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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
X ACT OF 1934
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For the fiscal year ended December 31, 1994
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
---- EXCHANGE ACT OF 1934
For the transition period from ________________ to ______________
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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None
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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Not Applicable
Number of shares outstanding of each class of common stock, as of December 31,
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1994:
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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 4,
1995 (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, 1994
TABLE OF CONTENTS
DEFINITIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . iii
PART I
1. BUSINESS. . . . . . . . . . . . . . . . . . . . . . . . . . 1
A. GENERAL. . . . . . . . . . . . . . . . . . . . . . . . 1
B. ELECTRIC OPERATIONS
General Matters. . . . . . . . . . . . . . . . . 1
Kewaunee Nuclear Power Plant . . . . . . . . . . 2
Fuel Supply. . . . . . . . . . . . . . . . . . . 4
Rhinelander Energy Center. . . . . . . . . . . . 6
Other Matters. . . . . . . . . . . . . . . . . . 7
Financial Summary. . . . . . . . . . . . . . . . 9
Electric Operating Statistics. . . . . . . . . . 10
C. GAS OPERATIONS
General Matters. . . . . . . . . . . . . . . . . 11
Financial Summary. . . . . . . . . . . . . . . . 14
Gas Operating Statistics . . . . . . . . . . . . 15
D. ENVIRONMENTAL MATTERS
General Matters. . . . . . . . . . . . . . . . . 16
Air Quality. . . . . . . . . . . . . . . . . . . 16
Water Quality. . . . . . . . . . . . . . . . . . 17
Gas Plant Cleanup. . . . . . . . . . . . . . . . 17
Other Solid Waste Disposal . . . . . . . . . . . 18
E. REGULATORY MATTERS
General Matters. . . . . . . . . . . . . . . . . 19
Customer Rate Matters. . . . . . . . . . . . . . 20
PSCW Industry Restructuring Proceeding . . . . . 20
Accounting Developments. . . . . . . . . . . . . 21
Dividend Restrictions. . . . . . . . . . . . . . 21
F. CAPITAL REQUIREMENTS . . . . . . . . . . . . . . . . . 22
G. EMPLOYEES. . . . . . . . . . . . . . . . . . . . . . . 22
2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . 23
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3. LEGAL PROCEEDINGS
Sheboygan Gas Plant. . . . . . . . . . . . . . . . . . 24
Oshkosh Gas Plant. . . . . . . . . . . . . . . . . . . 24
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. . . . . 25
4A. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT . . . . . 25
PART II
5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDERS MATTERS . . . . . . . . . . . . . . . . . . . . 27
6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA AND FINANCIAL STATISTICS
(1984 AND 1990 TO 1994)
A. SELECTED FINANCIAL DATA . . . . . . . . . . . . . . . . 28
B. FINANCIAL STATISTICS . . . . . . . . . . . . . . . . . 28
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION . . . . . . . . . . . . . 29
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. CONSOLIDATED STATEMENTS OF INCOME . . . . . . . . . . . 36
B. CONSOLIDATED BALANCE SHEETS . . . . . . . . . . . . . . 37
C. CONSOLIDATED STATEMENTS OF CAPITALIZATION . . . . . . . 38
D. CONSOLIDATED STATEMENTS OF CASH FLOWS . . . . . . . . . 39
E. CONSOLIDATED STATEMENTS OF RETAINED EARNINGS . . . . . 40
F. NOTES OF CONSOLIDATED FINANCIAL STATEMENTS . . . . . . 41
G. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS . . . . . . . 56
9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE. . . . . . . . . . . . . 57
PART III
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K. . . . . . . . . . . . . . . . . . . . . . . . . 57
DESCRIPTION OF DOCUMENTS . . . . . . . . . . . . . . . . . . 59
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . 63
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DEFINITIONS
The following abbreviations and acronyms are used in the text of this
Form 10-K:
Act . . . . . . . . . . Federal Clean Air Act Amendments of 1990
ANR . . . . . . . . . . ANR Pipeline Company
Columbia* . . . . . . . The Columbia Energy Center
Committee . . . . . . . Advisory Committee formed by the PSCW to
recommend changes in the structure and
regulation of the electric utility
industry in Wisconsin
Company . . . . . . . . Wisconsin Public Service Corporation
CPCN. . . . . . . . . . Certificate of Public Convenience and
Necessity
DNR . . . . . . . . . . Wisconsin Department of Natural
Resources
DOE . . . . . . . . . . U. S. Department of Energy
Edgewater*. . . . . . . The Edgewater Unit 4 power plant
Enrichment Corporation. United States Enrichment Corporation
EPA . . . . . . . . . . U. S. Environmental Protection Agency
FERC. . . . . . . . . . Federal Energy Regulatory Commission
INPO. . . . . . . . . . Institute of Nuclear Power Operations
Kewaunee* . . . . . . . Kewaunee Nuclear Power Plant
MG&E. . . . . . . . . . Madison Gas and Electric Company
MPSC. . . . . . . . . . Michigan Public Service Commission
NERCO . . . . . . . . . NERCO Coal Company
NNAB. . . . . . . . . . National Nuclear Accrediting Board
NTS . . . . . . . . . . Network Transmission Service
Nuclear Policy Act. . . Nuclear Waste Policy Act of 1982
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Policy Act. . . . . . . The National Energy Policy Act of 1992
Polsky. . . . . . . . . Polsky Energy Corporation
PRP . . . . . . . . . . Potentially responsible party
PSCW. . . . . . . . . . Public Service Commission of Wisconsin
Pulliam*. . . . . . . . The Pulliam generating facility
Railroads . . . . . . . Soo Line and Wisconsin Central railroads
REC . . . . . . . . . . The Rhinelander Energy Center, a
cogeneration facility 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
RTG . . . . . . . . . . A regional transmission group such as
the one which the Mid-America
Interconnected Network companies are
planning to form
Superfund . . . . . . . Comprehensive Environmental Response,
Compensation and Liability Act
Union . . . . . . . . . Local 310 of the International Union of
Operating Engineers which represents
certain Company employees
Viking. . . . . . . . . Viking Gas Transmission Company
WDG . . . . . . . . . . Wisconsin Distributors Group
WEPCO . . . . . . . . . Wisconsin Electric Power Company
Weston* . . . . . . . . The Weston generating facility
Wisconsin*. . . . . . . State of Wisconsin
WP&L. . . . . . . . . . Wisconsin Power and Light Company
WPPI. . . . . . . . . . Wisconsin Public Power, Inc.
WPSR. . . . . . . . . . WPS Resources Corporation, parent of the
Company
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* Indicates items not defined elsewhere in this report.
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PART I
ITEM 1. BUSINESS
A. GENERAL
Wisconsin Public Service Corporation ("Company"), a Wisconsin
corporation, which was incorporated July 17, 1883, is a regulated
public utility engaged chiefly in the production, transmission,
distribution and sale of electricity and in the purchase,
transportation, distribution and sale of natural gas. On September 1,
1994, the Company became a wholly-owned subsidiary of WPS Resources
Corporation ("WPSR") as a result of a one-for-one exchange of common
stock shares. Also on September 1, 1994, all of the capital stock of
WPS Communications, Inc. and Packerland Energy Services, Inc. was
transferred to WPSR as part of a corporate restructuring.
At year end 1994, the Company served at retail 353,893 electric
customers and 196,666 gas customers in an 11,000 square mile service
territory in Northeastern Wisconsin and an adjacent part of Upper
Michigan. Additionally, the Company provides wholesale full or
partial requirements electric service, either directly or indirectly,
to eleven municipal utilities, and also two Rural Electrification
Administration financed electric cooperatives and a privately held
utility. About 98% of operating revenues in the year 1994 were
derived from Wisconsin customers and 2% from Michigan customers. Of
total revenues in 1994, 73% were from electric operations and 27% from
gas operations. Of total electric revenues, 91% were from retail
sales and 9% were from wholesale sales.
The Company's retail service areas are principally protected in
Wisconsin by indeterminate permits secured by statute, and in the
state of Michigan by franchises granted by municipalities.
B. ELECTRIC OPERATIONS
GENERAL MATTERS. The largest communities served at retail with
electricity are the cities of Green Bay, Oshkosh, Wausau and Stevens
Point.
The Company's maximum net demand in 1994 was 1,549,000 kw which
occurred on June 16. At that time, system capability was
1,819,900 kw, and after adjustments for firm purchases and sales to
other utilities, the Company's reserve capacity was 16.6%. This 1994
maximum net demand was slightly lower than the 1993 summer net peak
demand. The Company's future reserves, also adjusted for firm
purchases and sales and planned capacity additions, are estimated to
be above the planning criteria of a 15% minimum reserve in 1995 and
1996. See Part I, Item 2, PROPERTIES, at page 23 for information
concerning generating facilities.
Coordinated planning for generation and transmission is a
function of the Wisconsin Upper Michigan Systems of which the Company
is a member along with Wisconsin Power and Light Company ("WP&L"),
Madison Gas & Electric Company ("MG&E"), Wisconsin Electric Power
Company ("WEPCO"), Upper Peninsula Power Company and Wisconsin Public
Power, Inc. ("WPPI"). Existing and planned interconnections with
other neighboring utilities provide a further means of sharing reserve
capacities and interchanging energy.
The Company owns 33.1% of the outstanding capital stock of
Wisconsin River Power Company ("River Power"). The business of River
Power consists of the ownership and operation of two dams and related
hydroelectric plants on the Wisconsin River having an aggregate
installed capacity of about 35,000 kw. The output of the
hydroelectric plants is sold, at the sites of the plants, to the three
companies which own the outstanding capital stock substantially in
proportion to their stock ownership interests.
KEWAUNEE NUCLEAR POWER PLANT. The Company is the operator and
41.2% owner of Kewaunee which is owned jointly with WP&L and MG&E.
This plant began commercial operation in 1974. The Kewaunee
capability factor was 86.6% in 1994, compared to a projected industry
average of 73.7%.
