facilities was predominantly lower sulfur coal as required by Wisconsin law which became effective January 1, 1993. During 1992, the Company negotiated a coal supply agreement for low sulfur, bituminous coal that is being used at the Pulliam plant and Weston Units 1 and 2 in a blend with low sulfur Powder River Basin sub-bituminous coal. During 1993, the Company negotiated a coal supply agreement and a rail transportation contract from mine origins to interchanges for Powder River Basin coal for the Pulliam plant and Weston Units 1 and 2 for a term ending in 1994. Deliveries of these low sulfur coals commenced in July of 1992.
The Company presently has a long-term contract with one coal supplier that is expected to provide approximately two-thirds of the projected 1994 coal requirements for Unit 3 at the Weston
plant. This 321 megawatt unit began operation in December of 1981. The coal contract will provide low sulfur Powder River Basin coal for a term ending in 2016.
During 1991, the Company bought-out the coal supply agreement with NERCO and the corresponding rail transportation contracts with the 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 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. See Part I, Item 1E, REGULATORY MATTERS, below for a discussion of the FERC consideration of this matter.
On August 28, 1993, the FVW acquired the assets of the GBW and the FRV. Prior to this date, the GBW/FRV provided alternative rail delivery options for the Pulliam plant in competition with the WC. The FVW and the WC are now under common control and ownership. To compensate for this diminished competition, the Company negotiated certain long-term rate protection provisions into existing contracts with the GBW/FRV and the WC, and also in a new contract with the FVW which took effect on August 28,1993.
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. 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.
WP&L has the responsibility to procure the fuel supply for the above-referenced jointly-owned facilities. The PSCW concluded in 1990 that WP&L improperly administered its coal supply agreement supplying the Columbia Unit 1 facility. The PSCW then issued an order which required WP&L to credit WP&L ratepayers for 46.2% of the $9 million of costs the PSCW concluded the utility incurred under the coal contract due to improper contract administration. The PSCW also required WP&L to reimburse the Company's Wisconsin retail ratepayers for 31.8% of the $9 million of costs to reflect the amount of such costs borne by the Company's ratepayers. WP&L petitioned the Dane County Circuit Court for review of the PSCW's refund order. The Dane County Circuit Court stayed and then overturned the PSCW's order. The Wisconsin Court of Appeals affirmed the Dane County Circuit Court decision. At the insistence of the PSCW, the decision will
be reviewed by the Wisconsin Supreme Court. The Company intervened in proceedings before the PSCW and remains a party in the appeal. The Company's position is that the PSCW's order requiring refund of past coal costs constitutes illegal retroactive ratemaking. If the PSCW prevails as the result of the appeal, and if WP&L is not required to reimburse Company ratepayers, the PSCW could require the Company to reimburse its retail ratepayers for the Company's share of such costs allocable to such ratepayers. A decision is expected in early 1994. This matter has not yet been reviewed by the FERC with respect to the Company's wholesale customers. Although the ultimate outcome of this matter is uncertain, in the opinion of Company management, there will be no material effect on the Company's results of operations or financial position.
A portion of the coal requirements for the 330 megawatt Edgewater Unit 4 will be supplied through 1994 by a Midwest coal supplier. Because this contract coal contains higher sulfur, the Company will use offsetting sulfur dioxide allowances from other units in its system to meet the Wisconsin sulfur dioxide emissions limitations which became effective January 1, 1993. The owners of Edgewater Unit 4 are conducting test burns of substitute coals and installing the equipment necessary to enable the joint owners to meet the Wisconsin sulfur dioxide emissions standards.
The supply of nuclear fuel for the Kewaunee plant involves the mining and milling of uranium ore to uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, enrichment of the uranium hexafluoride and fabrication of the enriched uranium into usable fuel assemblies. 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 nuclear 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, which requires approximately 250,000 pounds of uranium concentrates per year, follows:
(a) The Company and the other Kewaunee plant co-owners formed a limited partnership of subsidiaries in the mid-1970s to secure uranium reserves and maintain a long-term uranium concentrates supply capability. In 1993, the Company completed divestiture of uranium reserves in Colorado and Utah and returned properties potentially containing uranium concentrates to the previous leaseholders. Requirements for uranium are now met through spot or contract purchases. The Company maintains an inventory policy to take advantage of economical spot market purchases of uranium. In general, the Company maintains a four-year supply of uranium.
(b) Uranium hexafluoride, from inventory and from spot market purchases, was used to satisfy converted material requirements in 1993. The Company intends to purchase future conversion services on the spot market.
(c) In 1993, enriched uranium was procured from COGEMA, Inc. pursuant to a contract executed in 1983 and last amended in 1991. The Company is obligated to take delivery of additional enriched uranium contracted from COGEMA in 1994. The Company also purchased the equivalent of 52,000 pounds of uranium concentrates as enriched uranium on the spot market in 1993. Enrichment services were purchased from the DOE under the terms of the utility services contract which is in effect for the life of the Kewaunee plant. The Company is committed to take 70% of its annual enrichment requirements in 1994 and 1995, and in alternate years thereafter from the DOE.
(d) Fuel fabrication requirements through February 15, 1995 are covered by contract. The contract contains an option to allow the Company to extend the contract through 1998.
(e) Beyond the stated periods set forth above, additional contracts for uranium concentrates, conversion to uranium hexafluoride, fabrication and reprocessing or spent fuel storage will have to be procured. The Company anticipates the prices for the foregoing will increase.
Pursuant to the Nuclear Policy Act, the 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 the Kewaunee plant. An additional one-time fee was paid to DOE for the disposal of spent nuclear fuel used to generate electricity prior to April 7, 1983.
In response to a U. S. Court of Appeals ruling, the DOE published a final rule in the December 31, 1991 Federal Register changing the quantity of nuclear generated electricity subject to the millage fee by incorporating line losses into the calculation. This resulted in approximately a 6% reduction in the quarterly payments for storage of spent nuclear fuel. The Company is entitled to a refund for the amount overpaid since 1983. The refund is being applied to the quarterly payments made to the DOE during the period 1992 through 1995. The total amount of the refund will be approximately $1.5 million of which $1.1 million has been applied to DOE payments at December 31, 1993. These amounts will be refunded to retail customers over a three-
year period which began in 1993 and will be refunded to wholesale customers in 1994 and 1995.
The 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. This will require the owners of Kewaunee to pay approximately $15 million in current dollars over a period of fifteen years. The Company's share, which is $6.2 million, amounts to an annual payment of approximately $412,000 which will increase fuel costs. The Company made its first payment of $394,900 in September of 1993. The payments are subject to adjustment for inflation.
WHOLESALE CUSTOMERS. 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 1997-2009. This contract cancellation is indicative of the increased competition the Company faces in the wholesale power market. The Company intends to compete aggressively to retain wholesale load.
In 1993, the Company entered into a new twenty-year power supply agreement with Marshfield whereby the Company will provide for Marshfield's needs, presently 58 megawatts at the Company's summer peak. The agreement provides Marshfield with a 32% ownership share in the recently completed combustion turbine peaking facility at Marinette. This will satisfy 24 megawatts of Marshfield's capacity needs. The agreement has received PSCW and FERC approvals.
The Company is currently negotiating a new power supply agreement with Rapids for service to the east side of that city. Rapids continues to take full requirement service from the Company until a new agreement is signed.
OTHER. Wisconsin legislation, passed in 1975 to control the siting of large power plants and high voltage transmission lines, requires all Wisconsin utilities to file twenty-year Advance Plans with the PSCW. The PSCW issued an order relative to Advance Plan 6 in September 1992 covering the planning horizon to 2011. The Company has petitioned for review to the Brown County Circuit Court regarding limited portions of the order associated with the method to be used to incorporate environmental externalities in system planning. Externalities are external costs of certain environmental effects used in comparing electric
production alternatives. An intervenor, Wisconsin's Environmental Decade, Inc., has petitioned for review on a related issue to the Circuit Court in Dane County. The Company's and intervenor's petitions have been combined and will be heard by the Dane County Circuit Court. A schedule for issuing a decision has not been established.
