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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
X
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For the fiscal year ended December 31, 1993
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
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For the transition period from to
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Commission file number 1-3016
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WISCONSIN PUBLIC SERVICE CORPORATION
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(Exact name of Registrant as specified in its charter)
WISCONSIN 39-0715160
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
700 North Adams St., P. O. Box 19001, Green Bay, Wisconsin 54307
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (414) 433-1445
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
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Common Stock, $4 par value New York Stock Exchange and
Chicago Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, Cumulative, $100 par value
5.00% Series 5.08% Series
5.04% Series 6.76% Series
(Title of Classes)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X . No .
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. ( )
State the aggregate market value of the voting stock held by nonaffiliates of
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the Registrant.
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$ 725,870,221 as of February 4, 1994
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Number of shares outstanding of each class of common stock, as of December 31,
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1993:
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Common Stock, $4 par value 23,896,962 Shares
DOCUMENTS INCORPORATED BY REFERENCE
(1) Definitive proxy statement for Annual Meeting of Shareholders on May 5,
1994 (Incorporated into Parts I and III)
WISCONSIN PUBLIC SERVICE CORPORATION
FORM 10-K
ANNUAL REPORT TO THE SECURITIES AND EXCHANGE COMMISSION
For the Year Ended December 31, 1993
TABLE OF CONTENTS
DEFINITIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii
PART I
1. BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
A. GENERAL. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
B. ELECTRIC OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . 1
General. . . . . . . . . . . . . . . . . . . . . . . . . . 1
Kewaunee Nuclear Plant . . . . . . . . . . . . . . . . . . 2
Fuel Supply. . . . . . . . . . . . . . . . . . . . . . . . 4
Wholesale Customers. . . . . . . . . . . . . . . . . . . . 8
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 8
C. GAS OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . .11
D. ENVIRONMENTAL MATTERS. . . . . . . . . . . . . . . . . . . . . .15
General. . . . . . . . . . . . . . . . . . . . . . . . . .15
Air Quality. . . . . . . . . . . . . . . . . . . . . . . .15
Water Quality. . . . . . . . . . . . . . . . . . . . . . .17
Gas Plant Cleanup. . . . . . . . . . . . . . . . . . . . .17
Other Solid Waste Disposal . . . . . . . . . . . . . . . .18
E. REGULATORY MATTERS . . . . . . . . . . . . . . . . . . . . . . .19
F. CAPITAL REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . .20
G. FORMATION OF HOLDING COMPANY . . . . . . . . . . . . . . . . . .20
H. DIVERSIFICATION. . . . . . . . . . . . . . . . . . . . . . . . .21
I. EMPLOYEES. . . . . . . . . . . . . . . . . . . . . . . . . . . .21
2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22
3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . . . . . . .23
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24
4A. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT . . . . . . . . . .24
PART II
5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS. . . . . . . . . . . . . . . . . . . . . .27
6. SELECTED FINANCIAL DATA. . . . . . . . . . . . . . . . . . . . . . . .28
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION . . . . . . . . . . . . . . . . . .30
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. . . . . . . . . . . . . .38
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS . . . . . . . . . . . . . . .60
9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . .61
PART III
PART IV
14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K. . . . . . . . . . . . . . . . . . . . . . . . . .61
DESCRIPTION OF DOCUMENTS . . . . . . . . . . . . . . . . . . . . . . .63
DEFINITIONS
The following abbreviations and acronyms are used in the text of
this Form 10-K:
ANR. . . . . . . . . . . . . . ANR Pipeline Company
CAAA . . . . . . . . . . . . . Federal Clean Air Act Amendments of
1990
Columbia . . . . . . . . . . . The Columbia Energy Center
Communications . . . . . . . . WPS Communications, Inc.
Company. . . . . . . . . . . . Wisconsin Public Service
Corporation
DNR. . . . . . . . . . . . . . Wisconsin Department of Natural
Resources
DOE. . . . . . . . . . . . . . U. S. Department of Energy
DSM. . . . . . . . . . . . . . Demand side management
Edgewater. . . . . . . . . . . The Edgewater Unit 4 power plant
EPA. . . . . . . . . . . . . . U. S. Environmental Protection
Agency
FERC . . . . . . . . . . . . . Federal Energy Regulatory
Commission
FRV. . . . . . . . . . . . . . Fox River Valley Railroad
Corporation
FVW. . . . . . . . . . . . . . Fox Valley & Western, Ltd.
GBW. . . . . . . . . . . . . . Green Bay & Western Railroad
Company
INPO . . . . . . . . . . . . . Institute of Nuclear Power
Operations
IRS. . . . . . . . . . . . . . Internal Revenue Service
Kewaunee . . . . . . . . . . . Kewaunee Nuclear Power Plant
-iii-
Marshfield . . . . . . . . . . Marshfield Electric and Water
Department
MG&E . . . . . . . . . . . . . Madison Gas and Electric Company
MPSC . . . . . . . . . . . . . Michigan Public Service Commission
MRC. . . . . . . . . . . . . . MRC Telecommunications, Inc.
NERCO. . . . . . . . . . . . . NERCO Coal Company
NNAB . . . . . . . . . . . . . National Nuclear Accrediting Board
NOV. . . . . . . . . . . . . . Notice of violation
NRC. . . . . . . . . . . . . . U. S. Nuclear Regulatory Commission
NSP. . . . . . . . . . . . . . Northern States Power Company
Nuclear Policy Act . . . . . . Nuclear Waste Policy Act of 1982
Packerland . . . . . . . . . . Packerland Energy Services, Inc.
PCB. . . . . . . . . . . . . . Polychlorinated biphenyl
Policy Act . . . . . . . . . . The National Energy Policy Act of
1992
PRP. . . . . . . . . . . . . . Potentially responsible party
PSCW . . . . . . . . . . . . . Public Service Commission of
Wisconsin
Pulliam. . . . . . . . . . . . The Pulliam generating facility
PURPA. . . . . . . . . . . . . Public Utility Regulatory Policy
Act
Railroads. . . . . . . . . . . Soo Line and Wisconsin Central
railroads
Rapids . . . . . . . . . . . . The City of Wisconsin Rapids
REA. . . . . . . . . . . . . . Rural Electrification
Administration
Resources. . . . . . . . . . . WPS Resources Corporation
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Rhinelander. . . . . . . . . . The cogeneration facility proposed
to be built adjacent to the
Rhinelander Paper Company, Inc.
mill in Rhinelander, Wisconsin
Rhinelander Paper. . . . . . . Rhinelander Paper Company, Inc.
River Power. . . . . . . . . . Wisconsin River Power Company
SEC. . . . . . . . . . . . . . U. S. Securities and Exchange
Commission
Superfund. . . . . . . . . . . Comprehensive Environmental
Response, Compensation and
Liability Act
Waste Policy Act . . . . . . . Low-Level Radioactive Waste Policy
Act of 1980
WC . . . . . . . . . . . . . . Wisconsin Central Railroad
Weston . . . . . . . . . . . . The Weston generating facility
Wisconsin. . . . . . . . . . . State of Wisconsin
WDG. . . . . . . . . . . . . . Wisconsin Distributors Group
WEPCO. . . . . . . . . . . . . Wisconsin Electric Power Company
WP&L . . . . . . . . . . . . . Wisconsin Power and Light Company
WPPI . . . . . . . . . . . . . Wisconsin Public Power, Inc.
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PART I
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
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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.
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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
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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
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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.
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(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-
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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
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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
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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
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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.
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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
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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.
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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.
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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
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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
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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
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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
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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.
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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
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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.
-21-
ITEM 2. PROPERTIES
The following table includes information about electric
generation facilities of the Company (including those
jointly-owned):
RATED
CAPACITY(a)
TYPE NAME LOCATION FUEL (KILOWATTS)
Steam Pulliam Green Bay, WI Coal 397,000 (b)
Weston Wausau, WI Coal, or Gas 493,800 (c)
Kewaunee Kewaunee, WI Nuclear 216,300 (d)
Columbia -
Units No. 1 & 2 Portage, WI Coal 333,800 (d)
Edgewater
Unit No. 4 Sheboygan, WI Coal 104,000 (d)
---------
Total Steam 1,544,900
Hydro Various 70,000
(15 Plants)
Combustion Various Gas, or Oil 292,300 (e)
Turbine (6 Plants)
& Diesel
Wind Turbine Kewaunee, WI 40
---------
Total System 1,907,240
=========
(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
-22-
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. 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
-23-
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. 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.