The Company is a member of the Institute of Nuclear Power
Operations ("INPO"), an organization of nuclear utilities which
promotes excellence in all aspects of nuclear plant operations. INPO
manages the accreditation process for industry training programs,
which includes periodic accreditation of those training programs by an
independent organization, the National Nuclear Accrediting Board
("NNAB"). All ten accredited training programs at Kewaunee are
currently in good standing with the NNAB.
The steam generator tubes at Kewaunee are susceptible to
corrosion characteristics seen throughout the nuclear industry.
Inspections are performed to identify degraded tubes. Degraded tubes
are either repaired by sleeving or are removed from service by
plugging. The steam generators were designed with approximately 15%
heat transfer margin, meaning that full power should be sustainable
with the equivalent of 15% of the steam generator tubes plugged. Tube
plugging and the build-up of deposits on the tubes affect the heat-
transfer capability of the steam generators to the point where
eventually full power operation is affected. The result will be a
gradual decrease in the capacity of the plant. The plant's capacity
could be reduced by as much as 20% by the year 2013 when the current
operating license expires. Currently, the equivalent of approximately
12% of the tubes in the steam generators are plugged with no loss of
capacity. The Company recently completed studies evaluating the
economics of replacing the two steam generators at Kewaunee. The
studies resulted in the conclusion that the most prudent course of
action is to continue operation of the existing steam generators. The
Company continues to evaluate appropriate repair strategies, including
replacement, as well as continued operation of the steam generators
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without replacement. The Company also continues to fund the
development of welded repair technology for steam generator tubes.
The Company continues to evaluate and implement initiatives to
improve the performance of Kewaunee which already performs at above
average levels for the industry. These initiatives include conversion
from a twelve-month to an eighteen-month operating cycle beginning in
the spring of 1995 and numerous other cost reduction measures. These
initiatives have resulted in approximately a 25% reduction in Kewaunee
operating and maintenance costs since 1991.
Physical decommissioning of Kewaunee is expected to occur during
the period 2014 to 2021 with additional expenditures being incurred
during the period 2022 to 2050 related to the storage of spent nuclear
fuel at the site. In July of 1994, the Public Service Commission of
Wisconsin ("PSCW") issued an order covering all Wisconsin utilities
that have nuclear generation. The order standardizes cost escalation
assumptions used in determining decommissioning liabilities. Based
upon this new methodology, and considering other assumption changes,
Kewaunee decommissioning costs are estimated to be $357 million in
current dollars and $785 million in year of expenditure dollars. The
Company's share of Kewaunee decommissioning costs are estimated to be
$147 million in current dollars. These costs are recovered currently
in customer rates and deposited in external trusts. As a result of
the new order, annual funding is expected to increase from
approximately $4.0 million to approximately $8.7 million. On
December 31, 1994, the market value of the investments in the trusts
was $64.1 million.
Spent fuel is currently stored at Kewaunee. The existing
capacity of the spent fuel storage facility will enable storage of the
projected quantities of spent fuel through April 2001. The Company
is evaluating options for the storage of additional quantities beyond
2001. Several technologies are available. An investment of
approximately $2.5 million in the early 2000s could provide additional
storage sufficient to meet spent fuel storage needs until the
expiration of the current operating license in 2013.
The Low-Level Radioactive Waste Policy Act of 1980 specifies that
states may enter into compacts to provide for regional low level waste
disposal facilities. Wisconsin is a member of the Midwest Low Level
Radioactive Waste Compact. The state of Ohio has been selected as the
host state for the Midwest Compact and is proceeding with the
preliminary phases of site selection. In June of 1994, the Barnwell,
South Carolina disposal facility, which had been accepting Kewaunee
low level radioactive waste materials, discontinued taking waste
materials from outside its region. The Company expects to have
sufficient storage space of its own to satisfy low level radioactive
waste disposal needs until the Ohio facility accepts low level
radioactive waste materials.
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FUEL SUPPLY. The Company's electric generation mix in 1994
compared to 1993 was: steam plants (coal), 62.6%, down from 64.7%;
steam plant (nuclear), 14.5%, down from 14.6%; hydro, 2.6%, down from
3.2%; combined natural gas and fuel oil, .7%, up from .4%; and
purchased power, 19.6%, up from 17.1%. Purchased power represents
short-term energy purchases.
The Company has reduced over-all fuel costs for the fifth
consecutive year. Fuel costs in 1994 compared with 1993, expressed in
dollars per million BTU, were: nuclear, $.49, up from $.45; coal,
$1.31, down from $1.38; natural gas, $2.77, down from $3.41; and No. 2
fuel oil, $4.15, up from $3.96.
In 1995, the Company will purchase almost all of the coal for its
solely-owned plants from Western sources. Delivery of coal at the
Pulliam plant is via railroad or lake vessel and at the Weston,
Columbia and Edgewater plants via railroad.
Pulliam and Weston Units 1 and 2 burn Powder River Basin sub-
bituminous coal. The Company has a long-term contract with one coal
supplier that is expected to provide approximately two-thirds of the
projected 1995 coal requirements for Unit 3 at Weston. The coal
contract will provide low sulfur Powder River Basin coal for a term
ending in 2016. The remainder of the coal for solely-owned generating
facilities is purchased under short-term agreements of two years or
less.
During 1991, the Company bought-out the coal supply agreement
with NERCO Coal Company ("NERCO") and the corresponding rail
transportation contracts with the Soo Line and the Wisconsin Central
("Railroads"). The Company paid approximately $34 million to NERCO
and the Railroads as compensation for relief of all contractual
obligations. The PSCW has ruled that the railroad and coal contract
buyout costs may be recovered in customer rates subject to a benefits
test. Management believes it will meet the benefits test and,
therefore, recover in future rates all of the buyout costs because the
cost of replacement coal plus the buyout costs as amortized and a
return on the unamortized portion of the buyout costs are less than
the costs under the original contracts. In the Wisconsin
jurisdiction, the remaining unamortized buyout costs of $15.4 million
will be recovered during 1995 and 1996. The Federal Energy Regulatory
Commission ("FERC") issued an order on November 15, 1994 allowing
recovery of all but approximately $3.6 million of NERCO buyout costs
through a monthly surcharge rate over the period January 1993 through
December 2005. The portion of the $3.6 million disallowance allocable
to the FERC jurisdiction will not be determined until the end of 1995.
Management believes that it is likely that the disallowance allocable
to the FERC jurisdiction will not exceed the $625,000 write off taken
in 1993 in anticipation of the disallowance. The Company will accrue
and recover carrying charges on the unrecovered balance.
The Company also has a 31.8% ownership share in Columbia and a
31.8% ownership share in the Edgewater Unit 4, both of which are
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operated by WP&L which has coal procurement responsibilities for these
units. Columbia, with two 527 megawatt units, uses coal from the
Wyoming-Montana coal fields. One hundred percent of the low sulfur
coal for Unit 1 is supplied under terms of a contract which expires in
2004. The entire low sulfur coal supply for Unit 2 is supplied from
the Southern Powder River Basin under short-term contracts. Edgewater
uses a blend of bituminous and sub-bituminous Powder River Basin coal
both of which are acquired under short-term contracts.
In 1989, the PSCW concluded that WP&L did not properly administer
a coal contract for Columbia, which is owned 31.8% by the Company,
46.2% by WP&L and 22.0% by MG&E, and ordered WP&L to refund $9 million
to the customers of the Company, WP&L and MG&E proportionately
according to the ownership shares of each utility in Columbia. WP&L
appealed the PSCW decision, and that PSCW action was found to
represent unlawful retroactive ratemaking by both the Dane County
Circuit Court and the Wisconsin Court of Appeals. On February 8,
1994, the Wisconsin Supreme Court upheld the decision of the Wisconsin
Court of Appeals.
The supply of nuclear fuel for Kewaunee requires the purchase of
uranium concentrates, the conversion of uranium concentrates to
uranium hexafluoride, enrichment of the uranium hexafluoride and
fabrication of the enriched uranium into usable fuel assemblies.
After a region (approximately one-third of the nuclear fuel assemblies
in the reactor) of spent fuel is removed from the reactor, it is
placed in temporary storage for cooling in a spent fuel pool at the
plant site. Permanent storage is addressed below. There are
presently no operating facilities in the United States reprocessing
commercial nuclear fuel. A discussion of the nuclear fuel supply for
Kewaunee follows:
(a) Requirements for uranium are met through spot or contract
purchases. An inventory policy, which takes advantage of
economical spot market purchases of uranium, results in the
Company maintaining inventories sufficient for three reactor
reloads of fuel.
(b) Uranium hexafluoride from inventory and from spot market
purchases was used to satisfy converted material requirements in
1994. The Company intends to purchase future conversion services
on the spot market.
(c) In 1994, enriched uranium was procured from COGEMA, Inc. pursuant
to a contract executed in 1983 and last amended in 1993.
Enrichment services were purchased from the United States
Enrichment Corporation ("Enrichment Corporation") under the terms
of the utility services contract which is in effect for the life
of Kewaunee. The Company is committed to take 70% of its annual
enrichment requirements in 1995, and in alternate years
thereafter, from the Enrichment Corporation.
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(d) Fuel fabrication requirements through June 15, 1995 are covered
by contract. The Company is finalizing a contract for fuel
fabrication extending through 2001.
(e) Beyond the stated periods set forth above, additional contracts
for uranium concentrates, conversion to uranium hexafluoride,
fabrication and spent fuel storage will have to be procured. The
Company anticipates the prices for the foregoing will increase.
Pursuant to the Nuclear Waste Policy Act of 1982 ("Nuclear Policy
Act"), the U. S. Department of Energy ("DOE") has entered into a
contract with the Company to accept, transport and dispose of spent
nuclear fuel beginning no later than January 31, 1998. It is likely
that the DOE will delay the acceptance of spent nuclear fuel beyond
1998. A fee to offset the costs of the DOE's disposal for all spent
fuel used since April 7, 1983 has been assessed by DOE at one mill per
net kilowatt hour of electricity generated and sold by Kewaunee. An
additional one-time fee was paid to the DOE for the disposal of spent
nuclear fuel used to generate electricity prior to April 7, 1983.