On January 14, 1994, the Company submitted its Advance Plan 7 filing to the PSCW. 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 capacity by 340 megawatts. Supply side generation forecasts indicate the need for generating units in 2001 (141 megawatt combustion turbine), 2007 (150 megawatt share of a 215 megawatt combined-cycle gas-fired unit), and in 2011 (141 megawatt combustion turbine). The plan also includes 116 megawatts of cogeneration from Rhinelander as discussed below. Other smaller scale renewable projects are included in the plan. Pulliam Units 3 and 4 are expected to be retired in 2013. They began operating in the 1940's. Advance Plan 7 must go through the regulatory review process with a decision by the PSCW expected in early 1995.
The Company has received proposals for capacity and energy from several independent power producers. Destec Energy, Inc., an independent power producer seeking to develop a 260 megawatt electric and steam cogeneration facility in the Company's service territory, has petitioned the PSCW, pursuant to the federal PURPA, seeking to require the Company to enter into an agreement to purchase all of the electric power produced by that facility. The petition seeks a ruling by the PSCW regarding the obligation of the Company to enter into a power purchase agreement and the price at which such power would have to be purchased under PURPA after a time frame commencing in approximately 1995. The Company filed a response to the petition stating that the Company should not be required under federal or Wisconsin law to purchase power from Destec on the terms and conditions proposed by Destec. On December 21, 1993, the PSCW issued its decision in a docket which considered establishing procedures to be used by Wisconsin utilities to compare various power purchase alternatives to the utility's construction of its own power generating facilities. That decision dismissed the Destec petition. Destec is participating in the PSCW mandated bidding process described in the following paragraph.
As noted above, the Company has identified the need for additional electric generating capacity or purchased power late in this decade. To satisfy this need, the Company has signed a thirty-five year steam and electrical sales agreement with Rhinelander Paper. This agreement provides, subject to PSCW approval, for the Company to construct, own and operate a 116 megawatt cogeneration facility, with an estimated cost of $191
million, adjacent to Rhinelander Paper's mill in Rhinelander, Wisconsin. Rhinelander Paper will purchase and use steam from the facility in it paper processes. In addition, the Company has requested proposals for the same capacity from electric generating plant project developers or for power purchases from other utilities, as required by the PSCW's newly developed bidding process. The Company will compare the bids to the proposed Rhinelander facility before proposing a solution to its capacity and energy needs to the PSCW which must approve generating plant additions. A final decision is expected by late 1994.
Although 12% of electric revenues come from sales to eighteen 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.
The Company is developing and implementing strategies to deal with issues raised by the Policy Act. The Policy Act 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.
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.
The Company has applied to the PSCW for approval to construct a portion of a joint 138 kv transmission line extending from New London to Stevens Point. It is anticipated that the Company's share of project costs will be approximately $13 million. Other parties to the project are WEPCO and WP&L. The Company also has applied to the PSCW for approval to rebuild a transmission line from Wausau to Abbotsford costing approximately $4.2 million. The line was originally constructed in 1930. The new line would be built at 161 kv and would initially operate at 115 kv. This line would interconnect with NSP which also has applied to the PSCW to rebuild their line from western Wisconsin to Abbotsford. WPPI has filed competing applications for each of
the above projects. If the PSCW approves the Company's applications, the construction will be completed in 1996 and 1997, respectively.
Electric research and development expenditures totalled $2.1 million for 1993, $2 million for 1992 and $1.8 million for 1991. These expenditures were made for Company sponsored projects and were primarily charged to electric operations.
The following table sets forth the amounts of revenues, operating income and identifiable assets attributable to electric utility operations:
YEAR ENDED DECEMBER 31 1993 1992 1991 (thousands)
Electric Operating Revenues $493,256 $477,625 $471,277
Operating Income, Including Allowance For Funds Used $ 76,005 $ 74,040 $ 67,193 During Construction
Identifiable Assets $938,951 $951,074 $904,908
See Note 7 in Notes to Financial Statements.
C. GAS OPERATIONS
At December 31, 1993, the Company provided natural gas distribution service to 185,002 customers in 123 cities, villages and towns in northeastern Wisconsin and 4,980 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 purchased and/or transported 57,106,632 dekatherms of gas (of which 34,875,585 dekatherms were for resale) during the year ended December 31, 1993. In 1993, on average, the Company had 105 end-user customers who purchased gas in the field and contracted with ANR and the Company to transport the gas to their points of use. A total of 22,231,047 dekatherms was transported for these customers. Transportation of gas occurs when a utility or end-user purchases gas from a producer or marketer rather than from the pipeline company and contracts with the pipeline company to transport that gas to the market area. The end-user contracts with the utility to transport the gas to its point of use. During 1993, several transportation customers returned to purchasing their gas requirements from the Company.
Load loss due to conservation has been minor. Load loss due to fuel switching also has been minor because customers have been able to purchase transportation gas from suppliers at competitive prices.
The Company retains a gas supply consultant to assist in creating a gas supply portfolio to match its gas load profile at the lowest reasonable cost. The portfolio is based on a twenty- year gas peak day forecast and is structured to place the Company in an optimum gas purchasing position. The Company has entered into fifteen gas supply contracts with twelve suppliers with terms from one to six years with domestic suppliers and ten years with Canadian suppliers. All gas pricing is 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 337,252 dekatherms per day is based on a 1994-1995 peak day forecast at -20 degrees Fahrenheit. An additional 11,862 dekatherms per day of reserve capacity allows for growth and any unforeseen need. Peak day requirements will be served by 115,780 dekatherms per day from transportation gas, and 221,472 dekatherms per day from storage gas. The Company has access to eleven BCF of storage capacity. Storage gas is purchased and stored during the summer for redelivery during the heating season.
The Company has been purchasing gas from ANR since 1952. Today, ANR transports gas from Louisiana, the Gulf of Mexico, the Texas-Oklahoma Panhandle area and Canada. On November 1, 1993, FERC Order 636 became effective for ANR. Order 636 prohibits pipeline companies, such as ANR, from providing gas merchant services such as those provided in the past. 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 company with the approval of the FERC. As a result of restructuring under Order 636, the Company contracted for its pro-rata share of pipeline capacity from each of ANR's three supply areas: Southeast, 42,609 dekatherms per day; Southwest, 39,949 dekatherms per day; and Canada, 37,283 dekatherms per day. The initial term of each contract is for ten years with the right to extend in five-year increments. In addition, the Company has capacity on Viking Gas Pipeline for 7,880 dekatherms per day 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 November 1, 1993, pipeline company reservation charges for 1994 will total approximately $12.7 million. The
Company also has a no-notice service of 26,631 dekatherms per day from ANR with an annual reservation charge of $2.5 million per year. Storage reservation charges including the associated firm transportation to storage and storage to our service territory is $19.7 million per year.
On December 30, 1993, in FERC Docket No. TM 94-4-48-000, ANR filed its fifth 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 total remaining Company fixed charge obligation for the five take-or- pay dockets still outstanding is $500,692. Monthly fixed charge payments are scheduled to be made through June 1996, and volumetric payments through April 1998. There is the potential for one or two more take-or-pay filings by ANR. All of such costs will be passed through to the Company's 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 rates. These costs include purchased gas adjustment costs of which the Company's share is $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 $31.4 million through the year 2009. The Company, as part of the WDG, is contesting the legality of the Dakota Gasification Plant costs provision and is paying these costs under protest subject to refund.
The Company intends to utilize a currently inactive non- utility subsidiary, Packerland, to market gas supply services to transport customers both inside and outside the Company's service territory. Application for PSCW approval of an affiliated interest agreement between the Company and Packerland is pending.
The Company is a member of 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 also files interventions in cases to protect its interests as they may be different from the group. The Company is also advised by the same Washington, D.C. legal counsel. WDG is challenging the payment of above-market Dakota Gasification Plant costs in the District of Columbia Circuit Court. The case could be heard this spring.
All of the Company's Wisconsin metered retail 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 during generic proceedings in 1988. The Company's Michigan retail rates include a gas cost recovery plan under procedures authorized by the 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.
At the present time, all new Wisconsin and Michigan applicants for gas service, regardless of type and size, are being supplied with natural gas. About 5,200 customers were added in 1993. Growth in new gas customers is on an upward trend as the Company aggressively seeks new gas distribution customers.
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, but the customer has asked ANR to seek FERC approval for it to be connected directly to the ANR system. 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.
The following table sets forth the amounts of revenues, operating income and identifiable assets attributable to gas utility operations:
YEAR ENDED DECEMBER 31 1993 1992 1991 (thousands)
Gas Operating Revenues $187,376 $157,177 $152,222
Operating Income, Including $ 8,226 $ 6,141 $ 8,141 Allowance For Funds Used During Construction
Identifiable Assets $184,880 $158,314 $129,483
See Note 7 in Notes to Financial Statements.