-24-
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
-25-
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.
-26-
PART II
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
1992
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 below.
-27-
ITEM 6. SELECTED FINANCIAL DATA
STATISTICS - FINANCIAL
Statements Of Income (Thousands)
1993 1992 1991 1990 1989 1988 1983
----------- ----------- ----------- ----------- ----------- ----------- ----------
Operating Revenues:
Electric. . . . . . . . . . . . . . $493,256 $477,625 $471,277 $448,905 $442,938 $435,958 $389,197
Gas . . . . . . . . . . . . . . . . 187,376 157,177 152,222 140,068 142,874 168,376 240,694
----------- ----------- ----------- ----------- ----------- ----------- ----------
680,632 634,802 623,499 588,973 585,812 604,334 629,891
Operating Expenses:
Operation -
Electric production fuels. . . . . 114,051 123,866 131,054 129,792 134,719 134,437 127,055
Gas purchased for resale . . . . . 133,347 109,890 103,189 97,443 97,927 120,702 202,770
Purchased power . . . . . . . . . 30,703 29,594 32,886 27,145 31,125 24,887 4,597
Other. . . . . . . . . . . . . . . 148,270 135,614 128,820 117,494 109,765 101,935 78,859
Maintenance. . . . . . . . . . . . . 51,597 46,436 48,223 44,265 43,363 43,422 32,112
Depreciation . . . . . . . . . . . . 60,609 58,592 55,687 55,363 53,135 50,486 59,195
Taxes -
Federal income. . . . . . . . . . 27,654 23,147 21,961 20,775 20,972 26,605 24,851
Net investment credit . . . . . . (1,860) (2,022) (2,071) (2,298) (2,256) (2,826) 501
State income. . . . . . . . . . . 7,313 6,081 5,688 5,083 4,373 5,096 6,862
Gross receipts and other. . . . . 25,204 24,459 23,034 23,138 22,403 22,399 18,569
----------- ----------- ----------- ----------- ----------- ----------- -----------
596,888 555,657 548,471 518,200 515,526 527,143 555,371
----------- ----------- ----------- ----------- ----------- ----------- -----------
Operating Income. . . . . . . . . . . 83,744 79,145 75,028 70,773 70,286 77,191 74,520
Other Income and (Deductions):
AFUDC, other funds. . . . . . . . 287 494 113 451 595 659 --
Other, net. . . . . . . . . . . . 3,356 6,076 4,351 2,845 1,464 823 (665)
Income taxes. . . . . . . . . . . 568 (1,116) (478) (162) 556 697 535
Gains on bonds reacquired . . . . -- -- -- -- -- 221
----------- ----------- ----------- ----------- ----------- ----------- -----------
4,211 5,454 3,986 3,134 2,615 2,179 91
Income Before Interest
Expense. . . . . . . . . . . . . . 87,955 84,599 79,014 73,907 72,901 79,370 74,611
Interest Expense:
Interest on long-term debt . . . . 24,393 25,662 22,127 21,289 21,327 21,583 19,517
AFUDC, borrowed funds. . . . . . . (200) (542) (193) (306) (341) (363) (263)
Other interest . . . . . . . . . . 1,562 1,477 2,908 3,901 2,785 1,730 3,763
----------- ----------- ----------- ----------- ----------- ----------- -----------
25,755 26,597 24,842 24,884 23,771 22,950 23,017
----------- ----------- ----------- ----------- ----------- ----------- -----------
Net Income. . . . . . . . . . . . . . 62,200 58,002 54,172 49,023 49,130 56,420 51,594
Preferred Stock
Dividend Requirements . . . . . . . 3,311 3,237 3,237 3,293 3,436 3,594 5,974
----------- ----------- ----------- ----------- ----------- ----------- -----------
Earnings on Common Stock. . . . . . . $58,889 $54,765 $50,935 $45,730 $45,694 $52,826 $45,620
----------- ----------- ----------- ----------- ----------- ----------- -----------
Income Statistics
Common Stock:
Shares outstanding, Dec. 31 (1) . .23,896,962 23,846,144 22,888,620 22,888,620 22,888,620 23,200,552 23,644,412
Shares outstanding, Avg. (1). . . .23,888,047 23,350,039 22,888,620 22,888,620 23,086,474 23,200,552 23,454,062
Earnings per share (1)(2) . . . . . $2.47 $2.35 $2.23 $2.00 $1.98 $2.28 $1.95
Dividends paid per share (1). . . . $1.76 $1.72 $1.68 $1.64 $1.60 $1.56 $1.11
Year-end stock price (1). . . . . . 33-5/8 31-3/4 28-1/4 23-5/8 23-3/4 21-5/8 27-3/4
Times Interest Earned:
Before income taxes . . . . . . . . 4.49 3.99 4.00 3.74 3.85 4.49 5.32
After income taxes. . . . . . . . . 3.29 3.01 3.03 2.84 2.95 3.33 3.22
Times Interest and
Preferred Dividends Earned After
Income Taxes . . . . . . . . . . 2.93 2.71 2.70 2.53 2.60 2.90 2.56
(1) Adjusted to reflect 2 for 1 common stock split in June 1987.
(2) Based on weighted average shares outstanding.
-28-
STATISTICS - FINANCIAL
Balance Sheets (Thousands)
Assets
Utility Plant: 1993 1992 1991 1990 1989 1988 1983
------------- ------------- ------------- ------------- ------------- ------------- -----------
Electric. . . . . . . . . $1,386,007 $1,354,579 $1,277,913 $1,241,346 $1,199,700 $1,155,645 $963,787
Gas . . . . . . . . . . . 184,234 173,012 164,038 156,428 150,050 143,617 117,309
------------- ------------- ------------- ------------- ------------- ------------- -----------
1,570,241 1,527,591 1,441,951 1,397,774 1,349,750 1,299,262 1,081,096
Less - accumulated
depreciation . . . . . 801,056 748,427 695,586 648,398 600,965 548,950 445,823
------------ ------------- ------------- ------------- ------------- ------------- -----------
769,185 779,164 746,365 749,376 748,785 750,312 635,273
Nuclear decommissioning
trusts, at cost . . . . . 56,699 51,023 45,504 40,587 36,003 31,715 --
Nuclear fuel, net . . . . . 17,981 16,880 18,704 19,531 23,503 19,156 10,694
------------- ------------- ------------- ------------- ------------- ------------- -----------
Net utility plant . . . 843,865 847,067 810,573 809,494 808,291 801,183 645,967
Investments . . . . . . . . 16,161 16,569 17,835 20,889 16,147 17,689 10,290
Current assets. . . . . . . 180,140 160,331 165,393 148,303 167,435 138,254 131,776
Deferred charges and other
assets . . . . . . . . . 158,675 121,583 79,736 30,553 31,296 37,249 4,587
------------- ------------- ------------- ------------- ------------- ------------- -----------
Total assets. . . . . . $1,198,841 $1,145,550 $1,073,537 $1,009,239 $1,023,169 $994,375 $792,620
------------- ------------- ------------- ------------- ------------- ------------- -----------
Capitalization and Liabilities
Common stock and premium. . $169,193 $167,705 $141,266 $141,266 $141,266 $143,187 $145,909
Retained earnings . . . . . 265,310 245,521 228,032 230,866 231,859 227,981 154,184
Preferred stock with no
mandatory redemption. . . 51,200 51,200 51,200 51,200 51,200 51,200 51,200
Preferred stock with
mandatory redemption. . . -- -- -- -- 642 2,145 24,750
Long-term debt. . . . . . . 314,225 321,498 332,907 273,349 255,275 256,264 222,092
------------- ------------- ------------- ------------- ------------- ------------- -----------
Total capitalization. . . 799,928 785,924 753,405 696,681 680,242 680,777 598,135
Short-term borrowings . . . 21,000 20,000 13,000 35,000 36,000 21,500 39,500
Bond sinking fund requirements
and maturing first mortgage
bonds . . . . . . . . . . -- 8,726 235 235 -- -- 9,125
Deferred income taxes . . . 138,952 169,012 160,703 150,199 153,741 157,620 --
Other liabilities and credits 238,961 161,888 146,194 127,124 153,186 134,478 145,860
------------- ------------- ------------- ------------- ------------- ------------- -----------
Total capitalization
and liabilities. . . $1,198,841 $1,145,550 $1,073,537 $1,009,239 $1,023,169 $994,375 $792,620
------------- ------------- ------------- ------------- ------------- ------------- -----------
- ------------------------------------------------------------------------------------------------------------------------------
Book Value Per Share, Dec. 31
including ESOP (1). . . . $18.18 $17.33 $16.14 $16.26 $16.30 $16.00 $12.69
Book Value Per Share, Dec. 31
excluding ESOP (1). . . . . $19.16 $18.44 $17.42 $16.87 $16.52 $16.24 $12.69
Return on Average Equity. . . 13.1% 13.2% 13.1% 12.1% 12.1% 14.4% 15.9%
Capitalization Ratios
Common equity including ESOP. 54.3 52.6 49.0 53.4 54.9 54.5 50.2
Preferred stock . . . . . . . 6.4 6.5 6.8 7.4 7.6 7.8 12.7
Long-term debt. . . . . . . . 39.3 40.9 44.2 39.2 37.5 37.7 37.1
Percent Long-Term Debt
to Net Utility Plant. . . . . 37.2 38.0 41.1 33.8 31.6 32.0 34.4
Average Bond Rate . . . . . . . 7.1 7.8 8.2 8.0 8.1 8.1 7.2
Average Preferred Stock Rate. . 6.1 6.3 6.3 6.3 6.4 6.5 7.8
Shareholders -
Common stock. . . . . . . . 25,240 25,983 24,943 25,248 25,752 26,858 33,857
Preferred stock . . . . . . 3,577 4,167 4,332 4,538 4,821 5,164 6,885
Number of Employees, Dec. 31. . 2,603 2,631 2,619 2,500 2,472 2,466 2,267
(1) Adjusted to reflect 2 for 1 common stock split in June 1987.