The Nuclear Policy Act provides that both the federal government
and the nuclear utilities fund the decontamination and decommissioning
of the three gaseous diffusion plants in the United States. Utility
contributions will be collected through a special assessment based on
a utility's percentage of uranium enrichment services purchased
through the date of enactment compared to total enrichment sales by
the DOE. The owners of Kewaunee are required to pay approximately
$19.2 million in current dollars over a period of fifteen years. At
December 31, 1994, the remaining liability was $15.4 million of which
the Company's share is $6.33 million. The payments are subject to
adjustment for inflation.
RHINELANDER ENERGY CENTER. The Company has identified the need
for additional power supply late in this decade. To satisfy this
need, the Company has signed a thirty-five year steam and electrical
sales agreement with Rhinelander Paper Company, Inc. ("Rhinelander
Paper") which likely will be amended to reflect continuing
negotiations between the parties. This agreement provides for the
Company to construct, own and operate the Rhinelander Energy Center
("REC"), a 122 megawatt cogeneration facility, with an estimated cost
of $169 million, adjacent to Rhinelander Paper's mill in Rhinelander,
Wisconsin. Rhinelander Paper will purchase and use steam from the
facility in its paper processes. On September 24, 1993, the Company
initiated the filing process for a Certificate of Public Convenience
and Necessity ("CPCN") which must be issued by the PSCW to permit
construction of the REC. Action by the PSCW on the application is
being carried out under a recently developed two-stage CPCN process
regulated by the PSCW. In the first stage, the Company requested
proposals from electric generating plant project developers and
compared them to the proposed REC. On December 21, 1994, the PSCW
issued its order approving the Company's REC project as the least cost
solution to the Company's capacity needs. One unsuccessful bidder,
Polsky Energy Corporation ("Polsky") petitioned for a rehearing of the
PSCW's decision. The PSCW has agreed to consider Polsky's allegations
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regarding the accuracy of certain computations related to the
Company's successful bid. On March 9, 1995, in response to the Polsky
petition, the PSCW affirmed their original decision in holding that
the REC remains the least cost alternative which will satisfy the
Company's additional capacity needs. The Company is proceeding with
stage two of the CPCN process to obtain PSCW authorization to
construct the REC, a process which is expected to result in a final
decision on the CPCN in the second half of 1995 in order to have the
facility in service in the summer of 1998.
OTHER MATTERS. On January 14, 1994, the Company submitted its
Advance Plan 7 filing to the PSCW. It was updated on April 29, 1994.
This plan identifies both the demand side and supply side needs of the
Company through the year 2013. Preliminary plans indicate that demand
side management programs will reduce the need for additional electric
capacity by 269 megawatts. Supply side generation forecasts indicate
the need for peaking generating units in 2001, 2002, 2004 and 2005
(combustion turbines of 75 megawatts each), an intermediate generating
unit in 2009 (215 megawatt combined-cycle gas-fired unit), and a
peaking generating unit in 2013 (75 megawatt combustion turbine). The
plan also includes 122 megawatts of cogeneration from the REC as
discussed above. Other smaller scale renewable projects are included
in the plan. Pulliam Units 3 and 4 are included in the plan as being
retired in 1998. They began operating in the 1940s. Advance Plan 7
must go through the regulatory review process. Hearings started in
November of 1994 and are scheduled to conclude in May of 1995.
The Company is developing and implementing strategies to deal
with issues raised by the National Energy Policy Act of 1992 ("Policy
Act"). The Policy Act's provisions for transmission access should
have minimal impact on the Company because the Company already has
transportation tariffs on file at the FERC. The generation provisions
of the Policy Act could create additional competition in that market;
however, generation opportunities for the Company also could increase.
Regionally, the member companies of the Mid-America
Interconnected Network, of which the Company is a member, are planning
the formation of a regional transmission group ("RTG") that will open
up the entire transmission grid within the network to member companies
and others who choose to participate. It will then be easier than
ever to transport electric power from one purchaser to another. FERC
must approve the agreement for the formation of a RTG.
The Company faces increased competition in the wholesale power
market. This may result in the loss of certain wholesale customers
and reduced margins. The Company intends to compete aggressively to
retain wholesale load.
In October of 1992, WPPI notified the Company that it was ending
its agreement to purchase power effective in October of 1997. WPPI is
a wholesale customer which buys 66 megawatts from the Company for
resale to municipal utilities in Algoma, Eagle River, New Holstein,
Sturgeon Bay and Two Rivers. WPPI has entered into an agreement to
buy power from another Wisconsin utility during the period 1997 to
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2009. Also, the Company has negotiated a new power supply agreement
with the City of Wisconsin Rapids.
Although 12% of electric revenues come from sales to twenty paper
mills, resulting in a relatively high and favorable load factor, there
is no single customer or small group of customers, the loss of which
would have a materially adverse effect on the electric business of the
Company.
In August of 1994, the Company received approval from the PSCW to
construct a portion of a jointly owned 138 Kv transmission line
extending from New London to Stevens Point. The Company's share of
the sixty mile transmission project will cost approximately $14.9
million; the remaining $9.6 million cost of the project is the
responsibility of WEPCO and WP&L. Completion of the project is
expected by early 1997. In the same order, the PSCW denied an
application by WPPI to build and own the project facilities as a means
to reduce its overall power supply costs. The Company, WEPCO and WP&L
offered, and were ultimately ordered, to file Network Transmission
Service ("NTS") tariffs with the FERC that would offer comparable use
on their transmission systems. The Company tendered its NTS tariff for
filing with the FERC in September of 1994. Currently, the NTS tariff
is under review by the FERC and intervenors.
The Company also is waiting for a ruling from the PSCW regarding
the Wausau to Abbotsford transmission project, which is part of a
larger transmission interface project with Northern States Power
Company, consisting of the rebuild of approximately twenty-three miles
of 115 Kv transmission line. The cost of the project is estimated to
be $4.2 million.
Applications for relicensing of the Company's Caldron Falls, High
Falls, Johnson Falls, Sandstone Rapids, Potato Rapids, Peshtigo, Grand
Rapids and Jersey projects were submitted to the FERC in December of
1991. These licenses, representing 30 megawatts of hydroelectric
generating capacity, expired in December of 1993. Since the FERC had
not considered the Company's applications at the license expiration
dates, the licenses have been extended on an annual basis until FERC
acts on the applications. Application to the FERC for relicensing of
the Company's Wausau Project was submitted in June of 1993. The
license for this project expires in June of 1995 and represents 5,400
kilowatts of capacity.
In the fall of 1994, the PSCW initiated a proceeding to assess
the future of utility regulation in Wisconsin and to investigate the
structure necessary for utilities to compete in the new electric
marketplace. Public meetings have been held to identify the relevant
issues. This matter is discussed in more detail in Part I, Item 1E,
REGULATORY MATTERS, at page 20.
Electric research and development expenditures totaled
$2.3 million for 1994, $2.1 million for 1993 and $2.0 million for
1992. These expenditures were made for Company sponsored projects and
were primarily charged to electric operations.
-8-
FINANCIAL SUMMARY. The following table sets forth the revenues,
operating income and identifiable assets attributable to electric
utility operations:
YEAR ENDED DECEMBER 31
1994 1993 1992
(thousands)
Electric Operating Revenues $480,816 $493,256 $477,625
Operating Income, Including
Allowance For Funds Used
During Construction $ 68,260 $ 75,561 $ 73,026
Identifiable Assets $937,481 $938,951 $951,074
See Note 7 in Notes to Consolidated Financial Statements.
-9-
ELECTRIC OPERATING STATISTICS
1994 1993
1992 1991 1990
1984
==============================================================================
===============================================
===
Operating revenues (Thousands)
==============================================================================
===============================================
===
Residential and farm $163,381 $165,568
$156,659 $158,014 $145,114
$135,833
Small commercial and industrial 137,323 140,678
136,164 134,314 125,575
107,436
Large commercial and industrial 118,121 123,920
115,147 111,037 108,549
102,032
Resale and other 61,991 63,090
69,655 67,912 69,667
60,119
==============================================================================
===============================================
===
Total $480,816 $493,256
$477,625 $471,277 $448,905
$405,420
==============================================================================
===============================================
===
Kilowatt-hour sales (Thousands)
Residential and farm 2,406,479 2,349,307
2,268,685 2,319,972 2,183,644
1,927,985
Small commercial and industrial 2,555,488 2,444,548
2,384,098 2,388,787 2,282,412
1,746,532
Large commercial and industrial 3,468,390 3,296,254
3,016,329 2,854,519 2,819,507
2,325,165
Resale and other 2,121,660 2,060,804
2,078,057 2,004,925 2,002,351
1,470,282
==============================================================================
===============================================
===
Total 10,552,017 10,150,913
9,747,169 9,568,203 9,287,914
7,469,964
==============================================================================
===============================================
===
Customers served (End of period)
Residential and farm 316,442 310,336
304,404 298,194 293,733
267,461
Small commercial and industrial 36,491 35,683
34,783 33,981 33,355
29,591
Large commercial and industrial 164 137
129 125 127
111
Resale and other 796 794
825 908 944
475
==============================================================================
===============================================
===
Total 353,893 346,950
340,141 333,208 328,159
297,638
==============================================================================
===============================================
===
Annual average use (Kwh)
Residential and farm 7,688 7,649
7,538 7,845 7,495
7,269
Small commercial and industrial 70,931 69,532
69,394 70,962 69,427
59,517
Large commercial and industrial 22,091,659 24,416,697
23,750,625 22,476,532 22,737,961
21,529,302
==============================================================================
===============================================
===
Average kwh price (Cents)
Residential and farm 6.79 7.05
6.91 6.81 6.65
7.05
Small commercial and industrial 5.37 5.75
5.71 5.62 5.50
6.15
Large commercial and industrial 3.41 3.76
3.82 3.89 3.85
4.39
==============================================================================
===============================================
===
Production capacity (Kw)
Steam 1,269,240 1,269,240
1,269,240 1,269,240 1,269,240
1,269,240
Nuclear 221,000 221,000
221,000 221,000 221,000
221,000
Hydraulic 64,786 64,786
64,786 64,786 64,786
64,236
Combustion turbine 239,700 239,700
156,200 156,200 156,200
156,200
Other 4,040 4,040
4,040 4,040 4,040
4,040
Interest in Wis. River Power Co. 11,667 11,667
11,667 11,667 11,667
11,667
==============================================================================
===============================================
===
Total system capacity 1,810,433 1,810,433
1,726,933 1,726,933 1,726,933
1,726,383
==============================================================================
===============================================
===
Generation and purchases
(Thousands of Kwh)
Steam 7,047,511 7,004,634
6,796,975 6,731,857 6,641,716
5,443,590
Nuclear 1,631,003 1,572,696
1,622,279 1,512,712 1,606,898
1,569,519
Hydraulic 292,617 346,386
325,663 326,212 252,806
307,911
Purchases and other 2,243,021 1,849,047
1,628,326 1,603,161 1,368,396
649,557
==============================================================================
===============================================
===
Total 11,214,152 10,772,763
10,373,243 10,173,942 9,869,816
7,970,577
==============================================================================
===============================================
===
System peak - firm (Kw) 1,549,000 1,548,000
1,494,000 1,592,000 1,516,300
1,202,900
==============================================================================
===============================================
===
Annual load factor 76.66% 74.29%
74.03% 69.44% 72.61%
73.57%
-10-
C. GAS OPERATIONS
GENERAL MATTERS. At December 31, 1994, the Company provided
natural gas distribution service to 191,551 customers in 138 cities,
villages and towns in Northeastern Wisconsin and 4,998 customers in
and around Menominee, Michigan. The principal Wisconsin cities served
include Green Bay, Oshkosh, Sheboygan, Marinette, Two Rivers, Stevens
Point and Rhinelander.