D. ENVIRONMENTAL MATTERS
GENERAL. 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 DNR and the EPA. 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 installations 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. In December of 1985, a committee appointed by the governor of Wisconsin to review sulfur dioxide emission limitations for Wisconsin utilities and industries recommended reductions from 1980 emission levels in the range of 30% to 60%. These recommendations were written into law by the Wisconsin Legislature. The law requires that Wisconsin utilities reduce annual sulfur dioxide emissions to 1.2 pounds per million BTU by 1993. The plants which the Company operates are now in compliance with all current sulfur dioxide and nitrogen oxide emission standards.
The CAAA were enacted in 1990. The CAAA will require reductions in sulfur dioxide in 1995 (Phase I) to meet limitations based on an emission rate of 2.5 pounds per million BTU multiplied by a historical generation baseline for the Pulliam Unit 8 and Edgewater Unit 4 generating units. Due to the Wisconsin limits, these units will be operating at levels substantially below this federal rate.
The CAAA require further reductions beginning in the year 2000 (Phase II). These limits are set based on an emission rate of 1.2 pounds per million BTU multiplied by a historical generation baseline for all generating units. The methods that will be used to meet these reductions will be determined by individual utilities with the filing of compliance plans.
Because of the emission allowance system included in the CAAA, 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 Company intends to achieve compliance with Wisconsin and federal sulfur dioxide emission limitations by switching to low sulfur coal. As anticipated, fuel switching has adversely impacted several units regarding unit operation and particulate emission compliance. A total of $44 million has been expended to date at Pulliam and Weston to comply with 1993 and prior Wisconsin emission standards for opacity and sulfur dioxide. An additional $15 million to $25 million expenditure has been projected for the period from 1994 through 1999 to assure continued federal and Wisconsin emission compliance under all normal operating conditions at Pulliam and Weston. Expenditures include natural gas start-up equipment, flue gas conditioning, precipitator upgrades, coal blending systems, fuel handling modifications and boiler cleaning equipment.
The CAAA also require the installation of low nitrogen oxide burners on several units. Low nitrogen oxide burners, which would be required by 1995, will be completed early in 1994 for Pulliam Unit 8. Phase I of the CAAA 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 will be installed for Pulliam Unit 7 in 1994. Based on past experience, it is anticipated that expenditures related to sulfur dioxide and nitrogen oxide emission compliance will be recoverable in rates.
Air toxic provisions in the CAAA will not be applied until the EPA conducts a three-year study to determine if those standards need to be applied to utilities.
The Company received a NOV on September 11, 1986 from the EPA. The NOV resulted from alleged violations of opacity standards at Weston Unit 2 on January 17 and May 22, 1986. Company representatives have met with EPA-Region V representatives, and, although the parties did not reach a complete agreement on a resolution of the matter at the meeting, the EPA basically accepted the Company's plan for dealing with opacity control at the facility. Final settlement of this matter is still pending.
On November 26, 1986, the Company received a NOV from the EPA asserting that the emissions from Pulliam exceeded the applicable opacity limits. The Company has entered into negotiations with the EPA, and as part of a proposed resolution of the matter, the Company has installed a start-up gas burner system on Units 3-6 and flue gas conditioning on Units 5-8. The
Company paid a $37,500 penalty. An agreement between the Company and the EPA was finalized on September 27, 1993.
WATER QUALITY. The Company is subject to regulation by the DNR and the EPA 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.
GAS PLANT CLEANUP. The Company is currently investigating the need for environmental cleanup of seven manufactured gas plant sites previously operated by the Company. The Company has engaged an environmental consultant who estimates that the cost to remediate one specific site, the Stevens Point site, will be approximately $2.1 million. This estimate is based upon a detailed investigation of the site assuming excavation of impacted soils, disposal of soils to a licensed landfill for such materials, on-site groundwater extraction and treatment, and post-cleanup monitoring for twenty-five years. 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 estimate for the first site as a basis for making projections on cleanup costs at the other sites because of some similar characteristics at the other sites. The remaining six sites are located adjacent to rivers. Because the first site studied is not adjacent to a river, there is no data currently available as to possible contaminated river sediments. Based on estimates from the Gas Research Institute, for sites with minimal sediment contamination, and assuming all six sites have river contamination, the Company would probably spend at a minimum an additional $2.7 million to cleanup these six sites. Estimates of the maximum cost to cleanup river sites are not available. The range of cleanup costs is estimated to be from $6.4 million to $19.2 million, which includes the $2.7 million to cleanup the six river sites. Remediation expenditures would be made over the next thirty-three years. The Company has recorded as a liability with an offsetting deferred charge, i.e., a regulatory asset, $16.5 million, which represents the Company's current estimate of cleanup costs for all seven sites excluding possible costs of river contamination cleanup. 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 rates.
As additional detailed investigations are completed, five are anticipated in 1994, these estimates will be adjusted to reflect specific site data. Other factors that can impact 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 2, LEGAL PROCEEDINGS, 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 PRPs for the cleanup of 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 minimus 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 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 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 only being addressed by the DNR, and the current work is not being conducted as part of EPA's Superfund program. A community fund raising effort was undertaken ($5,000 was paid by the Company), which in combination with DNR contributions, paid for the remedial investigation and feasibility study. The DNR has selected a remedy which is estimated to cost $11 million to $12 million. The DNR has proposed to contribute approximately $4.5 million toward the remedy if the remaining amount is raised by the parties that contributed waste to the landfill. 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 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 PCB 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 is nearing completion.
E. REGULATORY 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 operation of Kewaunee and the construction and operation of any future nuclear plants are subject to the jurisdiction of the NRC.
In January of 1993, electric rates for Wisconsin retail customers increased $8.7 million, or 2.1% on average and natural gas rates for Wisconsin retail customers increased $3.8 million, or 2.3%. Subsequently, during 1993, the Company implemented two electric rate reductions totaling about $6.2 million on an annualized basis due to decreasing fuel costs.
In March of 1993, the Company made a 1994 rate filing with the PSCW requesting a decrease in electric rates of $1.3 million, or .3% and an increase in natural gas rates of $2.0 million, or 1.3%. During the rate case process, the Company proposed a three-year rate plan including electric rate reductions of 4% for 1994, 1.25% for 1995 and 1% for 1996. This proposal was based on a specific set of conditions. The PSCW proposed an alternate three-year plan with similar rate reductions but a different set of conditions. The Company and the PSCW were unable to agree on a number of non-rate related conditions. As a result, 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. The new rates for 1994 reflect an authorized rate of return of 11.3% on common equity, down from 12.3% in 1993.
In 1993, agreement was reached with the FERC customers and the FERC staff regarding the rate effects of the NERCO coal buyout. As a result, the Company has expensed $625,000 which represents the maximum amount of buyout costs allocable to the FERC jurisdiction which will not be recovered in customer rates.
The Company anticipates that the FERC will issue an order confirming this settlement.
No changes were made to Michigan electric and gas rates during 1993 other than through the fuel adjustment clause.
F. CAPITAL REQUIREMENTS
Anticipated capital requirements for 1994 are $87.1 million, of which $56.1 million, $6.4 million, $8.6 million, and $6.0 million are for electric construction, nuclear fuel, gas construction, and other construction expenditures, respectively, and $10.0 million for the funding of nuclear plant decommissioning, certain employee benefit plans and non-utility investments. All of the capital expenditures for 1994, and approximately 62% of the anticipated total capital expenditures of $294.3 million during 1995 and 1996, are expected to be financed through internal sources. The Company does not expect to sell permanent securities in 1994 or 1995. Security sales in 1996 are contingent upon the Company receiving approval to construct Rhinelander.