-29-
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.
-30-
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.
-31-
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
-32-
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
-33-
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
-34-
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
-35-
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
-36-
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.
-37-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
STATEMENTS OF INCOME
Year Ended December 31
1993 1992 1991
------------- ------------ ----------
(Thousands)
Operating Revenues:
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 493,256 $ 477,625 $ 471,277
Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187,376 157,177 152,222
------------- ------------ ----------
680,632 634,802 623,499
------------- ------------ ----------
Operating Expenses:
Operation -
Electric production fuels. . . . . . . . . . . . . . . . . . 114,051 123,866 131,054
Gas purchased for resale . . . . . . . . . . . . . . . . . . 133,347 109,890 103,189
Purchased power. . . . . . . . . . . . . . . . . . . . . . . 30,703 29,594 32,886
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . 148,270 135,614 128,820
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . 51,597 46,436 48,223
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . 60,609 58,592 55,687
Taxes -
Federal income . . . . . . . . . . . . . . . . . . . . . . . 27,654 23,147 21,961
Investment credit restored . . . . . . . . . . . . . . . . . (1,860) (2,022) (2,071)
State income . . . . . . . . . . . . . . . . . . . . . . . . 7,313 6,081 5,688
Gross receipts and other . . . . . . . . . . . . . . . . . . 25,204 24,459 23,034
------------- ------------ ----------
596,888 555,657 548,471
------------- ------------ ----------
Operating Income . . . . . . . . . . . . . . . . . . . . . . . . 83,744 79,145 75,028
------------- ------------ ----------
Other Income and (Deductions):
Allowance for equity funds used during construction. . . . . 287 494 113
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . 3,356 6,076 4,351
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 568 (1,116) (478)
------------- ------------ ----------
4,211 5,454 3,986
------------- ------------ ----------
Income Before Interest Expense . . . . . . . . . . . . . . . . . 87,955 84,599 79,014
------------- ------------ ----------
Interest Expense:
Interest on long-term debt . . . . . . . . . . . . . . . . . 24,393 25,662 22,127
Allowance for borrowed funds used during construction. . . . (200) (542) (193)
Other interest . . . . . . . . . . . . . . . . . . . . . . . 1,562 1,477 2,908
------------- ------------ ----------
25,755 26,597 24,842
------------- ------------ ----------
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,200 58,002 54,172
Preferred Stock Dividend Requirements. . . . . . . . . . . . . . 3,311 3,237 3,237
------------- ------------ ----------
Earnings On Common Stock . . . . . . . . . . . . . . . . . . . . $ 58,889 $ 54,765 $ 50,935
------------- ------------ ----------
Average Number Of Shares Of Common Stock Outstanding (Thousands) 23,888 23,350 22,889
Earnings Per Average Share Of Common Stock . . . . . . . . . . . $2.47 $2.35 $2.23
Dividends Per Share On Common Stock. . . . . . . . . . . . . . . $1.76 $1.72 $1.68
The accompanying notes to financial statements are an integral part of these statements.
-38-
BALANCE SHEETS
December 31
1993 1992 1991
----------- ------------ ----------
Assets (Thousands)
Utility Plant:
In service - Electric. . . . . . . . . . . . . . . . . . . . . . . $ 1,374,662 $ 1,327,964 $ 1,269,979
Gas . . . . . . . . . . . . . . . . . . . . . . . . . 183,798 172,763 163,901
----------- ------------ ----------
1,558,460 1,500,727 1,433,880
Less - Accumulated provision for depreciation. . . . . . . . . . 801,056 748,427 695,586
----------- ------------ ----------
757,404 752,300 738,294
Nuclear decommissioning trusts . . . . . . . . . . . . . . . . . . 56,699 51,023 45,504
Construction in progress . . . . . . . . . . . . . . . . . . . . . 11,781 26,864 8,071
Nuclear fuel, less accumulated provision for amortization of
$130,011, $124,394, and $117,792, respectively . . . . . . . . . 17,981 16,880 18,704
----------- ------------ ----------
Net utility plant . . . . . . . . . . . . . . . . . . . . . . . 843,865 847,067 810,573
----------- ------------ ----------
Current Assets:
Cash and equivalents . . . . . . . . . . . . . . . . . . . . . . . 5,391 178 477
Customer and other receivables, net of reserves. . . . . . . . . . 66,511 62,573 65,673
Accrued utility revenues . . . . . . . . . . . . . . . . . . . . . 37,314 33,880 29,545
Fossil fuel, at average cost . . . . . . . . . . . . . . . . . . . 10,208 12,907 25,502
Gas in storage, at average cost. . . . . . . . . . . . . . . . . . 19,885 11,622 1,815
Materials and supplies, at average cost. . . . . . . . . . . . . . 19,411 18,722 19,260
Prepayments and other. . . . . . . . . . . . . . . . . . . . . . . 21,420 20,449 23,121
----------- ------------ ----------
Total current assets . . . . . . . . . . . . . . . . . . . . . 180,140 160,331 165,393
----------- ------------ ----------
Deferred Charges . . . . . . . . . . . . . . . . . . . . . . . . . . 118,128 106,390 63,360
Investments and Other Assets . . . . . . . . . . . . . . . . . . . . 56,708 31,762 34,211
----------- ------------ ----------
$ 1,198,841 $ 1,145,550 $ 1,073,537
----------- ------------ ----------
Capitalization and Liabilities
Capitalization:
Common stock equity. . . . . . . . . . . . . . . . . . . . . . . . $ 434,503 $ 413,226 $ 369,298
Preferred stock with no mandatory redemption . . . . . . . . . . . 51,200 51,200 51,200
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . 314,225 321,498 332,907
----------- ------------ ----------
Total capitalization . . . . . . . . . . . . . . . . . . . . . 799,928 785,924 753,405
----------- ------------ ----------
Current Liabilities:
Note payable . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,000 10,000 10,000
Commercial paper . . . . . . . . . . . . . . . . . . . . . . . . . 11,000 10,000 3,000
Maturing first mortgage bonds. . . . . . . . . . . . . . . . . . . -- 8,726 235
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . 64,113 55,300 62,898
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . 3,266 1,234 1,258
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . 7,695 7,204 6,729
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,956 10,207 12,275
----------- ------------ ----------
Total current liabilities. . . . . . . . . . . . . . . . . . . 106,030 102,671 96,395
----------- ------------ ----------
Other Long-Term Liabilities and Deferred Credits:
Accumulated deferred income taxes. . . . . . . . . . . . . . . . . 138,952 169,012 160,703
Accumulated deferred investment credits. . . . . . . . . . . . . . 34,210 36,071 38,093
Regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . 61,434 6,393 926
Long-term liabilities. . . . . . . . . . . . . . . . . . . . . . . 58,287 45,479 24,015
----------- ------------ ----------
292,883 256,955 223,737
----------- ------------ ----------
Commitments and Contingencies (See Note 6)
----------- ------------ ----------
$ 1,198,841 $ 1,145,550 $ 1,073,537
----------- ------------ ----------
The accompanying notes to financial statements are an integral part of these balance sheets.