The Company transported 58,508,511 dekatherms of gas of which
34,757,372 dekatherms were for resale during the year ended
December 31, 1994. At the end of 1994, the Company had 117 end-user
customers who purchased their gas directly from suppliers and
contracted with transporters, including the Company, to transport the
gas to their points of use. A total of 23,751,139 dekatherms was
transported for these customers. During 1994, several transportation
customers returned to purchasing their gas requirements from the
Company. Load loss due to fuel switching has been minor because
customers have been able to purchase transportation gas from suppliers
at competitive prices.
Since the Company has a purchased gas adjustment provision as
part of its customer rates, it recovers all of its purchased gas costs
from customers. This allows the Company to receive the same margin
(gas revenues less cost of gas) on therm sales to customers who
purchase natural gas from the Company as it receives from
transportation customers.
The Company retains a gas supply consultant who assists in
creating a gas supply portfolio to match its gas load profile at the
lowest reasonable cost. The portfolio is based on twenty-year gas
peak day and annual sales forecasts and is structured to place the
Company in an optimum gas purchasing position. The Company has
entered into seventeen gas supply contracts with fourteen suppliers
with terms from five months to six years with domestic suppliers and
ten years with Canadian suppliers. There are nine years remaining on
the contracts with Canadian suppliers. The large majority of gas is
competitively priced based on a monthly spot price index. The gas
supply contracts contain a gas inventory charge as well as corporate
warranties to assure gas deliverability for the term of the contract.
Peak day design requirements of 340,777 dekatherms per day is
based on a 1994-1995 peak day forecast at -20 degrees Fahrenheit. An
additional 11,295 dekatherms per day, or 3.3%, of reserve capacity
allows for growth and any unforeseen needs. Peak day requirements
will be served by 117,657 dekatherms per day from transportation gas,
and 223,120 dekatherms per day from storage gas. The Company has
access to eleven BCF of storage capacity in Michigan. Storage gas is
purchased and stored during the summer for redelivery during the
heating season. The Company has purchased 0.1 BCF of underground salt
dome storage in Louisiana to protect against a supply area gas
shortage.
-11-
The Company transports gas from Louisiana, the Gulf of Mexico,
the Texas-Oklahoma Panhandle area and Canada under contracts with ANR
Pipeline Company ("ANR") for domestic gas and Viking Gas Transmission
Company ("Viking") for Canadian supplies. On November 1, 1993, FERC
Order 636 became effective for ANR. Order 636 prohibits pipeline
companies, such as ANR, from bundling gas merchant services with
transportation services. Thus, Order 636 shifts gas supply
responsibilities to local distribution companies, such as the Company,
while the pipeline companies continue to transport gas owned by
others. Pipeline transportation rates are governed by tariffs which
are subject to adjustment by the pipeline companies with the approval
of the FERC. As a result of restructuring under Order 636, effective
November 1, 1993, the Company contracted for its pro rata share of
pipeline capacity from each of ANR's three supply areas: Southeast,
Southwest, and Canada. The initial term of each contract was for ten
years with the right to extend in five-year increments. In addition,
the Company has preexisting capacity on Viking for delivery of
Canadian gas with a term of four years with a right to extend.
Order 636 mandates a straight fixed variable rate design which
loads all fixed costs into the reservation charge. Based on rates
effective May 1, 1994, pipeline company reservation charges for 1995
will total approximately $41.3 million. The Company also has a no-
notice service to accommodate load swings caused by unexpected system
requirements.
On December 30, 1994, in FERC Docket No. TM 95-3-48-000, ANR
filed its sixth annual reconciliation of the take-or-pay
buyout/buydown costs recovered through monthly charges. These costs,
which represent 75% of ANR's total take-or-pay buyout/buydown costs
paid to their gas suppliers, are being passed on to ANR's customers,
including the Company. The Company's remaining fixed charge
obligation for the two take-or-pay dockets still outstanding is
$41,930. Monthly fixed charge payments and volumetric payments are
scheduled to be made through April 1998. All such costs are expected
to be recovered from customers pursuant to established policies of the
PSCW.
ANR, as a result of its FERC Order 636 compliance filing, will
recover various transition costs from its customers, including the
Company. The Company expects to recover ANR transition costs in
future customer rates. These costs include purchased gas adjustment
costs of which the Company's share is approximately $3.7 million. In
addition, ANR has upstream pipeline capacity costs of between
$85 million and $275 million of which the Company's share is
approximately 10%. The exact amount cannot be determined at this
time.
The Company is currently being billed for ANR's above-market
costs of gas purchases from the Dakota Gasification Plant. The
potential total amount of these billings is undetermined at this time.
The 1994 allocation of these costs was $3.2 million, and the 1995
allocation is expected to be $3.3 million. The Company, as part of
the Wisconsin Distributors Group ("WDG"), is contesting the legality
-12-
of the Dakota Gasification Plant costs provision and is paying these
costs under protest subject to refund. A hearing before the District
of Columbia Circuit Court could take place in 1995.
WPSR, the parent of the Company, has established a non-regulated
subsidiary, WPS Energy Services, Inc., to market gas supply services
to transportation customers.
The Company is a member of the WDG which utilizes a Washington,
D.C. legal counsel to monitor FERC activities and advise the group.
The group files testimony and interventions in cases that impact its
members. The Company is also advised by the same Washington, D.C.
legal counsel. The Company files interventions in cases to protect
its interests as they may be different from the group.
All of the Company's Wisconsin retail natural gas rates contain a
purchased gas adjustment clause which provides for tracking changes
for wholesale costs and an annual true-up of such costs. The PSCW
reaffirmed this purchased gas adjustment clause/true-up mechanism in
the Company s 1994 rate order. The Company's Michigan retail rates
include a gas cost recovery plan under procedures authorized by the
Michigan Public Service Commission ("MPSC") in 1983. Both the PSCW
and the MPSC have approved mechanisms to allow for full recovery of
take-or-pay and transition related costs which the FERC has authorized
ANR to pass on to its customers.
The Company is aggressively seeking new natural gas customers
resulting in the addition of about 6,557 new customers in 1994.
Growth in natural gas customers results from adding new customers in
existing service areas and from the acquisition of new natural gas
distribution franchises. At December 31, 1994, five applications for
new gas distribution franchises were pending before the PSCW.
The Company uses gas for power generation in peaking turbines and
for ignition and flame stabilization at its Weston Unit 3 and Pulliam
generating plants.
One large industrial customer is in a geographical location which
would allow for its direct connection to the ANR system. A special
rate designed to keep this customer on the Company distribution system
has been approved by the PSCW. The customer has requested a bypass to
connect directly to the ANR system, but remains a Company
transportation customer. There is no single customer or small group
of customers, the loss of which would have a materially adverse effect
on the natural gas business of the Company.
-13-
FINANCIAL SUMMARY. The following table sets forth the amounts of
revenues, operating income and identifiable assets attributable to gas
utility operations:
YEAR ENDED DECEMBER 31
1994 1993 1992
(thousands)
Gas Operating Revenues $182,058 $187,376 $157,177
Operating Income, Including
Allowance For Funds Used During
Construction $ 8,016 $ 8,183 $ 6,119
Identifiable Assets $188,554 $184,880 $158,314
See Note 7 in Notes to Consolidated Financial Statements.