G. FORMATION OF HOLDING COMPANY
The Board of Directors, at its December meeting, approved the formation of a holding company system and authorized management to take all action to obtain the shareholder and regulatory approvals necessary for such corporate restructuring. A new corporation, known as Resources, was organized to become the holding company. If the required shareholder and regulatory approvals are obtained, one share of common stock of Resources will be exchanged on a tax free basis for each outstanding share of Company common stock. Resources will become the sole owner of the common stock of the Company which will continue its business and operations. Each holder of common stock of the Company will automatically become a shareholder of Resources and all certificates which previously represented common stock of the Company will thereafter, for all corporate purposes, be deemed to represent common stock of Resources. The exchange will not include the Company's preferred stock and first mortgage bonds. The Company believes that the new structure will create a structure which can more effectively address the growing competition in the energy industry, facilitate selective diversification into non-utility businesses which are related to the utility business of the Company or energy conservation or energy resources or which otherwise benefit the service territory of the Company, afford separation between utility and non-utility businesses thereby minimizing the risks associated with unregulated businesses to which Company customers and security
holders may be exposed, and provide additional flexibility for financing and for maintaining appropriate utility capital ratios.
H. DIVERSIFICATION
Packerland, a previously inactive wholly owned subsidiary, will be utilized to provide energy supply consulting and natural gas supply/transportation procurement services for commercial and industrial customers within and outside the Company's traditional service area. Packerland currently has only nominal assets.
Communications, a wholly owned subsidiary of the Company, was organized in 1985 to be a partner in the NorLight fiber optics telecommunications partnership. In 1991, the assets of NorLight were sold, and a portion of the purchase price was set aside to fund an escrow out of which the purchaser can be reimbursed for certain liabilities. In December of 1994, the escrow will terminate and any funds then held in the escrow and not payable to the purchaser of the NorLight assets will be distributed to the NorLight partners. It is anticipated that Communications will be dissolved at that time. In January of 1994, an indemnification claim in the amount of $188,653, of which the Communications' share is $62,884, was received from MRC.
Rapidly changing technologies have been associated recently with the electric and gas utility industry. That is why the Company continued its support of UTECH, a venture capital partnership which invests in new technologies that could be applied to utility operations. The Company has $2.5 million invested in UTECH.
I. EMPLOYEES
During 1993, the Company employed an average of 2,652 persons. Of this number, 2,175 and 477 were considered electric and gas utility employees, respectively.
Approximately 1,125 Company employees are represented by The International Union of Operating Engineers Local 310. The current contract runs through October of 1994. There has never been a strike against the Company by its employees.
ITEM 2.



ITEM 2. PROPERTIES
The following table includes information about electric generation facilities of the Company (including those jointly-owned):
(a) Based on 1993 winter capacity tests.
(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. The Kewaunee plant 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 Marshfield jointly own 105 kilowatts of combustion turbine peaking capacity which the Company operates. The entire capacity of the unit is included herein.
The Company owns 52 transmission substations with a transformer capacity of 5,163,043 kva; 91 distribution substations with a transformer capacity of 2,725,152 kva; and
21,870 route miles of electric transmission and distribution lines. Gas properties include approximately 3,409 miles of main, 65 gate and city regulator stations and 173,835 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 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 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 former 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 and the Company will negotiate an allocation of the costs associated with the site between themselves. Based on the initial study, and a more detailed investigation of the Company's Stevens Point site, it is believed that the cost of cleanup for the Sheboygan site could be as much as $2.1 million, excluding possible river cleanup costs which could increase the cost of the cleanup project. The Company has filed suit against its insurers seeking a declaratory judgment to establish the liability of insurers to reimburse costs associated with the Sheboygan and other gas plant matters.
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. The estimated cost of the study is $75,000. The city has claimed that contaminated groundwater from the former gas plant property has migrated onto city-owned land. Until the results of the study are compiled and analyzed (the Company is awaiting the results of laboratory tests), the Company is not able to determine the validity of the claim. The Company has filed suit against its insurers seeking a declaratory judgment to establish the liability of insurers to reimburse costs associated with the Oshkosh and other gas plant matters.
FEDERAL TAX AUDIT. The Company has received an audit report from the IRS for its 1984 through 1986 tax returns. The IRS has disallowed as a deduction amounts contributed by the Company to its defined benefit pension plans resulting in a deficiency of $3 million. The Company did not contest the adjustment. The audit included other adjustments unrelated to the pension plan issue for the years 1984 through 1986, including adjustments which offset the foregoing deficiency. The Company has contested certain of these adjustments as well as the disallowance of certain other claims for refund. The Company has reached a settlement with the IRS that will result in an overall refund of tax to the Company exceeding $1.3 million plus interest. If the PSCW follows the same practice it has in the past, the settlement, including interest, will be refunded to customers in future rate proceedings.
Incorporated herein by reference are the discussion of coal contract administration related litigation under "B. ELECTRIC OPERATIONS - Fuel" and the descriptions of the various proceedings relating to environmental matters described under "D. ENVIRONMENTAL MATTERS" both in Item 1 hereof.
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 registration statement on Form S-4, which will include a proxy statement for the annual meeting of the shareholders of the Company which is scheduled to be held on May 5, 1994, which Resources will file relating to shares of its common stock to be issued in connection with the formation of a holding company system.
EXECUTIVE OFFICERS OF THE REGISTRANT - ------------------------------------
Current Position and Business Effective Name and Age Experience During Past Five Years Date - ---------------------------- ------------------------------------ ---------
DANIEL A. BOLLOM 57 President and Chief Executive Officer 03-01-91 President and Chief Operating Officer 06-01-89 Senior Vice President-Operations 06-01-86
DANIEL P. BITTNER 50 Senior Vice President-Finance 03-01-92 Vice President-Treasurer 02-01-89 Treasurer 02-01-85
RICHARD A. KRUEGER 56 Senior Vice President-Power Supply and Engineering 07-01-89 Senior Vice President-Power Engineering and Construction 10-01-88 Vice President-Fossil Operations 11-01-86
CLARK R. STEINHARDT 52 Senior Vice President-Nuclear Power 06-01-91 Vice President-Nuclear Power 06-01-90 Assistant Vice President-Nuclear Power 07-01-89 Manager-Nuclear Power 06-01-88 Manager-Kewaunee Plant 07-01-84
PATRICK D. SCHRICKEL 49 Senior Vice President-Operations 06-01-89 Vice President-Gas Engineering and Supply 02-01-85
J. GUS SWOBODA 58 Senior Vice President-Marketing and Corporate Services 10-01-89 Senior Vice President-Marketing 06-01-89 Vice President-Marketing 11-01-87
BERNARD J. TREML 44 Assistant Vice President-Human Resources 07-01-93 Manager-Human Resources 08-01-92 Manager-Marketing Programs and Services 08-01-91 Manager-Retail Marketing 07-01-90 Administrator-Division Accounting 07-01-83
LARRY L. WEYERS 48 Vice President-Energy Supply 01-01-92 Assistant Vice President-Energy Supply 07-01-90 Director-Fuel Services 09-16-85
RICHARD E. JAMES 40 Assistant Vice President-Rates and Economic Evaluation 03-01-92 Manager-Rates and Economic Evaluation 01-01-89 Director-Rates and Economic Evaluation 10-01-87
ROBERT H. KNUTH 60 Assistant Vice President-Secretary 06-01-90 Secretary and Assistant Treasurer 05-11-78
DAVID W. SCHONKE 60 Assistant Vice President-Electric Distribution Engineering 06-01-86
Current Position and Business Effective Name and Age Experience During Past Five Years Date - ---------------------------- ------------------------------------ ---------
GLEN R. SCHWALBACH 48 Assistant Vice President-Gas Engineering and Supply 06-01-90 Manager-Gas Engineering and Supply 06-01-89 Gas Measurement and Utilization Supervisor 10-01-87
RALPH G. BAETEN 50 Treasurer 03-01-92 Insurance and Benefits Director 05-01-87
DIANE L. FORD 40 Controller 03-01-92 Administrator-Corporate Accounting 05-01-87
FRANK J. KICSAR 54 Assistant Secretary 03-01-92 Director-Corporate Tax 10-01-76
NOTE: All ages are as of December 31, 1993. None of the executives listed above are related by blood, marriage, or adoption to any of the other officers listed or to any director of the Registrant. Each officer shall hold office until his successor shall have been duly elected and qualified, or until his death, resignation, disqualification or removal.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
COMMON STOCK Two-Year Comparison
Dividends Share Data Per Share Price Range
1993 High Low 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
1st Quarter . . $ .425 28-5/8 26-1/8 2nd Quarter . . .425 29-3/8 27 3rd Quarter . . .435 32-1/4 29-1/4 4th Quarter . . .435 ------ 32-1/4 30-1/2 Total $1.72
Common Stock
Listed on the New York and Chicago Stock Exchanges
Ticker Symbol: WPS
Transfer Agent and Registrar:
Firstar Trust Company P.O. Box 2077 Milwaukee, Wisconsin 53201
As of December 31, 1993, there were 25,240 common stock shareholders of record.