-39-
STATEMENTS OF CAPITALIZATION
December 31
1993 1992 1991
---------- ----------- ---------
(Thousands)
COMMON STOCK EQUITY:
Common stock, $4 par value, 32,000,000 shares authorized;
23,896,962, 23,846,144 and 22,888,620 shares outstanding, respectively. $ 95,588 $ 95,385 $ 91,555
Premium on capital stock . . . . . . . . . . . . . . . . . . . . . . . . 73,605 72,320 49,711
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . 288,693 272,019 257,404
ESOP loan guarantees . . . . . . . . . . . . . . . . . . . . . . . . . . (23,383) (26,498) (29,372)
---------- ----------- ---------
Total common stock equity. . . . . . . . . . . . . . . . . . . . . . 434,503 413,226 369,298
---------- ----------- ---------
PREFERRED STOCK:
Cumulative, $100 par value, 1,000,000 shares authorized:
With no mandatory redemption -
Series Shares Outstanding
5.00% 132,000. . . . . . . . . . . . . . . . . 13,200 13,200 13,200
5.04% 30,000. . . . . . . . . . . . . . . . . 3,000 3,000 3,000
5.08% 50,000. . . . . . . . . . . . . . . . . 5,000 5,000 5,000
6.76% 150,000. . . . . . . . . . . . . . . . . 15,000 15,000 15,000
6.88% 150,000. . . . . . . . . . . . . . . . . 15,000 -- --
7.72% 150,000. . . . . . . . . . . . . . . . . -- 15,000 15,000
---------- ----------- ---------
Total preferred stock. . . . . . . . . . . . . . . . . . . . . . . . 51,200 51,200 51,200
---------- ----------- ---------
LONG-TERM DEBT:
First mortgage bonds -
Series Year Due
4-3/8% 1993. . . . . . . . . . . . . . . . . . . -- -- 8,726
4-1/2% 1994. . . . . . . . . . . . . . . . . . . -- 10,944 10,944
9.50% 1994. . . . . . . . . . . . . . . . . . . -- -- 45,000
6-3/8% 1997. . . . . . . . . . . . . . . . . . . -- 23,482 23,482
5-1/4% 1998. . . . . . . . . . . . . . . . . . . 50,000 -- --
7-1/4% 1999. . . . . . . . . . . . . . . . . . . -- 24,039 24,039
8-1/4% 2001. . . . . . . . . . . . . . . . . . . -- 25,000 25,000
7.30% 2002. . . . . . . . . . . . . . . . . . . 50,000 50,000 --
8-1/8% 2003. . . . . . . . . . . . . . . . . . . -- 25,000 25,000
6.80% 2003. . . . . . . . . . . . . . . . . . . 50,000 -- --
7-7/8% 2005. . . . . . . . . . . . . . . . . . . -- -- 10,530
6-1/8% 2005. . . . . . . . . . . . . . . . . . . 9,075 9,075 --
8.20% 2012. . . . . . . . . . . . . . . . . . . -- 45,000 45,000
6.90% 2013. . . . . . . . . . . . . . . . . . . 22,000 -- --
9.70% 2014. . . . . . . . . . . . . . . . . . . -- 22,000 22,000
10-1/8% 2014. . . . . . . . . . . . . . . . . . . 1,000 1,000 1,000
8.80% 2021. . . . . . . . . . . . . . . . . . . 60,000 60,000 60,000
7-1/8% 2023. . . . . . . . . . . . . . . . . . . 50,000 -- --
---------- ----------- ---------
292,075 295,540 300,721
Unamortized discount and premium on bonds, net . . . . . . . . . . . . . (1,257) (1,037) (1,193)
---------- ----------- ---------
Total first mortgage bonds . . . . . . . . . . . . . . . . . . . . . . . 290,818 294,503 299,528
ESOP loan guarantees . . . . . . . . . . . . . . . . . . . . . . . . . . 23,383 26,498 29,372
Other long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . 24 497 4,007
---------- ----------- ---------
Total long-term debt . . . . . . . . . . . . . . . . . . . . . . . . 314,225 321,498 332,907
---------- ----------- ---------
Total capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 799,928 $ 785,924 $ 753,405
---------- ----------- ---------
The accompanying notes to financial statements are an integral part of these statements.
-40-
STATEMENTS OF CASH FLOWS
Year Ended December 31
1993 1992 1991
--------- --------- ---------
(Thousands)
Cash Flows From Operating Activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 62,200 $ 58,002 $ 54,172
Adjustments to reconcile net income to net cash from
operating activities -
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . 60,609 58,592 55,687
Amortization of nuclear fuel and other . . . . . . . . . . . . . 27,693 20,522 17,915
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . (867) 7,266 10,659
Investment credit restored . . . . . . . . . . . . . . . . . . . (1,860) (2,022) (2,071)
AFUDC equity . . . . . . . . . . . . . . . . . . . . . . . . . . (287) (494) (113)
Pension (income) . . . . . . . . . . . . . . . . . . . . . . . . (9,830) -- --
Post retirement liability. . . . . . . . . . . . . . . . . . . . 5,915 -- --
Deferred demand-side management expenditures . . . . . . . . . . (18,988) (32,073) (9,901)
Coal and rail contract settlements . . . . . . . . . . . . . . . -- -- (28,290)
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,644 (3,601) 2,679
Changes in -
Customer and other receivables . . . . . . . . . . . . . . . . (3,938) 3,100 (8,101)
Accrued utility revenues . . . . . . . . . . . . . . . . . . . (3,434) (4,335) (1,143)
Fossil fuel. . . . . . . . . . . . . . . . . . . . . . . . . . (5,565) 2,788 (4,913)
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . 8,813 (6,886) 7,989
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . . 2,032 3,425 (3,897)
--------- --------- ---------
Net cash from operating activities . . . . . . . . . . . . . . 137,137 104,284 90,672
--------- --------- ---------
Cash Flows From (Used For) Investing Activities:
Construction and nuclear fuel expenditures, including AFUDC debt (68,654) (95,211) (64,887)
Decommissioning funding. . . . . . . . . . . . . . . . . . . . . (5,676) (5,518) (4,917)
Sale of interest in combustion turbine . . . . . . . . . . . . . 7,849 -- --
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,786) 2,784 (902)
--------- --------- ---------
Net cash from (used for) investing activities. . . . . . . . . (71,267) (97,945) (70,706)
--------- --------- ---------
Cash Flows From (Used For) Financing Activities:
Proceeds from issuance of common stock . . . . . . . . . . . . . 1,693 26,439 --
Proceeds from issuance of preferred stock. . . . . . . . . . . . 15,000 -- --
Redemption of preferred stock. . . . . . . . . . . . . . . . . . (15,000) -- --
Sale of first mortgage bonds . . . . . . . . . . . . . . . . . . 172,000 59,075 60,000
Redemption and maturities of first mortgage bonds. . . . . . . . (189,973) (55,765) (960)
Change in other long-term debt . . . . . . . . . . . . . . . . . -- -- (15,000)
Change in commercial paper . . . . . . . . . . . . . . . . . . . 1,000 7,000 (22,000)
Preferred stock dividends. . . . . . . . . . . . . . . . . . . . (3,332) (3,237) (3,237)
Common stock dividends . . . . . . . . . . . . . . . . . . . . . (42,045) (40,150) (38,453)
--------- --------- ---------
Net cash from (used for) financing activities. . . . . . . . . (60,657) (6,638) (19,650)
--------- --------- ---------
Net Increase (Decrease) in Cash and Equivalents. . . . . . . . . . . 5,213 (299) 316
Cash and Equivalents at Beginning of Year. . . . . . . . . . . . . . 178 477 161
--------- --------- ---------
Cash and Equivalents at End of Year. . . . . . . . . . . . . . . . . $ 5,391 $ 178 $ 477
--------- --------- ---------
Cash Paid During Year For:
Interest, less amount capitalized. . . . . . . . . . . . . . . . . $21,973 $22,678 $21,001
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . $33,177 $18,301 $21,977
Construction and nuclear fuel expenditures, including
accruals, AFUDC and customer contributions . . . . . . . . . . . . $72,731 $102,281 $64,536
The accompanying notes to financial statements are an integral part of these statements.