-14-
GAS OPERATING STATISTICS
==============================================================================
====================================
1994 1993 1992
1991 1990 1984
==============================================================================
==================================
Operating revenues (Thousands)
Residential $104,020 $110,541 $93,234
$94,274 $84,030 $97,114
Small commercial and industrial 18,586 20,254 15,796
15,557 13,833 17,941
Large commercial and industrial 45,115 47,091 33,676
34,396 31,789 121,721
Other 14,337 9,490 14,471
7,995 10,416 1,995
==============================================================================
==================================
Total $182,058 $187,376 $157,177
$152,222 $140,068 $238,771
==============================================================================
==================================
Therms delivered (Thousands)
Residential 187,355 192,053 182,603
184,042 169,406 165,808
Small commercial and industrial 38,568 41,385 38,060
36,743 33,301 35,168
Large commercial and industrial 115,939 108,068 88,516
87,506 82,496 267,951
Other 9,810 6,337 3,718
5,414 5,729 1,985
- ------------------------------------------------------------------------------
- ----------------------------------
Total therm sales 351,672 347,843 312,897
313,705 290,932 470,912
Transportation 234,149 220,672 232,578
228,991 215,421 -
==============================================================================
==================================
Total 585,821 568,515 545,475
542,696 506,353 470,912
==============================================================================
==================================
Customers served (End of period)
Residential 178,992 172,902 168,349
164,392 160,956 143,229
Small commercial and industrial 14,689 14,571 14,248
13,635 13,084 11,301
Large commercial and industrial 2,867 2,508 2,178
2,360 2,388 2,491
Interdepartmental 1 1 1
1 1 1
Transportation customers 117 127 161
165 170 -
==============================================================================
==================================
Total 196,666 190,109 184,937
180,553 176,599 157,022
==============================================================================
==================================
-15-
D. ENVIRONMENTAL MATTERS
GENERAL MATTERS. The Company is subject to regulation with
regard to the impact of its operations on air and water quality and
solid waste disposal, and may be subject to regulation with regard to
other environmental considerations by various federal, state and local
authorities. The application of federal and state restrictions to
protect the environment involves or may involve review, certification
or issuance of permits by various federal and state authorities,
including the U. S. Environmental Protection Agency ("EPA") and the
Wisconsin Department of Natural Resources ("DNR"). Such restrictions,
particularly in regard to emissions into the air and water and solid
waste disposal, may limit, prevent or substantially increase the cost
of the operation of the Company's generating facilities and may
require substantial investments in new equipment at existing
installations. They may also require substantial investments for
proposed new projects and may delay or prevent authorization and
completion of the projects. The Company cannot forecast other effects
of all such regulation upon its generating, transmission and other
facilities, or its operations, but believes that it is presently
meeting existing requirements.
AIR QUALITY. The plants which the Company operates are in
compliance with all current sulfur dioxide and nitrogen oxide emission
standards.
The Federal Clean Air Act Amendments of 1990 ("Act") were enacted
in 1990. The Act requires reductions in sulfur dioxide in 1995
(Phase I) to meet limitations based on an emission rate of 2.5 pounds
per million BTUs multiplied by a historical generation baseline for
Pulliam Unit 8 and Edgewater Unit 4 generating units. The Act
requires further reductions beginning in the year 2000 (Phase II).
These limits are set based on an emission rate of 1.2 pounds per
million BTUs multiplied by a historical generation baseline for all
generating units. The Company's generating facilities met the year
2000 standard in 1994. The Company has achieved compliance with
Wisconsin and federal sulfur dioxide emission limitations by switching
to low sulfur coal.
Because of the emission allowance system included in the Act,
operations during Phase I are expected to produce surplus allowances
which are expected to be available to aid in compliance with the
requirements of Phase II. To the extent the Company determines that
it will have allowances available beyond its own requirements in both
Phase I and Phase II, it will consider the sale of these excess
allowances. The PSCW has ordered that profits from the sale of
allowances must be used to benefit utility customers.
The Act also requires the installation of low nitrogen oxide
burners on several units. Low nitrogen oxide burners were installed
at Pulliam Unit 8 early in 1994. Phase I of the Act allows units
smaller than 100 megawatts, such as Pulliam Unit 7, to be designated
Phase I units, thus building up sulfur dioxide credits. Having made
this election, low nitrogen oxide burners were installed at Pulliam
-16-
Unit 7 in 1994. Expenditure of $15 million to $25 million are
projected through 1999 to assure continued federal and Wisconsin
emission compliance under all normal operating conditions at Pulliam
and Weston. Based on past experience, it is anticipated that
expenditures related to sulfur dioxide and nitrogen oxide emission
compliance will be recoverable in customer rates.
Air toxic provisions in the Act will not be applied until the EPA
conducts a three-year study to determine if those standards need to be
applied to utilities.
WATER QUALITY. The Company is subject to regulation by the EPA
and the DNR with respect to thermal and other discharges from the
Company's power plants into Lake Michigan and other waters of
Wisconsin. Permits were reissued to the Company for its Pulliam and
Weston power plants. Various portions of those permits were
challenged. These challenges have not been formally resolved,
although many of the issues raised in the challenges have been
resolved through informal discussions with the DNR, additional testing
by the Company and regulatory changes. Under Wisconsin law, the
challenged portions of the permits are stayed, and the administrative
review process is completed. It is not anticipated that any of the
outstanding issues will have a material cost associated with them.
GAS PLANT CLEANUP. The Company is currently investigating the
need for environmental cleanup of eight manufactured gas plant sites
which it previously operated. The Company engaged an environmental
consultant to develop cleanup cost estimates for the two sites at
which Phase II site investigations have been completed. The cleanup
cost estimates for the Stevens Point and the Oshkosh sites are
$1.7 million and $2.6 million, respectively. With respect to
Stevens Point, the estimate assumes excavation of contaminated soils,
thermal treatment of soils, disposal of treatment residuals, on-site
groundwater extraction and treatment and post-cleanup monitoring for
twenty-five years. The cost estimate for the Oshkosh site assumes, in
addition to those items noted for Stevens Point, removal and disposal
of contaminated river sediments. The consultant has yet to perform
detailed investigations of the remaining six sites, and comparable
information on these sites is not available.
The Company used the estimates for these two sites as a basis for
making projections on cleanup costs at the other sites. Six of the
eight sites are located adjacent to rivers. Using the Oshkosh cleanup
estimate, which includes remediation of contaminated river sediments,
and assuming all six sites have sediment contamination, and using the
Stevens Point estimate for the two sites not adjacent to rivers, the
range of future investigation and cleanup costs for all eight sites is
estimated to be from $14.8 million to $29.3 million. Remediation
expenditures would be made over the next thirty-four years. The
Company has recorded as a liability with an offsetting deferred
charge, i.e., a regulatory asset, of $26.9 million, which represents
the Company's current estimate of cleanup costs for all eight sites.
Based on discussions with regulators and a recent rate order in
Wisconsin, management believes that these costs, but not the carrying
-17-
costs associated with the deferred charges, will be recoverable in
future customer rates.
As additional detailed investigations are completed, three having
been initiated in 1994, these estimates will be adjusted to reflect
specific site data. These adjustments could be significant. Other
factors that can affect these estimates are changes in remedial
technology and regulatory requirements. The estimates presented above
do not take into consideration any recovery from insurance carriers or
other third parties which the Company is pursuing.
See also Part I, Item 3, LEGAL PROCEEDINGS, at page 24, for
discussion of the Sheboygan Gas Plant and Oshkosh Gas Plant sites.
OTHER SOLID WASTE DISPOSAL. On December 1, 1986, the Company
received notice from EPA-Region V that it was one of 832 potentially
responsible parties ("PRP") for the cleanup of the Maxey Flats Waste
Disposal Site. Documents obtained to date indicate that the Company
contributed 0.0162% of the waste disposed of at the site. A remedial
investigation and feasibility study has been completed. At this time,
the cost of the remedial action and EPA oversight is estimated to be
about $77.5 million. The EPA has offered a buyout agreement to
de minimis PRPs. Although a final agreement has not been executed,
the Company's buyout cost will be about $28,000. While liability for
cleanup under the Comprehensive Environmental Response, Compensation
and Liability Act ("Superfund") program is joint and several, the
amounts paid by the PRPs are usually related to their volumetric
contribution of waste to the site.
In November of 1986, the Company was notified by the DNR that it
was one of the several PRPs involved in the Holtz & Krause Landfill
located in Wausau, Wisconsin. The Company disposed of 12,516 cubic
yards of non-hazardous office waste and construction debris at the
site. This represents 1.02% of the total amount of waste at the site.
The landfill is currently being addressed only by the DNR. The
current work is not being conducted as part of the EPA's Superfund
program. The DNR has selected a remedy which is estimated to cost a
total of $11 million to $12 million. The DNR has agreed to contribute
approximately $4.5 million toward the remedy. Also, the county in
which the landfill is located has adopted a surcharge on the waste
disposal fee charged at the county's landfill to raise funds to assist
in the remediation. Clean Sites, Inc., a neutral cost allocation
expert, was retained by the Holtz & Krause PRP Group to develop an
allocation. The amount to be allocated to the Company, $37,163, was
paid to the cleanup fund in October of 1993. The DNR has indicated
that it will pursue a cost-recovery action against entities that do
not settle with the Holtz & Krause PRP Group. In 1994, the Company
entered into a Consent Decree that acknowledges the payment of the
settlement amount, requires the settling parties to clean up the site
and requires the state to pay its agreed upon contribution. In
addition, the Company entered into a "buyout" agreement with the
larger contributors of waste to the site in which the larger
contributors agreed to indemnify the Company for any cost overruns up
to a total site remedial cost of $20 million. If site remedial costs
-18-
exceed $20 million, the cost allocation may be reopened. Most of the
site work was completed in 1994.
In March of 1987, the Company was notified by the EPA that it was
a PRP for the cost of cleaning up the Rose Chemical site in Holden,
Missouri. Based on records that are available, a small amount of
polychlorinated biphenyl material, about 39,000 pounds, was sent to
the site. At this time, the Company has signed a participation
agreement for the cleanup and contributed $60,192 which is based on
the volumetric contribution of waste and the expected total cleanup
cost.
In November of 1988, the Company received notice from the DNR
that the Sherman Street property located in Wausau, Wisconsin, had
levels of lead contamination present. Based on an investigation
conducted by a neighboring business, Wausau Steel, it appears that
this contamination originates on an adjacent Wausau Steel property.
The cleanup of the property by Wausau Steel has been completed,
pending DNR approval.
In January 1995, the Company was notified that the EPA was
seeking to recover $775,442 from several companies, not including the
Company, that sent waste drums to the J. K. Drum site in New London,
Wisconsin. One of the companies notified by EPA requested the Company
to join a group to negotiate a settlement with the EPA. The Company's
records indicate that it contributed drums to the site which it
believes were empty. The Company is evaluating a response to the
notice.