See also Item 6


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
RESULTS OF OPERATIONS
1993 Compared to 1992
Electric operating revenues increased a total of $15.6 million, or 3.3%. This increase was the result of a 4.2% increase in kilowatt-hour (KWH) sales and a 2.1% rate increase for the Company's Wisconsin retail customers that was effective January 1, 1993. This was partially offset by rate reductions totalling $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 to this customer class of 6.7%.
Gas operating revenues increased $30.2 million, or 19.2%. This increase is primarily 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% retail Wisconsin rate increase ($5.5 million) effective January 1, 1993. The PSCW allows the Company to pass on to its customers, through a purchased gas adjustment clause, changes in the cost of gas. Residential revenues increased $17.3 million, and commercial and industrial revenues increased $14.6 million.
Electric production fuels decreased $9.8 million, or 7.9%, even though electric generation was up 2.1%. This decrease was primarily the result of less expensive coal, which has been purchased on the spot market. Such purchases decreased overall coal-related costs per kilowatt-hour by 11.8%, and reduced coal costs by approximately $14.2 million between years.
Gas purchased for resale increased $23.5 million, or 21.3%, due to higher gas volumes of 10.4%, and higher average cost of gas per dekatherm of 10.1%
Other operating expenses increased $12.7 million, or 9.3%, primarily due to increased amortization of 1991 coal and associated rail contract buy-outs costs of $2.9 million, and increased electric and gas conservation expenses of $9.7 million.
Maintenance expense increased $5.1 million, or 10.9%, primarily due to additional maintenance activities at the Company'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.
1992 Compared to 1991
Electric operating revenues increased $6.4 million, or 1%. This increase was the result of a 2% increase in kilowatt-hour (KWH) sales and a 1.4% rate increase for the Company's Wisconsin retail customers that was effective January 1, 1992. This was offset by a 1% rate reduction, effective May 1992 for Wisconsin retail customers due to reduced fuel costs. Residential KWH sales decreased approximately 2%, due to an extremely cool summer. This reduction was more than offset by increased KWH sales to large commercial and industrial customers, primarily in the paper industry.
Gas operating revenues increased $5 million, or 3%. Gas therm sales increased less than 1% due primarily to the relatively mild winter weather. Therm sales to firm and interruptible industrial customers increased by 2%, due largely to a shift from transport to system gas. Gas rates averaged a 5% increase reflecting the higher cost of purchased gas.
Electric production fuels decreased $7.2 million, or 5.5%, even though generation at the Company's coal and nuclear plants was up 2.1%. Nuclear fuel expense declined $1.4 million primarily due to a $1 million refund from the United States Department of Energy (DOE) retroactive to 1983 for nuclear fuel disposal costs. Since this refund will be returned to customers between 1993-1995, a liability was established to refund this amount to customers, which increased other expenses. Coal expense declined $5.4 million primarily due to a $3.8 million coal inventory adjustment in 1992, and a reduction in the average cost of coal. The latter reflects the Company's buyout of several long-term contracts, and the purchase of less expensive coal on the spot market, which reduced fuel costs by approximately $2.7 million between years.
Gas purchased for resale increased $6.7 million, or 6.5%, reflecting the higher cost of gas from spot market purchases.
Purchased power decreased $3.3 million, or 10.0% due to the 1992 Kewaunee nuclear plant refueling being shorter than the 1991 refueling, which reduced the need for replacement power, and the cooler summer.
Other expenses increased $6.8 million, or 5.3%, primarily due to the amortization of $3.4 million of coal and associated rail contract buy-out costs that were made in 1991, and the $1.0 million charge from the DOE for nuclear fuel disposal costs, as previously discussed.
Federal and state income taxes increased $1.6 million, or 5.7% due to higher pre-tax income.
Interest on long-term debt increased $3.5 million, or 16.0%, reflecting interest expense associated with the issuance of $60 million of first mortgage bonds in September 1991.
BALANCE SHEET
1993 Compared to 1992
Gas in storage increased $8.3 million. This increase in additional storage capacity reflects part of a package of transportation and storage services from ANR, the Company's primary gas transporter.
Investments and other assets increased $25.0 million. This increase primarily reflects the adoption of Statement of Financial Standards (SFAS) No. 87, Employers' Accounting for Pensions, as of January 1, 1993, whereby the Company recorded a prepaid pension asset of $20.0 million to reflect the overfunded status of the Company's pension plans. As of December 31, 1993 this asset totalled $24.5 million. The corresponding credit was recorded as a regulatory liability and is being refunded to customers over 5 years beginning in January 1993.
Accumulated deferred income taxes decreased $30.0 million. This decrease reflects the adoption of SFAS No. 109, Accounting for Income Taxes, in the first quarter of 1993, which reduced deferred income taxes by $33.0 million, net. The corresponding credit was recorded as a regulatory liability.
Regulatory liabilities increased $55.0 million with the adoption of SFAS No. 87 ($22.0 million) and SFAS No. 109 ($33.0 million) as previously discussed.
1992 Compared to 1991
Deferred charges increased $43.0 million. This increase reflects additional demand-side management (DSM) expenditures of $27.8 million, net, and deferred costs associated with
environmental remediation of old gas plant sites ($8.5 million) and charges under the National Energy Act for remediation of federal uranium enrichment facilities ($6.2 million).
FINANCIAL CONDITION
During 1993, the Company refinanced $164.5 million of long- term debt which will result in annual reductions in interest expense of approximately $3.0 million. As allowed by the PSCW, the costs associated with the refinancings have been deferred and are to be amortized to expense as the benefits of the lower interest rates are realized.
The Company continues to maintain good liquidity levels and a financial condition considered to be strong by utility analysts. Internally generated funds exceeded requirements during the year. No external funding difficulties are anticipated in the future. Pretax interest coverage was 4.5 times interest expense for the year ended December 31, 1993.
Rating agencies have reaffirmed the Company's bond ratings of AA+ (Standard & Poor's), Aa2 (Moody's), and AA+ (Duff & Phelps), even in light of the rating agencies' awareness of the increased competitive environment facing our industry. In addition, Standard & Poor's revised its methodology for rating utilities in 1993. Based on this, Standard & Poor's characterized the Company as having "above average business and competitive prospects."
The Company has identified the need for additional electric generating capacity or purchased power late in this decade. To satisfy this need, the Company has signed a 35-year Steam and Electrical Sales Agreement with Rhinelander Paper Company, Inc. Under the agreement, the Company plans to construct, own and operate a 116 megawatt cogeneration facility adjacent to Rhinelander's mill in Rhinelander, Wisconsin at a cost of $191 million. In addition, as required by the PSCW's newly developed bidding process, the Company has requested proposals for the same capacity from electric generating plant project developers or for power purchases from other utilities. The Company will compare the bids to the proposed Rhinelander facility before proposing a solution to its capacity and energy needs to the PSCW which must approve the final solution. A final decision is expected by late 1994. No other major construction projects are anticipated at this time.
For the five-year period 1994-1998, internally generated funds are expected to lag construction expenditures and other investments totalling $642 million by about $190 million. These
expenditures are comprised of $463 million for electric construction, $29 million for nuclear fuel, $43 million for gas construction, and $34 million for other construction expenditures; and $73 million for funding of nuclear plant decommissioning, certain employee benefit plans, and non-utility investments. The Company currently expects to finance this shortfall in internally generated funds by net bond additions of $124 million, common stock sales of $21 million, preferred stock sales of $25 million, and short-term debt of $20 million. However, no permanent security sales are anticipated until 1996.
The PSCW ordered revised depreciation rates to be effective January 1, 1994, which will reduce the annual depreciation provision by approximately $5.8 million.
In 1993, the Company filed for a rate decrease for Wisconsin retail customers, of $1.3 million (.3%) for electric, and an increase of $2.0 million (1.3%) for gas. A rate order was received in December 1993 giving the Company the option for a one or three year rate plan. The Company elected the one year plan which reduces electric rates by $17.4 million (4.0%) and increases gas rates by $1.0 (.6%). The authorized return on common equity was reduced from 12.3% to 11.3%.