-41-
STATEMENTS OF RETAINED EARNINGS
Year Ended December 31
1993 1992 1991
--------- --------- -----------
(Thousands)
Balance at Beginning of Year . . . . . . . . . . . . . . . . . . . . . . . $ 272,019 $ 257,404 $ 244,922
Add - Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,200 58,002 54,172
--------- --------- -----------
334,219 315,406 299,094
--------- --------- -----------
Deduct -
Cash dividends declared on preferred stock-
5.00% Series ($5.00 per share) . . . . . . . . . . . . . . . . . . . . 660 660 660
5.04% Series ($5.04 per share) . . . . . . . . . . . . . . . . . . . . 151 151 151
5.08% Series ($5.08 per share) . . . . . . . . . . . . . . . . . . . . 254 254 254
6.76% Series ($6.76 per share) . . . . . . . . . . . . . . . . . . . . 1,014 1,014 1,014
6.88% Series ($6.88 per share) . . . . . . . . . . . . . . . . . . . . 384 -- --
7.72% Series ($7.72 per share) . . . . . . . . . . . . . . . . . . . . 868 1,158 1,158
Cash dividends declared on common stock. . . . . . . . . . . . . . . . . 42,045 40,150 38,453
Loss on repurchase of preferred stock. . . . . . . . . . . . . . . . . . 150 -- --
--------- --------- -----------
45,526 43,387 41,690
--------- --------- -----------
Balance at End of Year . . . . . . . . . . . . . . . . . . . . . . . . . . $ 288,693 $ 272,019 $ 257,404
--------- --------- -----------
The accompanying notes to financial statements are an integral part of these statements.
-42-
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%.
-43-
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
-44-
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.
-45-
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.
-46-
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
-47-
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).
As of December 31
-------------------------------
1993 1992 1991
---- ---- ----
(Thousands)
Vested benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . $ 162,304 $ 152,581 $ 129,943
Non-vested benefit obligation . . . . . . . . . . . . . . . . . . . . . . 8,084 7,420 6,316
-------- -------- --------
Total actuarial present value of accumulated benefit obligation . . . . . $ 170,388 $ 160,001 $ 136,259
======== ======== ========
Projected benefit obligation for service rendered to date . . . . . . . . $(235,661) $(221,085) $(181,750)
Plan assets at fair value . . . . . . . . . . . . . . . . . . . . . . . . 342,540 314,613 304,672
-------- --------- --------
Plan assets in excess of projected benefit obligation . . . . . . . . . . 106,879 93,528 122,922
Unrecognized net gain . . . . . . . . . . . . . . . . . . . . . . . . . . (59,024) (47,337) (73,381)
Prior service cost not yet recognized . . . . . . . . . . . . . . . . . . 7,044 7,668 8,292
Unrecognized net asset being recognized over 17 years . . . . . . . . . . (30,384) (33,849) (37,313)
-------- -------- --------
Prepaid retirement plan cost . . . . . . . . . . . . . . . . . . . . . . $ 24,515 $ 20,010 $ 20,520
======== ======== ========
The net retirement plan expense (income) includes the following components:
Service cost - benefits earned during the year. . . . . . . . . . . . . . $ 5,935 $ 4,251 $ 4,122
Interest cost on projected benefit obligation . . . . . . . . . . . . . . 16,375 15,003 14,247
Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . (37,856) (25,826) (61,912)
Net amortization and deferral . . . . . . . . . . . . . . . . . . . . . . 11,042 463 38,471
Regulatory adjustment to funded amount . . . . . . . . . . . . . . . . . (5,326) 6,109 5,072
-------- -------- --------
Net retirement plan expense (income). . . . . . . . . . . . . . . . . . . $ (9,830) $ -- $ --
======== ======== ========
The assumed rates for calculations used
in the above tables were:
1993 1992 1991
---- ---- ----
Expected long-term return on investments 9.00% 9.00% 9.00%
Average rate for future salary increases 6.25% 6.25% 6.25%
Discount rate to compute projected benefit obligation 7.50% 7.50% 8.50%
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
-48-
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.
1993
----
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).
-49-
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.
-50-
1993 1992 1991
---- ---- ----
(Thousands except for percentages)
Amount Rate Amount Rate Amount Rate
------ ---- ------ ---- ------ ----
Statutory federal income tax . . . . . . . $33,159 35.0% $29,350 34.0% $27,277 34.0%
State income taxes, net . . . . . . . . . 4,636 4.9 4,518 5.2 4,546 5.7
Investment credit restored . . . . . . . . (1,860) (2.0) (2,022) (2.3) (2,066) (2.6)
Rate difference on deferred income tax
reversals. . . . . . . . . . . . . . . . (1,441) (1.5) (1,843) (2.1) (1,903) (2.4)
Regulatory effects of dividends paid to
ESOP . . . . . . . . . . . . . . . . . . (1,434) (1.5) (1,381) (1.6) (1,375) (1.7)
Other differences, net . . . . . . . . . . (521) (.5) (300) (.4) (423) (.5)
------ ---- ------ ---- ------ ----
Effective income tax $32,539 34.4% $28,322 32.8% $26,056 32.5%
====== ==== ====== ==== ====== ====
The current and deferred components of income tax expense are as follows:
1993 1992 1991
---- ---- ----
Current provision:
Federal. . . . . . . . . . . . . . . . . . . . . . . $ 28,212 $ 18,284 $ 13,783
State. . . . . . . . . . . . . . . . . . . . . . . . 7,054 4,794 3,685
-------------- ------------ -----------
Total current 35,266 23,078 17,468
-------------- ------------ -----------
Deferred provision (benefit):
DSM expenditures, net . . . . . . . . . . . . . . . 3,070 11,921 1,433
Pension . . . . . . . . . . . . . . . . . . . . . . 3,810 - -
Other post retirement benefits . . . . . . . . . . . (2,201) - -
Coal and rail contract buyout costs, net . . . . . . (2,864) (1,234) 10,996
Depreciation differences . . . . . . . . . . . . . . (1,942) (927) (1,239)
Other, net . . . . . . . . . . . . . . . . . . . . . (740) (2,494) (531)
-------------- ------------ -----------
Total deferred (867) 7,266 10,659
Investment credit restored, net . . . . . . . . . . . (1,860) (2,022) (2,071)
-------------- ------------ -----------
Total income tax expense $ 32,539 $ 28,322 $ 26,056
============== ============ ===========
Classification of income taxes:
Operating expenses . . . . . . . . . . . . . . . . . $ 33,107 $ 27,206 $ 25,578
Other income and deductions . . . . . . . . . . . . (568) 1,116 478
-------------- ------------ -----------
Total income tax expense $ 32,539 $ 28,322 $ 26,056
============== ============ ===========
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.
-51-
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.
-52-
(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.
-53-
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
-54-
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
-55-
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.
-56-
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.
-57-
(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.