E. REGULATORY MATTERS
GENERAL MATTERS. Utility rates, service and securities issues
of the Company are subject to regulation by the PSCW and the MPSC, and
the Company is subject to regulation of its wholesale electric rates,
hydroelectric projects and certain other matters by the FERC. It is
also subject to limited regulation by local authorities. The Company
follows Statement of Financial Accounting Standard No. 71, Accounting
for the Effects of Certain Types of Regulation, and its financial
statements reflect the effects of the different ratemaking principles
of the various jurisdictions. These include the PSCW, 89% of
revenues, the MPSC, 2% of revenues and FERC, 9% of revenues. The
operation of Kewaunee is subject to the jurisdiction of the
U. S. Nuclear Regulatory Commission.
In the Wisconsin jurisdiction, the rate process has been changed
effective in 1995 such that retail electric and natural gas rates will
be set every two years, rather than annually as has been the practice
in the past. The earliest that the rates which took effect January 1,
1995 could change would be for the year 1997. Customer rates are set
based on forecasted expenses and capital costs.
Wisconsin retail rates include an electric fuel-adjustment clause
based on a "cost variance range approach." This range is based on a
-19-
specific estimated fuel cost for the next year. If actual fuel costs
fall outside this range, a hearing may be held and an adjustment to
future rates may result. Automatic fuel-adjustment clauses are used
for FERC wholesale-electric and Michigan retail-electric portions of
the Company's business. The Company has a purchased gas adjustment
clause which allows it to pass on to all classes of gas customers
changes in the cost of gas purchased from its suppliers, subject to
PSCW and MPSC review.
CUSTOMER RATE MATTERS. In the Wisconsin jurisdiction, a
$17.4 million, or 4% electric rate reduction, and a $1 million, or .6%
natural gas rate increase, covering a one-year period, became
effective on January 1, 1994. Electric revenues were also reduced
$2 million, or .5% in May of 1994 as a result of reduced fuel costs.
Customer rates for 1994 reflected an authorized rate of return of
11.3% on common equity, down from 12.3% in 1993. The return on common
equity, when adjusted to reflect allowed earnings on deferred
investment tax credits, amounted to 11.9% and 13.0%, respectively, for
the years 1994 and 1993.
On December 19, 1994, the PSCW approved an electric rate
reduction of $10.9 million, or 2.6% to be effective on January 1, 1995
for the years 1995 and 1996. Natural gas rates remained unchanged.
The rates for 1995 and 1996 reflect an authorized rate of return on
common equity of 11.5% which when adjusted to reflect allowed earnings
on deferred investment tax credits is 12.18%. A capital structure
including 54% common equity was also approved.
No changes were made to Michigan electric and gas rates during
1994 other than through the fuel adjustment clauses. Likewise,
wholesale electric rates remained unchanged except for reductions
related to fuel costs.
PSCW INDUSTRY RESTRUCTURING PROCEEDING. On September 8, 1994,
the PSCW commenced a proceeding to consider the probable costs and
benefits of changing the structure and regulation of the electric
utility industry in Wisconsin. Changes in federal law, improvements
in the electric transmission system and technological advances suggest
that now is the time to prepare for, capture and maximize the benefits
of a changing and more market-oriented industry.
At its January 24, 1995 meeting, the PSCW identified the primary
objectives of the proceeding to be the creation of a system that sends
accurate price signals to customers resulting in the most economically
efficient use of resources; the creation of a system which maximizes,
within the public interest, the number and diversity of service
offerings to customers; and the creation of a system in which
providers maximize economic efficiency and environmental stewardship.
The PSCW has created an Advisory Committee ("Committee"),
consisting of twenty-two members, representing various constituencies,
including a Company member, which will examine every aspect of
electric service and determine which functions, if any, should be
performed by a competitive market and identify specific transitional
-20-
mechanisms that may be needed to create a workable competitive market
for these services. For services that have natural monopoly
characteristics, the Committee will explore whether new institutional
or regulatory policies could further benefit the public.
Following a period that includes public comment on the
Committee's recommendations, the Committee will submit its recommended
alternatives to the PSCW which will review the recommendations along
with outside comments before deciding the appropriate public policy
and commencing with implementation of its decision. The work of the
Committee is intended to be finished in time to allow the PSCW to
prepare a final report for the legislature on recommendations for
legislative changes by December 1, 1995.
ACCOUNTING DEVELOPMENTS. See Part II, Item 7, MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION, at page 29, for a discussion of accounting developments.
In addition, the staff of the U. S. Securities and Exchange
Commission has questioned certain of the current accounting practices
of the electric utility industry, including those of the Company,
regarding the recognition, measurement and classification of nuclear
decommissioning costs for nuclear generation facilities in the
financial statements of electric utilities. In response to these
questions, the Financial Accounting Standards Board has agreed to
review the accounting for nuclear decommissioning costs. If current
electric utility industry accounting practices for such
decommissioning are changed: (1) the annual provisions for
decommissioning could increase; and (2) the estimated cost for
decommissioning could be recorded as a liability rather than as
accumulated depreciation. The Company does not believe that such
changes, if required, would have an adverse effect on results of
operations due to its current and future ability to recover
decommissioning costs through customer rates.
The PSCW certified new straight-line depreciation rates which
became effective January 1, 1994 concurrent with the implementation of
new customer rates. The result was a reduction in annual depreciation
expense of approximately $5.8 million.
Regulatory assets represent probable future revenue associated
with certain costs which will be recovered from customers through the
ratemaking process. Regulatory liabilities represent costs previously
collected that are refundable in future rates. At December 31, 1994,
regulatory assets and liabilities amounted to $109.1 million and
$66.0 million, respectively. Based on prior and current rate
treatment of such deferred charges, management believes it is probable
that the Company will continue to recover these costs from ratepayers.
Pursuant to a PSCW rate order, effective January 1, 1995, the Company
is to recover approximately $23.6 million of deferred regulatory costs
each year.
DIVIDEND RESTRICTIONS. The Company is restricted by a PSCW order
to paying normal dividends of no more than 109% of the previous year's
-21-
common stock dividend without prior notice to the PSCW. Also,
Wisconsin law prohibits the Company from making loans to WPSR and its
non-regulated subsidiaries and from guaranteeing their obligations.
F. CAPITAL REQUIREMENTS
Anticipated construction expenditures for 1995 are $84.2 million,
of which $53.1 million, $1.3 million, $24.4 million, and $5.4 million
are for electric construction, nuclear fuel, gas construction, and
other construction expenditures, respectively. Approximately 60% of
the expenditures for 1995, and 97% of the anticipated total capital
expenditures of $150.6 million during 1996 and 1997, are expected to
be financed through internal sources. The Company does not expect to
sell equity or long-term debt during this period. Expenditures
related to the REC are not reflected in the above amounts because a
subsidiary of the Company anticipates entering into a project
financing arrangement with respect to the $169 million facility.
G. EMPLOYEES
At December 31, 1994, the Company employed 2,572 persons. Of
this number, 2,093 and 479 were considered electric and gas utility
employees, respectively.
Approximately 1,070 the Company employees are represented by
Local 310 of the International Union of Operating Engineers ("Union").
During 1994, the Union ratified a new contract with the Company which
provides for work force flexibility in that, for the duration of the
contract, Union employees can perform traditional union work across
craft lines, perform non-union work and perform work traditionally
performed by contractors; and non-union employees can perform some
union work. The current contract runs through October of 1997.
There has never been a strike against the Company by its employees.
-22-
PAGE
ITEM 2. PROPERTIES
The following table includes information about electric
generation facilities of the Company (including those jointly owned):
RATED
CAPACITY(a)
TYPE NAME LOCATION FUEL (KILOWATTS)
Steam Pulliam Green Bay, WI Coal 397,000 (b)
Weston Wausau, WI Coal or Gas 493,800 (c)
Kewaunee Kewaunee, WI Nuclear 216,300 (d)
Columbia -
Units 1 & 2 Portage, WI Coal 334,000 (d)
Edgewater
Unit 4 Sheboygan, WI Coal 104,600 (d)
----------
Total Steam 1,545,700
Hydro Various 68,900
(15 Plants)
Combustion Various Gas or Oil 264,400 (e)
Turbine (6 Plants)
& Diesel
----------
Total System 1,879,000
==========
(a) Based on 1994 winter capacity.
(b) This plant contains six units.
(c) This plant contains three units. Two units burn only coal and
the other can burn coal or natural gas.
(d) These facilities are jointly-owned. Kewaunee is operated by the
Company; WP&L is operator of the Columbia and Edgewater units.
The capacity indicated is the Company's portion of total plant
capacity based on percent of ownership.
(e) The Company and the Marshfield Electric and Water Department
jointly own 113,300 kilowatts of combustion turbine peaking
capacity which the Company operates. The capacity included is
the Company s portion of total plant capacity based on percent of
ownership.
The Company owns 51 transmission substations with a transformer
capacity of 5,253,000 kva; 107 distribution substations with a
transformer capacity of 2,821,000 kva; and 20,316 route miles of
electric transmission and distribution lines. Gas properties include
-23-
approximately 3,532 miles of main, 70 gate and city regulator stations
and 181,078 services. All gas facilities are located in Wisconsin
except for distribution facilities in and near the city of Menominee,
Michigan.
Substantially all of the Company's utility plant is subject to a
first mortgage lien.
ITEM 3. LEGAL PROCEEDINGS
SHEBOYGAN GAS PLANT. In November of 1990, the Company was
notified by the DNR that it may be a PRP for environmental
contamination found on property next to the Sheboygan River previously
used by the Company for the gasification of coal in the City of
Sheboygan, Wisconsin (the "Sheboygan II Gas Plant"). The Company last
used the property for this purpose in approximately 1930. In 1966,
the property was sold and is now owned by the City of Sheboygan. The
DNR has offered the Company the opportunity to investigate and
remediate the property under an agreement with the State of Wisconsin
as opposed to having the site handled by the EPA as part of the larger
Sheboygan River and Harbor Superfund site. The Company, the City of
Sheboygan and the State of Wisconsin have negotiated an agreement for
performing the work, and therefore, Wisconsin, and not the EPA, will
be handling this matter.