SFAS No. 112, Employers' Accounting for Postemployment Benefits will become effective in 1994. This statement establishes accounting and reporting standards for post- employment benefits other than those covered by SFAS Nos. 87 and 106. As a result of adopting this statement, the Company is to expense $1.8 million of transition obligation costs in 1994 which is being recovered in utility rates.
TRENDS
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. In addition, the Kewaunee nuclear plant is regulated by the Nuclear Regulatory Commission (NRC), and environmental matters are primarily governed by the Environmental Protection Agency (EPA) and the Wisconsin Department of Natural Resources (DNR).
The regulatory environment is becoming more complex, especially with the Company's primary regulator, the PSCW, even
as competition becomes more prevalent. This is evidenced by the recently developed requirement of the PSCW that proposals for new power generation facilities be tested by a bidding process to ensure that cost effective projects are developed, statewide advance planning for generation and transmission, deregulation in the gas business, and increased emphasis on DSM. The Company has reacted to these changes with innovative rate designs, proposals for new generation, new conservation programs and partnerships with customers. In general, the regulatory climate in Wisconsin is viewed as being above average by outside parties.
In December 1993, the Board of Directors of the Company approved the formation of a holding company to be known as WPS Resources Corporation (WPS Resources). If the required shareholder and regulatory approvals are obtained, one share of $1 par common stock of WPS Resources will be exchanged on a tax free basis for each outstanding share of the Company's $4 par common stock. The share exchange and corporate restructuring will not result in any change in accounting treatment for the Company. After the share exchange, the accounts of the Company will be included in the consolidated financial statements of WPS Resources. The intent at this time is that subsidiaries created under WPS Resources will offer energy or energy-related products and/or services.
In order to address the complexities in the natural gas market as a result of the Federal Energy Regulatory Commission's Order 636 that went into effect in November 1993, the Company has formed a non-utility subsidiary Packerland Energy Services, Inc. This subsidiary will be brokering gas, and selling transportation and energy management services primarily to regional commercial and industrial businesses.
The Company has accrued $16.5 million for the environmental remediation of seven manufactured gas plant sites previously operated by the Company. This accrual is based on a study that was recently completed at one site, and was used as the basis for making projections on the six remaining sites. The range of cleanup costs for all seven sites is estimated to be from $6.4 million to $19.2 million.
Because the first site studied is not adjacent to a river, there is no data currently available as to possible contaminated river sediments. The remaining six sites are adjacent to rivers. Based on estimates from the Gas Research Institute, for sites with minimal sediment contamination, and assuming all six sites have river contamination, the Company would probably spend, at a minimum, an additional $2.7 million to clean up these sites.
As additional site specific studies are completed (five are anticipated in 1994) these estimates will be adjusted. Other
factors that can impact these estimates are changes in remedial technology and regulatory requirements. The estimates presented do not take into consideration any recovery from insurance carriers or other third parties which the Company is pursuing. Based on discussions with regulatory authorities, and a recent rate order in the Wisconsin jurisdiction, management believes that these costs, but not carrying costs on deferred expenditures, will be recoverable in future rates.
In addition, the Company has been notified that it is a minor participant in some waste disposal sites. However, no significant costs are anticipated to cleanup these sites.
New Federal Clean Air Act amendments were enacted in 1990. The Act establishes stringent sulfur dioxide and nitrogen oxide emission limitations. Wisconsin had previously enacted laws to limit sulfur emissions. The Company anticipates meeting these new limitations primarily by switching to lower sulfur fuels. However, some new 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 to $25 million between 1994 and 1999.
In the PSCW's latest 20 year advance plan, the Commission reaffirmed their support for DSM as a proper means to control energy growth in Wisconsin, and has increased the targeted reductions for all state utilities. This amounts to a reduction of 340 megawatts for the Company through 2010. The Company has been a leader in this area and expects to meet the targets set by the PSCW.
For a more detailed discussion of these items, refer to the notes (1)(j) and (6) to financial statements.
The steam generator tubes at Kewaunee are susceptible to corrosion characteristics seen throughout the nuclear industry. Annual inspections are performed to identify degraded tubes. Degraded tubes are either repaired by sleeving or are 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 is a gradual decrease in the capacity of the plant. Currently, the equivalent of 10% of the tubes in the steam generators are plugged. The Company continues to evaluate appropriate repair strategies, including replacement at a projected cost of $132.9 million (Company share $54.7 million), as well as continued operation of the steam generators without replacement. The Company intends to operate Kewaunee
until at least 2013, the expiration of the present operating license. The Company is also evaluating initiatives to improve the performance of Kewaunee. These initiatives include funding of the development of welded repair technology for steam generator tubes and numerous cost reduction measures such as the conversion from a twelve-month to an eighteen-month fuel cycle. If the steam generators are not replaced, and excluding the possible affect of the aforementioned repair strategies, the Company projects a gradual power reduction of approximately 1% per year which may begin as soon as 1995.
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, quantifiable statement of financial results but do not evaluate the impact of inflation. Under ratemaking prescribed by the commissions regulating the Company, 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, the Company is only allowed to recover the historical cost of plant via depreciation in these forecasts.
NOTES TO FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(a) Business
The 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 Restructuring
On December 9, 1993, the Board of Directors of the Company approved the formation of a holding company to be known as WPS Resources Corporation (WPS Resources). If the required shareholder and regulatory approvals are obtained, one share of $1 par common stock of WPS Resources will be exchanged on a tax free basis for each outstanding share of the Company's $4 par common stock. The share exchange and corporate restructuring will not result in any change in accounting treatment for the Company. After the share exchange, the accounts of the Company will be included in the consolidated financial statements of WPS Resources.
Once the holding company is formed, in all subsequent financial statements, preferred stock dividends of the Company would be retroactively restated as a nonoperating expense. This restatement would have no impact on earnings on common stock, or on earnings per share.
(c) 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 1993, retail rate was approximately 10.8%.
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 1993, this rate was approximately 5.2%.
Substantially all of the Company's utility plant is subject to a first mortgage lien.
(d) 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 property units. Maintenance and repair costs and replacement and renewal of items less than units of property are generally charged to operating expenses.
In October 1993, the Company sold, at its cost, a 32% interest in a combustion turbine to a municipality for $7.8 million.
(e) Depreciation
Straight-line composite depreciation expense is recorded over the estimated useful life of the property (including estimated salvage and cost of removal) as approved by the PSCW.
In a rate order received in December 1993 to become effective January 1, 1994, new depreciation rates were ordered which will decrease annual depreciation expense by approximately $5.8 million.
1993 1992 1991 ---- ---- ---- Annual composite depreciation rates: Electric . . . . . . . . . . . . . . . . 3.88% 3.87% 3.80% Gas. . . . . . . . . . . . . . . . . . . 3.81% 3.81% 4.13%
(f) Nuclear Decommissioning Matters
Nuclear decommissioning costs are accrued over the estimated service life of the Kewaunee nuclear plant (Kewaunee), currently recovered from customers in rates, and deposited in external trusts. Such costs totalled $2.4 million, $2.4 million and $3.2 million for 1993, 1992, and 1991, respectively. In a rate order to become effective January 1, 1994, decommissioning costs recovered in rates will be $4.0 million. As of December 31, 1993, the external trusts totalled $56.7 million ($60.6 million market value). The Company's share of
Kewaunee decommissioning costs is estimated to be $149 million in current dollars based on a site specific study, performed in 1992, using immediate dismantlement as the method of decommissioning.
Depreciation expense includes decommissioning costs recovered and a charge to offset earnings from the external trusts. As of December 31, 1993, the accumulated provision for depreciation included accumulated provisions for decommissioning totalling $56.7 million.
(g) Nuclear Fuel
The cost of nuclear fuel is amortized to fuel expense based on the quantity of heat produced for the generation of electric energy by Kewaunee. The costs amortized to 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 fee related to 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 1999, and after modifications are made to the spent fuel pool, through the year 2012.
(h) Cash and Equivalents
The Company considers short-term investments with an original maturity of three months or less to be cash equivalents.
(i) Revenue and Customer Receivables
The Company accrues revenues related to electric and gas service, including estimated amounts for service rendered but not billed.
Included in customer receivables and in investments and other assets is a total of $3.5 million of energy conservation loans to customers as of December 31, 1993. 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 fuel cost for the upcoming year. If the Company's actual fuel costs fall outside this range, a hearing may be held and 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 also permitted to recover bad debts in utility rates.