1993 1992 1991
---------------------------- ----------------------------- -----------------------------
(Thousands)
Electric Gas Total Electric Gas Total Electric Gas Total
-------- ------- -------- -------- -------- --------- -------- -------- ---------
Operating revenues. $493,256 $187,376 $ 680,632 $ 477,625 $ 157,177 $ 634,802 $ 471,277 $ 152,222 $ 623,499
Operating expenses -
Operation and
maintenance . . 310,535 167,434 477,969 304,347 141,052 445,399 311,028 133,145 444,173
Depreciation. . . 54,498 6,111 60,609 52,819 5,773 58,592 49,683 6,004 55,687
Other taxes . . . 22,064 3,140 25,204 21,687 2,772 24,459 20,516 2,518 23,034
------- ------- -------- -------- -------- --------- -------- ------- --------
387,097 176,685 563,782 378,853 149,597 528,450 381,227 141,667 522,894
Operating income
before income
taxes . . . . . . 106,159 10,691 116,850 98,772 7,580 106,352 90,050 10,555 100,605
AFUDC . . . . . . . 445 43 488 1,014 21 1,035 286 20 306
Provisions for income
tax . . . . . . . 30,599 2,508 33,107 25,746 1,460 27,206 23,143 2,434 25,577
------- ------- -------- -------- -------- --------- -------- ------- --------
Operating income
including AFUDC . $ 76,005 $ 8,226 84,231 $ 74,040 $ 6,141 80,181 $ 67,193 $ 8,141 75,334
======= ======= ======== ======== ======= =======
Other income, net . 3,924 4,960 3,873
Interest expense. . 25,955 27,139 25,035
-------- --------- ---------
Net income. . . . . $ 62,200 $ 58,002 $ 54,172
======== ========= =========
Identifiable assets(a) $938,951 $184,880 $1,123,831 $ 951,074 $ 158,314 $1,109,388 $904,908 $129,483 $1,034,391
======= ======= ======== ======== ======= =======
Assets not allocated(b) 75,010 36,162 39,146
--------- --------- ---------
Total assets. . . $1,198,841 $1,145,550 $1,073,537
========= ========= =========
Construction and nuclear
fuel expenditures
including AFUDC . $ 59,038 $ 13,693 $ 72,731 $ 91,272 $ 11,009 $ 102,281 $ 55,850 $ 8,686 $ 64,536
======= ======= ========= ======== ======== ========= ======= ======= =========
- ---------------
(a) At December 31 and net of the respective accumulated provisions for depreciation.
(b) Primarily includes cash, investments, pension assets, nonutility property and other receivables.
-58-
(8) QUARTERLY FINANCIAL INFORMATION (Unaudited):
Three Months Ended
--------------------------------------------------------
(Thousands except for per share data)
1993
----
March June September December(1) Total
----- ---- --------- ----------- -----
Operating revenues $189,003 $157,692 $156,310 $177,627 $680,632
Operating income $25,543 $16,946 $22,293 $ 18,962 $ 83,744
Net income $20,980 $11,731 $16,548 $ 12,941 $ 62,200
Earnings on common stock $20,171 $10,883 $15,673 $ 12,162 $ 58,889
Average number of shares of common stock outstanding 23,861 23,897 23,897 23,897 23,888
Earnings per average share of common stock $.85 $.45 $.66 $.51 $2.47
1992
----
March June September December(1) Total
----- ---- --------- ----------- -----
Operating revenues $175,966 $144,396 $141,289 $173,151 $634,802
Operating income $ 23,460 $ 12,922 $ 17,407 $ 25,356 $ 79,145
Net income $ 18,453 $ 7,714 $ 12,591 $ 19,244 $ 58,002
Earnings on common stock $ 17,644 $ 6,905 $ 11,782 $ 18,434 $ 54,765
Average number of shares of common stock outstanding 22,889 22,946 23,748 23,808 23,350
Earnings per average share of common stock $.77 $.30 $.50 $.78 $2.35
1991
----
March June September December Total
----- ---- --------- -------- -----
Operating revenues $181,342 $137,430 $139,835 $164,892 $623,499
Operating income $ 21,599 $ 11,560 $ 21,581 $ 20,288 $ 75,028
Net income $ 16,331 $ 6,745 $ 15,996 $ 15,100 $ 54,172
Earnings on common stock $ 15,522 $ 5,936 $ 15,187 $ 14,290 $ 50,935
Average number of shares of common stock outstanding 22,889 22,889 22,889 22,889 22,889
Earnings per average share of common stock $.68 $.26 $.66 $.63 $2.23
- ------------
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.
-59-
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.
-60-
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 above:
DESCRIPTION PAGES IN 10-K
Statements of Income for the three years
ended December 31, 1993, 1992 and 1991 38
Balance Sheets as of December 31, 1993,
1992 and 1991 39
Statements of Capitalization as of
December 31, 1993, 1992 and 1991 40
Statements of Cash Flows for the three
years ended December 31, 1993, 1992 and 1991 41
Statements of Retained Earnings for the three
years ended December 31, 1993, 1992 and 1991 42
Notes to Financial Statements 43 - 59
Report of Independent Public Accountants 60
-61-
(2) Financial statement schedules.
The following financial statement schedules
included in Part IV of this report should be read in conjunction
with the financial statements in Part II, Item 8, above.
Schedules not included herein have been omitted because they are
not applicable or the required information is shown in the
financial statements or notes thereto.
DESCRIPTION PAGES IN 10-K
Schedule V -
Utility Plant for the years ended
December 31, 1993, 1992 and 1991 68 - 70
Schedule VI -
Accumulated Provision for Depreciation of
Utility Plant and Amortization of Nuclear
Fuel for the years ended December 31, 1993,
1992 and 1991 71 - 73
Schedule X -
Supplementary Income Statement Information
for the years ended December 31, 1993,
1992 and 1991 74
(3) All exhibits, including those incorporated by
reference.
-62-
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENTS
3A Articles of Incorporation as effective May 26, 1972 and
amended through May 31, 1988 (Incorporated by reference
to Exhibit 3A to Form 10-K for the year ended December
31, 1991); Articles of Amendment to Articles of
Incorporation dated June 9, 1993 (Incorporated by
reference to Exhibit 3 to Form 8-K filed June 10, 1993).
3B By-Laws in effect February 14, 1991 (Incorporated by
reference to Exhibit 3B to Form 10-K for the year ended
December 31, 1991).
4A Copy of First Mortgage and Deed of Trust, dated as of
January 1, 1941 to First Wisconsin Trust Company, Trustee
(Incorporated by reference to Exhibit 7.01 - File No.
2-7229); Supplemental Indenture, dated as of November 1,
1947 (Incorporated by reference to Exhibit 7.02 - File
No. 2-7602); Supplemental Indenture, dated as of November
1, 1950 (Incorporated by reference to Exhibit 4.04 - File
No. 2-10174); Supplemental Indenture, dated as of May 1,
1953 (Incorporated by reference to Exhibit 4.03 - File
No. 2-10716); Supplemental Indenture, dated as of October
1, 1954 (Incorporated by reference to Exhibit 4.03 - File
No. 2-13572); Supplemental Indenture, dated as of
December 1, 1957 (Incorporated by reference to Exhibit
4.03 - File No. 2-14527); Supplemental Indenture, dated
as of October 1, 1963 (Incorporated by reference to
Exhibit 2.02B - File No. 2-65710); Supplemental
Indenture, dated as of June 1, 1964 (Incorporated by
reference to Exhibit 2.02B - File No. 2-65710);
Supplemental Indenture, dated as of November 1, 1967
(Incorporated by reference to Exhibit 2.02B - File No.
2-65710); Supplemental Indenture, dated as of April 1,
1969 (Incorporated by reference to Exhibit 2.02B - File
No. 2-65710); Fifteenth Supplemental Indenture, dated as
of May 1, 1971 (Incorporated by reference to Exhibit
2.02B - File No. 2-65710); Sixteenth Supplemental
Indenture, dated as of August 1, 1973 (Incorporated by
reference to Exhibit 2.02B - File No. 2-65710);
Seventeenth Supplemental Indenture, dated as of September
1, 1973 (Incorporated by reference to Exhibit 2.02B -
File No. 2-65710); Eighteenth Supplemental Indenture,
dated as of October 1, 1975 (Incorporated by reference to
Exhibit 2.02B - File No. 2-65710); Nineteenth
Supplemental Indenture, dated as of February 1, 1977
(Incorporated by reference to Exhibit 2.02B - File No.