An initial study was completed on the site which confirmed the
presence of contaminants that appear to be related to the Sheboygan II
Gas Plant. A follow-up investigation was recommended by the
environmental consultant to determine more precisely the scope of the
contamination and to determine if any contamination is migrating from
off-site. The Company is awaiting approval from the DNR for the
additional work. After the follow-up investigation is completed, the
City of Sheboygan and the Company will negotiate an allocation of the
costs associated with cleanup of the site. Based on the initial
study, and a more detailed investigation of the Company's former
Oshkosh site, it is believed that the cost of cleanup for the
Sheboygan II Gas Plant site could be as much as $2.6 million. The
estimates presented above do not take into consideration any recovery
from insurance carriers or other third parties which the Company is
pursuing.
OSHKOSH GAS PLANT. In April of 1992, the Company received an
order from the DNR directing it to complete an investigation and
implement remedial activities on property owned by the Company in the
City of Oshkosh, Wisconsin. Previously, the Company had operated a
manufactured gas plant on the property from 1883 until 1946. A
challenge to the order was filed on May 8, 1992, and the Company and
the DNR have negotiated the terms of a consent order. An
environmental consultant conducted an investigation in late 1993 and a
more detailed investigation in 1994. Based on the more detailed
investigation, the cost of remediation is estimated to be as much as
$2.6 million. Additional studies are planned to define further the
area of contamination (primary river sediments). The results of these
-24-
studies may affect the cost estimate for remediation based on the
nature and extent of contamination. The City of Oshkosh has claimed
that contaminated groundwater from the former gas plant property has
migrated onto city-owned land. The Company has agreed to stay the
statute of limitations that may be applicable to the City of Oshkosh's
claim in order to avoid the filing of a lawsuit by the City of
Oshkosh. The Company is continuing to evaluate the validity of the
City of Oshkosh's claim as additional data is received. The estimates
presented above do not take into consideration any recovery from
insurance carriers or other third parties which the Company is
pursuing.
Incorporated herein by reference are the descriptions of the
various proceedings relating to environmental matters described under
D. ENVIRONMENTAL MATTERS, at pages 16 through 19, Item 1.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during
the fourth quarter of the fiscal year.
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information about outside directors is omitted for the reason
that such information will be included in a proxy statement for the
annual meeting of the shareholders of the parent company, WPSR, which
is scheduled to be held on May 4, 1995.
EXECUTIVE OFFICERS OF THE REGISTRANT
- ------------------------------------
Current Position and Business
Effective
Name and Age Experience During Past Five Years
Date
- ---------------------------- ------------------------------------
- ---------
DANIEL A. BOLLOM 58 President and Chief Executive Officer
03-01-91
President and Chief Operating Officer
06-01-89
DANIEL P. BITTNER 51 Senior Vice President-Customer
Service
05-09-94
Senior Vice President-Finance
03-01-92
Vice President-Treasurer
02-01-89
RICHARD A. KRUEGER 57 Senior Vice President-Sales and
Marketing
05-09-94
Senior Vice President-Power Supply
and Engineering
07-01-89
CLARK R. STEINHARDT 53 Senior Vice President-Nuclear Power
06-01-91
Vice President-Nuclear Power
06-01-90
Assistant Vice President-Nuclear Power
07-01-89
PATRICK D. SCHRICKEL 50 Senior Vice President-Finance and
Corporate Services
05-09-94
Senior Vice President-Operations
06-01-89
-25-
J. GUS SWOBODA 59 Senior Vice President-Human and
Corporate Development
05-09-94
Senior Vice President-Marketing and
Corporate Services
10-01-89
BERNARD J. TREML 45 Vice President-Human Resources
05-09-94
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 49 Vice President-Power Supply and
Engineering
05-09-94
Vice President-Energy Supply
01-01-92
Assistant Vice President-Energy Supply
07-01-90
Director-Fuel Services
09-16-85
RICHARD E. JAMES 41 Assistant Vice President-Corporate
Planning
05-09-94
Assistant Vice President-Rates and
Economic Evaluation
03-01-92
Manager-Rates and Economic Evaluation
01-01-89
ROBERT H. KNUTH 61 Assistant Vice President-Secretary
06-01-90
Secretary and Assistant Treasurer
05-11-78
DAVID W. SCHONKE 61 Assistant Vice President-Electric
Distribution Engineering
06-01-86
GLEN R. SCHWALBACH 49 Assistant Vice President-Gas
Engineering and Supply
06-01-90
Manager-Gas Engineering and Supply
06-01-89
RALPH G. BAETEN 51 Treasurer
03-01-92
Insurance and Benefits Director
05-01-87
DIANE L. FORD 41 Controller
03-01-92
Administrator-Corporate Accounting
05-01-87
FRANK J. KICSAR 55 Assistant Secretary
03-01-92
Director-Corporate Tax
10-01-76
NOTE: All ages are as of December 31, 1994. 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 or her
successor shall have been duly elected and qualified, or until
his or her death, resignation, disqualification or removal.
-26-
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The common stock of the Company has been wholly owned by WPSR
since the reorganization which was effective September 1, 1994 as
described in Part I, Item 1A, GENERAL, at page 1.
The Company is restricted by a PSCW order to paying normal
dividends of no more than 109% of the previous year's common stock
dividend without prior notice to the PSCW. Also, Wisconsin law
prohibits the Company from making loans to WPSR and its non-regulated
subsidiaries and from guaranteeing their obligations.
WPSR paid a normal dividend for the fourth quarter of 1994 in the
amount of $.455 per share. In addition, WPSR paid special dividends
in September and December of 1994 of $3.9 million and $13.0 million,
respectively.
COMMON STOCK Two-Year Comparison (1)
Share Data Dividends Per Share Price Range
High Low
1994 1st Quarter $ .445 33-5/8 28
2nd Quarter .445 30-3/4 27-3/8
3rd Quarter (2) .455 30-3/8 27
4th Quarter (2) .455 Not Publicly Traded
Total $1.80
1993 1st Quarter $ .435 34-3/4 30-1/8
2nd Quarter .435 35-3/8 32-1/8
3rd Quarter .445 36-1/2 33-3/4
4th Quarter .445 36 31-3/4
Total $1.76
- ----
(1) The dividends for all of 1993 and the first three quarters of 1994 were
paid by the Company to public shareholders. As a result of the
reorganization, the fourth quarter dividend for 1994 was paid to public
shareholders by WPSR.
(2) Special dividends are described in the third paragraph of this Item.
-27-
ITEM 6. SELECTED FINANCIAL DATA
A. SELECTED FINANCIAL DATA
==============================================================================
============================
1994 1993 1992
1991 1990 1984
(Millions)
- ------------------------------------------------------------------------------
- ----------------------------
Operating Revenues 662.8 680.6 634.8
623.5 589.0 644.2
Net Income 55.8 62.2 58.0
54.2 49.0 56.3
Total Assets (At December 31) 1,205.2 1,198.8 1,145.6
1,073.5 1,009.2 793.3
Long-Term Debt, Net (At December 31) 316.1 314.2 321.5
332.9 273.3 210.5
==============================================================================
===========================
B. FINANCIAL STATISTICS
==============================================================================
===============================================
===
Year Ended December 31 1994 1993
1992 1991 1990
1984
==============================================================================
===============================================
===
Coverage
Times interest earned before income taxes 4.19 4.49
3.99 4.00 3.74
6.27
Times interest earned after income taxes 3.09 3.29
3.01 3.03 2.84
3.74
Times interest and preferred dividends
earned after income taxes 2.77 2.93
2.71 2.70 2.53
2.92
==============================================================================
===============================================
===
Return on average equity 11.4% 13.1%
13.2% 13.1% 12.1%
16.2%
==============================================================================
===============================================
===
Capitalization ratios
Common equity including ESOP 53.9 54.3
52.6 49.0 53.4
53.2
Preferred stock 6.4 6.4
6.5 6.8 7.4
12.0
Long-term debt 39.7 39.3
40.9 44.2 39.2
34.8
==============================================================================
===============================================
===
Percent long-term debt to net utility plant 36.6 37.2
38.0 41.1 33.8
32.8
==============================================================================
===============================================
===
Average rate
Bonds 7.1 7.1
7.8 8.2 8.0
7.6
Preferred stock 6.1 6.1
6.3 6.3 6.3
7.6
==============================================================================
===============================================
===
Shareholders
Preferred stock 3,372 3,577
4,167 4,332 4,538
6,553
==============================================================================
===============================================
===
Number of employees 2,572 2,603
2,631 2,619 2,500
2,390
==============================================================================
===============================================
===
-28-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION
RESULTS OF OPERATIONS
OVERVIEW OF 1994 COMPARED TO 1993
Earnings on common stock declined from $58.9 million in 1993 to
$52.7 million in 1994, or 10.5%. The most significant reason for this
decrease was a Public Service Commission of Wisconsin ("PSCW") order
decreasing the authorized return on common equity for the Company from
12.3% to 11.3%, thereby reducing earnings approximately $3.8 million.
1994 COMPARED TO 1993
Electric margins (revenues less electric fuel expense and purchased
power) declined by $17.3 million, or 5.0%, due primarily to reduced
electric rates.
Electric operating revenues decreased $12.4 million, or 2.5%,
primarily due to a 4.2% reduction in Wisconsin retail rates that took
effect January 1, 1994. Electric rates also were reduced .5% in May
1994 as a result of reduced fuel costs. These decreases were
partially offset by a 4.0% increase in kilowatt-hour ("kwh") sales.
Residential, commercial and industrial kwh sales increased 2.4% and
4.9%, respectively, due to a warmer summer and customer growth.
Wholesale kwh sales increased 3.0%.