Approximately 9% of the Company's total revenues are from companies in the paper products industry.
(j) Deferred Charges
Deferred charges represent costs recoverable in future rates.
Deferred charges are as follows: 1993 1992 1991 ---- ---- ---- (Thousands)
DSM expenditures . . . . . . . . . $ 46,219 $33,438 $ 5,633 Coal and rail contract buy-out costs . . . . . . . . . 24,168 30,822 34,067 Environmental remediation costs . . . . . . . . . . . . . 16,451 9,100 600 Debt refinancing costs . . . . . . 10,743 6,139 5,431 Enrichment facility fee . . . . . 5,082 6,180 -- Natural gas obligations . . . . . 4,210 8,319 3,041 Computer software . . . . . . . . 2,782 5,451 7,231 Other. . . . . . . . . . . . . . . 8,473 6,941 7,357 ------- ------- ------ Total $118,128 $106,390 $63,360 ======= ======= ======
Beginning in 1991, the PSCW increased the Demand Side Management (DSM) expenditures the Company was making to promote electric and gas conservation. A significant portion of these expenditures are deferred and are to be recovered in utility rates over a ten-year period. In the PSCW's latest advance plan, DSM was reaffirmed as an integral part of their long-term energy planning.
In 1991, in order to lower overall fuel costs, the Company bought out of a major long-term coal contract and its related rail transportation contract. These buyouts totalled approximately $34.0 million. Based on management analyses and projected benefit tests as prescribed by regulators, these buyouts are expected to yield to ratepayers benefits that significantly exceed their costs.
Management believes it is probable that the Company will continue to recover from ratepayers all deferred charges described above based on prior and current rate treatment of such costs.
(k) Regulatory Liabilities
Regulatory liabilities represent costs previously collected that are refundable in future rates.
See notes (1)(m) and (1)(n) for specific discussion of deferred taxes and pension regulatory liabilities.
Regulatory liabilities have been established for the following items as of December 31,:
1993 1992 1991 ---- ---- ---- (Thousands)
Deferred taxes . . . . . . . . . . $33,030 $ - $ - Pensions . . . . . . . . . . . . . 22,021 6,619 - Other. . . . . . . . . . . . . . . 6,383 (226) 926 ------ ------ ------
Total $61,434 $ 6,393 $ 926 ====== ====== ======
(l) Investments and Other Assets
Investments include various immaterial subsidiaries and 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 on officers 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 1993, 1992 and 1991. Prior to January 1, 1993, the PSCW required the recognition of the funded amounts for ratemaking and financial reporting purposes. Concurrent with a rate order effective January 1, 1993, the Company adopted the accrual method of accounting for pension costs under SFAS No. 87. In connection therewith, the Company recorded a prepaid pension cost
and related regulatory liability of $20.0 million reflecting the plans' overfunded status. Beginning January 1, 1993, this regulatory liability is being returned to ratepayers over five years.
The following tables set forth the plans' funded status and expense (income).
The Company also has self-funded plans which provide 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, 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. The cost of post-retirement health care benefits for future retirees is recognized using the projected unit credit actuarial method. In adopting SFAS No. 106, the Company elected to recognize the transition obligation for current and future retirees over 20 years.
Since 1981, the Company has been prospectively funding amounts to irrevocable trusts as allowed for income tax purposes. These funded amounts have been expensed and recovered through rates. The investments of the trust covering administrative employees are subject to federal income taxes at a 31% tax rate, while the non- administrative trust is tax-exempt.
The following tables set forth the plans' accrued post retirement benefit obligation (APBO), as of December 31 and expense provision for the year then ended.
---- Retirees and dependents . . . . . . . . . . . . . . . $(47,095) Fully eligible active plan participants . . . . . . . (5,671) Other active plan participants . . . . . . . . . . . (66,681) ------- Total APBO. . . . . . . . . . . . . . . . . . . . . . (119,447) Fair value of plan assets . . . . . . . . . . . . . . 68,949 -------- APBO in excess of plan assets . . . . . . . . . . . . (50,498) Unrecognized net loss . . . . . . . . . . . . . . . . (1,400) Unrecognized prior service cost . . . . . . . . . . . - Unrecognized transition obligation . . . . . . . . . 45,756 -------- Accrued post-retirement benefit obligation . . . . . $ (6,142) ========
Benefits earned during the year . . . . . . . . . . . $ 4,379 Interest on APBO. . . . . . . . . . . . . . . . . . . 8,248 Actual return on plan assets. . . . . . . . . . . . . (4,861) Net amortization and deferral . . . . . . . . . . . . 2,262 -------- Post-retirement benefit cost . . . . . . . . . . . . $ 10,028 ========
The assumed expected long-term return on investments and 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 in 1993 were 13% (medical) and 9% (dental), decreasing to 7% and 5%, respectively, over the following 13 years. The assumed increase in health care cost for 1994 is 11.5% (medical) and 8.5% (dental).
Increasing each of the medical and dental cost trend rates by 1% in each year would increase the total APBO as of December 31, 1993 by $26.4 million and the total net periodic post-retirement benefit cost for the year then ended by $4.3 million.
During 1992 and 1991, the cost of post-retirement health care benefits was $2.7 million and $5.0 million, respectively.
As of December 31, 1993, the Company had approximately 956 retirees eligible to receive health care benefits.
Concurrent with a rate order effective January 1, 1994, the Company adopted SFAS No. 112, which establishes accounting and reporting standards for post-retirement benefits other than those covered by SFAS Nos. 87 and 106. In connection therewith, the Company will expense in 1994 the transition obligation of $1.8 million.
The Company has a leveraged Employee Stock Ownership Plan and Trust (ESOP) that held 2,303,250 shares of Company common stock (market value approximately $77.4 million) at December 31, 1993. At that date, the ESOP also had loans guaranteed by the Company and secured by the common stock. At December 31, 1993, these loans had recorded values of $2.8 million (bearing an interest rate of 73.5% of prime rate) and $20.6 million (bearing an interest rate of 9.33%). The estimated market value of these loans at December 31, 1993 totalled $24.7 million.
Principal and interest on the loans are to be paid through Company contributions and dividends on Company 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 service. 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 employee contribution is an approximately equal sharing of benefits of the program between customers and employees.
(n) Income Taxes
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.
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 as excess deferred income taxes resulting from taxes provided at rates greater than current rates and previously unrecorded taxes have been recorded as a regulatory liability/asset to be refunded to/collected from customers in future years. Such net regulatory liability totalled $33.0 million as of December 31, 1993.
As of December 31, 1993, the Company had the following significant temporary differences that created deferred tax assets and liabilities:
Deferred tax assets- Plant related . . . . . . . . . . . . . . . . . . . . $ 48,853 Other . . . . . . . . . . . . . . . . . . . . . . . . 17,207 ---------- Total 66,060
Deferred tax liabilities- Plant related . . . . . . . . . . . . . . . . . . . . 162,752 DSM expenditures . . . . . . . . . . . . . . . . . . 18,242 Coal and rail contract buy-out costs . . . . . . . . 9,154 Other . . . . . . . . . . . . . . . . . . . . . . . . 14,864 ---------- Total 205,012 ----------
Net deferred tax liabilities $ 138,952 ==========
(2) JOINTLY-OWNED FACILITIES:
Information with respect to the Company's share of major jointly- owned electric generating facilities in service at December 31, 1993 is as follows:
Columbia Edgewater Energy Unit Center No. 4 Kewaunee -------- --------- -------- (Thousands except for percentages)
Ownership 31.8% 31.8% 41.2% Plant capacity (Mw) 335.2 104.9 221.0 Utility plant in service $110,190 $21,608 $132,711 Accumulated provision for depreciation $ 55,910 $11,005 $ 68,530 In-service date 1975 and 1978 1969 1974
The Company's share of direct expenses for these plants is included in the corresponding operating expenses in the statements of income, and the Company has supplied its own financing for all jointly-owned projects. Nuclear decommissioning costs are excluded from the depreciation amount reported for Kewaunee.
(3) 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:
1993 1992 1991 ---- ---- ---- (Thousands except for percentages) As of end of year - Discount rate on outstanding commercial paper 3.4% 3.4% 4.9% Interest rate on note payable 3.3% 3.5% 4.2% Unused lines of credit $22,970 $23,150 $23,150 Compensating balance requirements $99 $108 $108 For the year - Maximum amount of borrowings $27,000 $22,500 $44,000 Average amount of borrowings $12,263 $12,414 $29,541 Weighted average interest rate on borrowings 3.2% 3.8% 6.3%
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 compliance with certain financial covenants is maintained. These agreements extend for 13 months or more. As of December 31, 1993, no borrowings were outstanding under these agreements.