2-65710); Twentieth Supplemental Indenture, dated as of
July 15, 1980 (Incorporated by reference to Exhibit 4B to
Form 10-K for the year ended December 31, 1980);
Twenty-First Supplemental Indenture, dated as of December
-63-
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENTS
1, 1980 (Incorporated by reference to Exhibit 4B to Form
10-K for the year ended December 31, 1980); Twenty-Second
Supplemental Indenture dated as of April 1, 1981
(Incorporated by reference to Exhibit 4B to Form 10-K for
the year ended December 31, 1981); Twenty-Third
Supplemental Indenture, dated as of February 1, 1984
(Incorporated by reference to Exhibit 4B to Form 10-K for
the year ended December 31, 1983); Twenty-Fourth
Supplemental Indenture, dated as of March 15, 1984
(Incorporated by reference to Exhibit 1 to Form 10-Q for
the quarter ended June 30, 1984); Twenty-Fifth
Supplemental Indenture, dated as of October 1, 1985
(Incorporated by reference to Exhibit 1 to Form 10-Q for
the quarter ended September 30, 1985); Twenty-Sixth
Supplemental Indenture, dated as of December 1, 1987
(Incorporated by reference to Exhibit 4A-1 to Form 10-K
for the year ended December 31, 1987); Twenty-Seventh
Supplemental Indenture, dated as of September 1, 1991
(Incorporated by reference to Exhibit 4 to Form 8-K filed
September 18, 1991); Twenty-Eighth Supplemental
Indenture, dated as of July 1, 1992 (Incorporated by
reference to Exhibit 4B - File No. 33-51428); Twenty-
Ninth Supplemental Indenture, dated as of October 1, 1992
(Incorporated by reference to Exhibit 4 to Form 8-K filed
October 22, 1992); Thirtieth Supplemental Indenture,
dated as of February 1, 1993 (Incorporated by reference
to Exhibit 4 to Form 8-K filed January 27, 1993); Thirty-
First Supplemental Indenture, dated as of July 1, 1993
(Incorporated by reference to Exhibit 4 to Form 8-K filed
July 7, 1993); Thirty-Second Supplemental Indenture,
dated as of November 1, 1993 (Incorporated by reference
to Exhibit 4 to Form 10-Q for the quarter ended September
30, 1993).
10A Copy of Joint Power Supply Agreement with Wisconsin Power
and Light Company and Madison Gas and Electric Company,
dated February 2, 1967 (Incorporated by reference to
Exhibit 4.09 in File No. 2-27308).
10B Copy of Joint Power Supply Agreement (Exclusive of
Exhibits) with Wisconsin Power and Light Company and
Madison Gas and Electric Company dated July 26, 1973
(Incorporated by reference to Exhibit 5.04A in File No.
2-48781).
10C Copy of Basic Generating Agreement, Unit 4, Edgewater
Generating Station, dated June 5, 1967, between Wisconsin
Power and Light Company and Wisconsin Public Service
-64-
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENTS
Corporation (Incorporated by reference to Exhibit 4.10 in
File No. 2-27308).
10C-1 Copy of Agreement for Construction and Operation of
Edgewater 5 Generating Unit, dated February 24, 1983,
between Wisconsin Power and Light Company, Wisconsin
Electric Power Company and Wisconsin Public Service
Corporation (Incorporated by reference to Exhibit 10C-1
to Form 10-K for the year ended December 31, 1983).
10C-2 Amendment No. 1 to Agreement for Construction and
Operation of Edgewater 5 Generating Unit, dated December
1, 1988 (Incorporated by reference to Exhibit 10C-2 to
Form 10-K for the year ended December 31, 1988).
10D Copy of revised Agreement for Construction and Operation
of Columbia Generating Plant with Wisconsin Power and
Light Company and Madison Gas and Electric Company, dated
July 26, 1973 (Incorporated by reference to Exhibit 5.07
in File No. 2-48781).
10E Copy of Guaranty and Agreements and Note Agreements for
Wisconsin Public Service Corporation Employee Stock
Ownership Plan and Trust (ESOP) dated November 1, 1990
(Incorporated by reference to Exhibits 10.1 and 10.2 to
Form 8-K filed November 2, 1990).
Executive Compensation Plans and Arrangements
10F-1 Copy of Form of Deferred Compensation Agreement (Plan
008) with certain executive officers of the registrant.
(Incorporated by reference to Exhibit 10F-1 to Form 8,
amending Form 10-K for the year ended December 31, 1992).
10F-2 Copy of Form of Supplemental Benefits and Deferred
Compensation Agreement (Plan 009) with certain executive
officers including the named executive officers of the
registrant, as defined by item 402(a)(3) of Regulation S-
K. (Incorporated by reference to Exhibit 10F-2 to Form
8, amending Form 10-K for the year ended December 31,
1992).
10F-3 Copy of Form of Deferred Compensation Agreement (Plan
010) with certain executive officers of the registrant.
(Incorporated by reference to Exhibit 10F-3 to Form 8,
amending Form 10-K for the year ended December 31, 1992).
10F-4 Copy of Form of Director Deferred Compensation Agreement
(Plan 011) with certain non-employee directors.
-65-
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENTS
(Incorporated by reference to Exhibit 10F-4 to Form 8,
amending Form 10-K for the year ended December 31, 1992).
11A Statement re computation of per share earnings (Not
applicable).
12 Statement re computation of ratios (Not applicable).
13 Annual report to security holders (Not applicable).
18 Letter re change in accounting principles (Not
applicable).
19 Previously unfiled documents (None).
22 Subsidiaries of the Registrant.
24.1 Consent of Independent Public Accountants.
25 Powers of Attorney.
-66-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
WISCONSIN PUBLIC SERVICE CORPORATION
(Registrant)
By /s/D. A. Bollom
----------------------------------
D. A. Bollom
President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
- ------------------------------------------------------------------------------
A. Dean Arganbright Director February 8, 1994
Michael S. Ariens Director
Richard A. Bemis Director
M. Lois Bush Director
Robert C. Gallagher Director By /s/D. A. Bollom
Kathryn M. Hasselblad-Pascale Director --------------------------------
James L. Kemerling Director D. A. Bollom
Linus M. Stoll Director Attorney-in-Fact
/s/ D. A. Bollom Principal Executive February 8, 1994
- ----------------------------------Officer and Director
D. A. Bollom
/s/ D. P. Bittner Principal Financial February 8, 1994
- ----------------------------------Officer
D. P. Bittner
/s/ D. L. Ford Principal Accounting February 8, 1994
- ----------------------------------Officer
D. L. Ford
-67-
Schedule V
WISCONSIN PUBLIC SERVICE CORPORATION
Utility Plant
December 31, 1993
Column A Column B Column C Column D Column E Column F
-------- ---------- --------- ----------- -------- --------
Other
Balance at Retirements Changes Balance
Beginning Additions or Sales Debit at End
Classification of Period at Cost at Cost (Credit) of Period
-------------- ---------- --------- ----------- -------- ---------
(thousands)
Utility Plant -
Intangible Electric
Electric
Steam Production $ 529,930 $ 9,544 $ 3,899 $ (37) $ 535,538
Nuclear 127,069 1,828 634 (26) 128,237
Hydraulic 25,737 271 35 (4) 25,969
Other Production 14,079 24,204 7,550 -- 30,733
Transmission 117,838 1,813 252 (183) 119,216
Distribution 402,874 21,429 2,783 87 421,607
General 23,347 1,369 676 (10) 24,030
Common 86,920 4,534 2,553 261 89,162
Plant Held for
Future Use 170 -- -- -- 170
--------- -------- ------- -------- ---------
Total Electric 1,327,964 64,992 18,382 88 1,374,662
Gas
Production 476 -- -- -- 476
Distribution 150,241 11,547 902 (11) 160,875
General 2,628 201 24 2 2,807
Common 19,418 997 561 (214) 19,640
Plant Held for
Future Use -- -- -- -- --
--------- -------- ------- -------- ---------
Total Gas 172,763 12,745 1,487 (223) 183,798
Nuclear Decommissioning
Trusts 51,023 6,195 312 (207) 56,699
Construction
in Progress -
Electric 26,615 -- -- (15,269) 11,346
Gas 249 186 -- -- 435
--------- -------- ------- -------- ---------
Total Construction
in Progress 26,864 186 -- (15,269) 11,781
Nuclear Fuel 141,274 6,718 -- -- 147,992
--------- -------- ------- -------- ---------