(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 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 for at least ten years.
In 1998, $50 million of 5-1/4% bonds will mature.
As of December 31, 1993 the market value of the Company's first mortgage bonds was $312.9 million (recorded value of $292.1 million).
(5) COMMON EQUITY:
In June 1992, 800,000 shares of new common stock were issued. This sale increased the common stock balance by $3.2 million ($4 par per share) and premium on capital by $19.4 million ($24.25 per share). Also, beginning in June 1992, the Company commenced a sale of shares to meet dividend reinvestment program (DRP) requirements. The Company is authorized to issue up to 600,000 shares of new common stock pursuant to the DRP. During 1993 and 1992, 50,818 and 157,524 shares, respectively, were issued under the DRP and 391,658 shares were available for issuance at December 31, 1993. In April 1993, the Company stopped issuing common stock under the DRP and began purchasing common stock on the open market for shareholder reinvested dividends.
At December 31, 1993, $287.8 million of retained earnings were available for dividends. However, the PSCW requires the Company to maintain an average common equity capitalization ratio in a range between 47% to 52%, which incorporates the Company's leveraged ESOP, thereby limiting the amount available to be paid out as dividends.
(6) COMMITMENTS AND CONTINGENCIES:
Coal Contracts - --------------
To ensure a reliable, low cost supply of coal the Company has entered into certain long-term contracts that have take-or-pay obligations totaling $319.0 million from 1994 through 2016. The obligations are subject to force majeure provisions which provide the Company other options, if the specified coal will not meet emission limits and acid rain legislation. In the opinion of management, any amounts paid under the take-or-pay obligations described above would be a legitimate cost of service subject to recovery in rates.
Gas Costs - ---------
The Company also has natural gas supply and transportation contracts that require total demand payments of $417.4 million through October 2003. Management believes that these costs will be recoverable in future 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, 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, 1993, the Company has an accrued liability with an offsetting regulatory asset in the amount of $3.7 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 rates.
The Company will be billed $2.0 million in 1994 for 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 $31.4 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 $27.0 million per incident, not to exceed $4.1 million per incident, per calendar year. These amounts represent the Company's 41.2% ownership share of Kewaunee.
Joint Plant Litigation - ----------------------
The Columbia Energy Center (Columbia) is owned 31.8% by the Company, 46.2% by Wisconsin Power and Light Company (WP&L), and 22.0% by Madison Gas and Electric Company (MG&E). WP&L operates Columbia. In 1989, the PSCW concluded that WP&L did not properly administer a coal contract for Columbia and ordered WP&L to refund $9 million to the ratepayers of WPSC, WP&L and MG&E proportionately according to the ownership shares of each utility in Columbia. WP&L appealed the PSCW decision, and such decision has been found to represent unlawful retroactive ratemaking by both the Dane County Circuit Court and the Wisconsin Court of Appeals. The case is currently before the Wisconsin Supreme Court. Although the ultimate outcome
of this matter is uncertain, in the opinion of Company management, there will be no material effect on the Company's results of operations or financial position.
Clean Air Regulations - ---------------------
In 1990, the Federal Clean Air Act Amendments (CAAA) were signed into law. The CAAA requires the Company to meet new emission limits for sulphur dioxide (SO2) and nitrogen oxide (NOx) in 1995 (Phase I) and in the year 2000 (Phase II). Since Wisconsin had already mandated reduced SO2 emissions by 1993 which were lower than the Federal levels mandated for 1995, the Company was already working on lowering emissions. Since Federal limits are more stringent than those mandated by Wisconsin in the year 2000, the Company is continuing to develop compliance plans for Phase II of the CAAA. The Company will comply cost effectively with both the Federal and Wisconsin SO2 laws primarily through fuel switching. The Company was in compliance with the new Wisconsin SO2 limits in 1993.
The final Federal regulations for NOx are not known at this time; however, based on draft rules the Company expects to make additional capital expenditures in the range of $15-$25 million between 1994 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 rates.
Manufactured Gas Plant Remediation - ----------------------------------
The Company is currently investigating the need for environmental cleanup of seven manufactured gas plant sites previously operated by the Company and has engaged an environmental consultant who estimated that the cost to remediate one specific site would be approximately $2.1 million. This estimate is based upon an investigation of the site and assumes excavation of impacted soils, disposal of soils to a licensed landfill for such materials, on-site groundwater extraction and treatment, and post-cleanup and monitoring for 25 years. The consultant has not yet performed phase II investigations of the remaining six sites and therefore comparable information on these sites is not available.
Because the first site is not on a river and the remaining six sites are, there is no data currently available as to possible contaminated river sediments. As a result, it is difficult to estimate the cost of cleanup in the rivers if contamination should be present; however, based on estimates from the Gas Research Institute for sites with minimal sediment contamination, and assuming all six sites have river contamination, management estimates the additional cost for minimum river remediation to be $2.7 million in total.
The Company used the estimate on the first site 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 are estimated to be in the range of $6.4 to $19.2 million. However, management's current estimate of cleanup costs for all seven sites, excluding any river sediment cleanup, is $16.5 million which would be spent over the next 33 years.
The $16.5 million estimate has been recorded as a liability with an offsetting deferred charge (regulatory asset). Based on discussions with regulatory authorities and effective with a recent rate order, these costs, less any insurance recoveries, will be recoverable in future rates, except for carrying costs.
As additional site specific studies are completed (five are anticipated in 1994), these estimates will be adjusted to reflect specific site data. Other factors that can impact these estimates are changes in remediation technology and regulatory requirements. This estimate does not take into consideration any recovery from insurance carriers or other third parties which the Company is pursuing.
The Company is also involved, and has made minor payments for the investigation and potential cleanup of certain waste disposal sites. Management believes the Company has been a minor contributor to the total contamination at these known 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 116 megawatt cogeneration facility with Rhinelander Paper Company and has filed an application for a Certificate of Public Convenience and Necessity (CPCN) with the PSCW requesting approval for the project. Estimated cost for the project is $191 million. In addition, as required by the PSCW's newly developed bidding process, the Company has requested proposals for the same capacity from electric generating plant project developers and power purchases from other utilities. The Company will compare the bids before proposing a solution to its capacity and energy needs to the PSCW, which must approve the option selected. A final decision is expected by late 1994.
New Construction - ----------------
Management estimates 1994 utility plant construction expenditures to be approximately $77.1 million. DSM expenditures are estimated to be $32.8 million, of which approximately $20.6 million will be deferred and amortized over the next ten years.
(7) SEGMENTS OF BUSINESS:
The following table presents information for the respective years pertaining to the Company's operations segmented by lines of business. The information does not represent ratemaking treatment since the Company is regulated by three jurisdictions with differing ratemaking practices.
(8) QUARTERLY FINANCIAL INFORMATION (Unaudited):
Because of various factors which affect the utility business, the quarterly results of operations are not necessarily comparable.
(1) In the quarters ended December 1993 and 1992, the Company recorded adjustments as a result of its annual coal inventory observation. These adjustments increased net income and earnings per average share of common stock by $1.2 million and $.05, respectively, for 1993, and $2.3 million and $.09, respectively, for 1992.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Wisconsin Public Service Corporation:
We have audited the accompanying balance sheets and statements of capitalization of WISCONSIN PUBLIC SERVICE CORPORATION (a Wisconsin corporation) as of December 31, 1993, 1992 and 1991, and the related statements of income, retained earnings and cash flows for the years then ended. These financial statements and the schedules referred to below are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Wisconsin Public Service Corporation as of December 31, 1993, 1992 and 1991, and the results of its operations and its cash flows for the years then ended 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 pensions, postretirement benefits other than pensions and income taxes.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental Schedules V, VI and X are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Milwaukee, Wisconsin, ARTHUR ANDERSEN & CO. January 26, 1994.
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 the Company's proxy statement. Such information will be included in a registration statement on Form S-4, which will include a proxy statement for the annual meeting of the shareholders of the Company which is scheduled to be held on May 5, 1994, which Resources will file relating to shares of its common stock to be issued in connection with the formation of a holding company system.
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 statements are included in Part II at Item 8