Total Utility Plant $1,719,888 $ 90,836 $ 20,181 $(15,611) $1,774,932
========= ======== ======= ======== =========
-68-
Schedule V
WISCONSIN PUBLIC SERVICE CORPORATION
Utility Plant
December 31, 1992
Column A Column B Column C Column D Column E Column F
-------- ---------- --------- ----------- -------- ---------
Other
Balance at Retirements Changes Balance
Beginning Additions or Sales Debit at End
Classification of Period at Cost at Cost (Credit) of Period
-------------- ---------- --------- ----------- ------- ---------
(thousands)
Utility Plant -
Intangible Electric
Electric
Steam Production $ 503,131 $ 27,776 $ 946 $ (31) $ 529,930
Nuclear 123,771 3,975 677 -- 127,069
Hydraulic 24,912 861 42 6 25,737
Other Production 14,059 20 1 1 14,079
Transmission 128,574 2,283 598 (12,421) 117,838
Distribution 369,569 24,297 3,334 12,342 402,874
General 22,436 1,088 245 68 23,347
Common 83,357 4,888 1,583 258 86,920
Plant Held for
Future Use 170 -- -- -- 170
---------- -------- -------- -------- --------
Total Electric 1,269,979 65,188 7,426 223 1,327,964
Gas
Production 476 -- -- -- 476
Distribution 142,016 8,933 705 (3) 150,241
General 2,487 211 70 -- 2,628
Common 18,922 1,091 353 (242) 19,418
Plant Held for
Future Use -- -- -- -- --
---------- -------- -------- -------- --------
Total Gas 163,901 10,235 1,128 (245) 172,763
Nuclear Decommissioning
Trusts 45,504 6,015 271 (225) 51,023
Construction
in Progress -
Electric 7,934 18,681 -- -- 26,615
Gas 137 112 -- -- 249
---------- -------- -------- -------- --------
Total Construction
in Progress 8,071 18,793 -- -- 26,864
Nuclear Fuel 136,496 4,778 -- -- 141,274
---------- -------- -------- -------- --------
Total Utility Plant $1,623,951 $ 105,009 $ 8,825 $ (247) $1,719,888
========= ======== ======= ======= =========
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Schedule V
WISCONSIN PUBLIC SERVICE CORPORATION
Utility Plant
December 31, 1991
Column A Column B Column C Column D Column E Column F
-------- ---------- --------- ----------- -------- --------
Other
Balance at Retirements Changes Balance
Beginning Additions or Sales Debit at End
Classification of Period at Cost at Cost (Credit) of Period
-------------- ---------- --------- ----------- ------- ---------
(thousands)
Utility Plant -
Intangible Electric $ 187 $ -- $ -- $ (187) $ --
Electric
Steam Production 501,490 4,094 2,642 189 503,131
Nuclear 120,622 3,887 738 -- 123,771
Hydraulic 23,963 992 44 1 24,912
Other Production 13,782 323 46 -- 14,059
Transmission 121,047 8,635 769 (339) 128,574
Distribution 353,208 19,706 3,531 186 369,569
General 21,171 1,401 386 250 22,436
Common 78,585 8,198 2,739 (687) 83,357
Plant Held for
Future Use 170 -- -- -- 170
--------- ------- ------- ------ ---------
Total Electric 1,234,225 47,236 10,895 (587) 1,269,979
Gas
Production 476 -- -- -- 476
Distribution 136,120 6,374 478 -- 142,016
General 2,381 119 13 -- 2,487
Common 17,085 1,861 621 597 18,922
Plant Held for
Future Use -- -- -- -- --
--------- ------- ------- ------ ---------
Total Gas 156,062 8,354 1,112 597 163,901
Nuclear Decommissioning
Trusts 40,587 6,086 -- (1,169) 45,504
Construction
in Progress -
Electric 7,121 813 -- -- 7,934
Gas 366 (229) -- -- 137
--------- ------- ------- ------ ---------
Total Construction
in Progress 7,487 584 -- -- 8,071
Nuclear Fuel 130,338 6,158 -- -- 136,496
--------- ------- ------- ------ ---------
Total Utility Plant $1,568,699 $ 68,418 $ 12,007 $(1,159) $1,623,951
========= ======= ======= ====== =========
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Schedule VI
WISCONSIN PUBLIC SERVICE CORPORATION
Accumulated Provision for Depreciation of Utility Plant and
Amortization of Nuclear Fuel
Year Ended December 31, 1993
Column A Column B Column C Column D Column E Column F
-------- -------- -------- -------- -------- --------
Additions Charged to
--------------------
Balance at Clearing Deductions Balance
Beginning Income and Other Net Other End of
Description of Period (Note 1) Accounts Retirements Salvage Changes Period
- ----------- ---------- -------- --------- ----------- ------- ------- -------
(thousands)
Electric $661,207 $54,498 $2,898 $10,885 $ (740) $ 600 $709,058
Gas 87,220 6,111 332 1,491 74 (100) 91,998
------- ------ ----- ------ ----- ----- -------
Subtotal 748,427 60,609 3,230 12,376 (666) 500 801,056
Nuclear Fuel 124,394 5,617 - - - - 130,011
------- ------ ----- ------ ----- ----- -------
Total $872,821 $66,226 $3,230 $12,376 $ (666) $ 500 $931,067
======= ====== ===== ====== ===== ====== =======
Note:
1993 1992 1991
---- ---- ----
Retirements per Schedule V $20,181 $8,825 $12,007
Less: Sale of combustion turbine 7,849 - -
Other, primarily land (44) 367 10
------ ----- ------
Retirements per Schedule VI $12,376 $8,458 $11,997
====== ===== ======
-71-
Schedule VI
WISCONSIN PUBLIC SERVICE CORPORATION
Accumulated Provision for Depreciation of Utility Plant and
Amortization of Nuclear Fuel
Year Ended December 31, 1992
Column A Column B Column C Column D Column E Column F
-------- -------- -------- -------- -------- --------
Additions Charged to
--------------------
Balance at Clearing Deductions Balance
Beginning Income and Other Net Other End of
Description of Period (Note 1) Accounts Retirements Salvage Changes Period
- ----------- --------- -------- --------- ----------- ------- ------- -------
(thousands)
Electric $613,124 $52,819 $2,641 $7,345 $ 141 $ 109 $661,207
Gas 82,462 5,773 311 1,113 102 (111) 87,220
------- ------ ----- ----- ----- ----- -------
Subtotal 695,586 58,592 2,952 8,458 243 (2) 748,427
Nuclear Fuel 117,792 7,092 -- -- -- (490) 124,394
------- ------ ----- ----- ----- ----- -------
Total $813,378 $65,684 $2,952 $8,458 $ 243 $ (492) $872,821
======= ====== ===== ===== ===== ===== =======
-72-
Schedule VI
WISCONSIN PUBLIC SERVICE CORPORATION
Accumulated Provision for Depreciation of Utility Plant and
Amortization of Nuclear Fuel
Year Ended December 31, 1991
Column A Column B Column C Column D Column E Column F
-------- -------- -------- -------- -------- --------
Additions Charged to
--------------------
Balance at Clearing Deductions Balance
Beginning Income and Other Net Other End of
Description of Period (Note 1) Accounts Retirements Salvage Changes Period
- ----------- --------- -------- --------- ----------- ------- ------- -------
(thousands)
Electric $571,319 $49,683 $2,378 $10,885 $ (855) $ (226) $613,124
Gas 77,079 6,004 353 1,112 116 254 82,462
------- ------ ----- ------ ----- ------ -------
Subtotal 648,398 55,687 2,731 11,997 (739) 28 695,586
Nuclear Fuel 110,807 8,499 -- -- -- (1,514) 117,792
------- ------ ----- ------ ----- ------ -------
Total $759,205 $64,186 $2,731 $11,997 $ (739) $(1,486) $813,378
======= ====== ===== ====== ===== ====== =======
Note 1: See Note 1 of Notes to Financial Statements with respect to the basis of
the provisions for depreciation. Reconciliation of depreciation expense
shown on the Statements of Income:
1993 1992 1991
---- ---- ----
Depreciation per Statements of Income $60,609 $58,592 $55,687
Amortization of Nuclear Fuel included
in Electric Production Fuels 7,585 7,092 8,499
------ ------ ------
Total $68,194 $65,684 $64,186
====== ====== ======
-73-
Schedule X
WISCONSIN PUBLIC SERVICE CORPORATION
SUPPLEMENTARY INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31,
1993, 1992 AND 1991:
The amounts of maintenance and repairs, depreciation and taxes
charged to other accounts are not significant. Advertising costs aggregated
less than one percent of total revenues. No significant royalties were paid.
The Company has no material capital leases.
Other taxes included in the Statements of Income are as follows:
Year Ended December 31
----------------------
(thousands)
1993 1992 1991
---- ---- ----
Gross Receipts $ 16,293 $16,053 $15,231
Payroll 7,055 6,723 6,411
Other 1,856 1,683 1,392
------- ------ ------
Total $ 25,204 $24,459 $23,034
======= ====== ======
-74-