Electric fuels and purchases increased $4.9 million, or 3.4%,
reflecting increased sales, offset in part by reduced production
costs. Electric production fuels decreased $3.0 million, or 2.7%,
even though generation was up 1.3%. This decrease in fuel costs per
kwh of 5.4% primarily was the result of purchasing less expensive coal
on the spot market. Purchased power costs were higher by
$7.9 million, or 25.8%. This was the result of a 19.9% increase in
kwh purchases, due to the severe cold weather in the first quarter of
the year, which forced WPSC to purchase expensive spot market
electricity, and the Soo Line railroad strike during the second half
of the year which impacted WPSC s ability to operate its coal-fired
units.
Gas margins (revenues less the cost of gas) increased by $1.7 million,
or 3.6%, due to customer growth. The PSCW allows WPSC to pass on to
its customers, through a purchased gas adjustment clause, changes in
the cost of gas.
Maintenance expense decreased $1.6 million, or 3.1%, due to lower
maintenance activity at the Kewaunee Nuclear Power Plant ("Kewaunee")
and to less electric transmission and distribution maintenance.
Depreciation and decommissioning expense decreased $4.2 million, or
7.0%. The primary cause was a rate order from the PSCW which took
effect January 1, 1994 reducing the annual depreciation provision by
-29-
an estimated $5.8 million. This was offset by higher decommissioning
expense of approximately $1.1 million.
Federal and state income taxes decreased $3.0 million, or 9.1%, due to
lower earnings.
1993 COMPARED TO 1992
Electric operating revenues increased $15.6 million, or 3.3%. This
increase was the result of a 4.2% increase in kwh sales and a 2.1%
rate increase for WPSC's Wisconsin retail customers that was effective
January 1, 1993. This was partially offset by rate reductions
totaling $1.1 million in September and November 1993 for Wisconsin
retail customers due to reduced fuel costs. Residential sales
increased $8.9 million, or 5.7%, due primarily to warmer summer
weather. Commercial and industrial sales rose $13.3 million, or 5.3%,
reflecting customer growth and the impact of the warmer weather.
Wholesale sales decreased $4.5 million, or 7.4%, due to an average
rate reduction for this customer class of 6.7%.
Electric production fuel costs decreased $9.8 million, or 7.9%, even
though electric generation was up 2.1%. This decrease primarily was
the result of less expensive coal which was purchased on the spot
market. Such purchases decreased overall coal-related costs per kwh
by 11.8% and reduced coal costs by approximately $14.2 million between
years.
Gas operating revenues increased $30.2 million, or 19.2%. This
increase primarily is due to a 10.1% increase in the cost of gas
($12.2 million), reflecting spot market volatility, a 3.2% increase in
heating-degree days ($12.5 million) and a 2.3% Wisconsin retail rate
increase ($5.5 million) effective January 1, 1993. Residential gas
revenues increased $17.3 million, and commercial and industrial gas
revenues increased $14.6 million.
Gas purchased for resale increased $23.5 million, or 21.3%, due to
higher gas volumes of 10.4% and to a 10.1% higher average cost of gas
per therm.
Other operating expenses increased $12.7 million, or 9.3%, primarily
due to increased amortization of 1991 coal and associated rail
contract buy-out costs of $2.9 million and increased electric and gas
conservation expenses of $9.7 million.
Maintenance expense increased $5.1 million, or 11.1%, primarily due to
additional maintenance activities at WPSC's coal-fired power plants.
Federal and state income taxes increased $5.9 million, or 21.7%, due
to higher pre-tax income and the effect of an increase in the federal
income tax rate from 34% to 35%, as provided in the Revenue
Reconciliation Act of 1993.
-30-
BALANCE SHEET
1994 COMPARED TO 1993
Accrued utility revenues decreased $8.5 million as a result of
unseasonably warm weather experienced in December 1994.
Long-term liabilities increased $20.6 million primarily due to higher
estimates for environmental remediation of $10.4 million and post-
retirement health care costs of $7.0 million.
FINANCIAL CONDITION
The Company requires large investments in capital assets used to
deliver electric and gas services. The Company maintains good
liquidity levels and a financial condition considered to be strong by
analysts. Internally generated funds closely approximate the
utility's cash requirements. No external funding difficulties are
anticipated in the future. Pre-tax interest coverage was 4.2 times
for the year ended December 31, 1994. WPSC's bond ratings are AA+
(Standard & Poor's), Aa2 (Moody's) and AA+ (Duff & Phelps).
The Company is restricted by a PSCW order to paying normal dividends
of no more than 109% of the previous year's common stock dividend
without prior notice to the PSCW. Also, Wisconsin law prohibits the
Company from making loans to WPS Resources Corporation (WPSR), the
Company's parent, and its subsidiaries and from guaranteeing their
obligations.
For the three-year period 1995 to 1997, internally-generated funds at
the Company are expected to lag behind construction expenditures,
which total $235 million, by $38 million. The Company currently
expects to finance this shortfall in internally generated funds with
short-term debt. These expenditures are comprised of $148 million for
electric construction, $20 million for nuclear fuel, $48 million for
gas construction and $19 million for other construction expenditures.
These construction costs exclude the Rhinelander Energy Center ("REC")
which will be substantially funded with non-recourse project financing
debt.
The PSCW has approved the REC as the preferred electric generating
project to meet the Company's expanding capacity and energy needs.
This approval followed a competitive bidding process. The REC will be
built and operated by non-regulated subsidiaries of the Company. REC
will be a coal-fired, 122-megawatt, $169 million cogeneration facility
which will produce steam and electricity for sale to the Rhinelander
Paper Company and electricity for sale to utility customers. Before
construction commences, the PSCW must certify that the REC satisfies a
public need. PSCW approval is expected in the second half of 1995.
The plant is expected to be placed in service in 1998.
Kewaunee is currently licensed through the year 2013. Physical
decommissioning is expected to occur during the period 2014 to 2021
-31-
with additional expenditures being incurred during the period 2022 to
2050. Decommissioning costs in current dollars are $147 million, and
the undiscounted amount is $785 million. As of December 31, 1994,
$64.1 million has been placed in external trusts to cover these future
costs. Management does not anticipate decommissioning to have any
negative impacts on the Company's liquidity or capital resources,
since these costs are currently recovered from customers and funded
through external decommissioning trusts.
The Company received a two-year rate order from the PSCW which became
effective January 1, 1995. This rate order decreased electric retail
rates by 2.6% and kept retail gas rates at current levels. This order
also increased the authorized rate of return on common equity from
11.3% to 11.5%.
Statement of Financial Accounting Standards ("SFAS") No. 112,
Employers Accounting for Post-Employment Benefits, became effective
in 1994. This statement establishes the accounting and reporting
standard for the estimated cost of benefits provided by an employer to
former or inactive employees after employment but before retirement.
The effect of this statement was not material.
SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities, became effective in 1994. This statement establishes the
accounting and reporting standard for investments in debt and
marketable equity securities. This standard primarily impacts nuclear
decommissioning investments. The effect of this statement was not
material.
SFAS No. 119, Disclosure about Derivative Financial Instruments and
Fair Value of Financial Instruments, also became effective in 1994.
This statement establishes disclosure requirements for derivatives.
As of December 31, 1994, the Company had no derivatives.
TRENDS
The Company follows SFAS No. 71, Accounting for the Effects of Certain
Types of Regulation, and its financial statements reflect the effects
of the different ratemaking principles followed by the various
jurisdictions regulating the utility. These include the PSCW, 89% of
revenues, the Michigan Public Service Commission, 2% of revenues, and
the Federal Energy Regulatory Commission ("FERC"), 9% of revenues. In
addition, Kewaunee is regulated by the Nuclear Regulatory Commission.
Environmental matters are primarily governed by the Environmental
Protection Agency and the Wisconsin Department of Natural Resources.
The single most important development in the electric utility industry
is the trend toward increased competition brought about by a
combination of new legislation, changing regulation and market forces.
Transmission access, mandated by the Energy Policy Act of 1992,
increased competition in the wholesale power segment of the business
and put pressure on profit margins. Certain segments of the industry
-32-
could become deregulated. Low-cost energy producers, such as the
Company, are in a position to benefit from competitive markets.
The PSCW has initiated a proceeding to consider restructuring electric
utility regulation in Wisconsin. Matters to be addressed include:
- Whether generation, transmission and distribution functions
will be allowed to exist together in the same company.
- Whether retail wheeling should be allowed.
- Whether utilities should be obligated to serve those
customers who have the ability to choose between alternate
suppliers.
- Whether utilities will be given the ability to price
services based on market factors rather than the traditional
regulatory-pricing model.
- The treatment of stranded investment in utility plant and
regulatory assets.
The Company has accrued $26.9 million for the future environmental
remediation of eight manufactured gas plant sites which it operated
previously. This accrual is based on studies at two sites and was
used as the basis for projecting costs on the remaining six sites.
The range of cleanup costs for all eight sites is estimated to be from
$14.8 million to $29.3 million.
These estimates will be adjusted as additional site-specific studies
are completed, three of which are anticipated in 1995. Factors that
can impact future cost estimates include the volume of contaminated
soil and changes in remedial technology and regulatory requirements.
A recent Wisconsin rate order provides that these costs may be
recovered from customers over a five-year period after expenditures
are incurred, but that no return on unrecovered costs is permitted.
The estimated cleanup costs presented do not take into consideration
recovery from insurance carriers or other third parties. In June
1994, the Wisconsin Supreme Court ("Court") held that insurance
coverage was not available for environmental cleanup costs to the
extent the clean up is done to prevent or mitigate future injury. The
Court also held that a notification letter from a government agency
about an environmental situation did not constitute a suit, triggering
the insurers' duty to defend. The Company is exploring alternative
approaches for pursuing claims against carriers in light of the
decision.
In addition, the Company has been notified that it is a minor
participant in a number of waste disposal site cleanup efforts.
However, no significant costs are anticipated to clean up these sites.
Federal Clean Air Act Amendments ("Act") were enacted in 1990. The
Act establishes stringent sulfur dioxide and nitrogen oxide emission
-33-
limitations. Wisconsin previously had enacted laws to limit sulfur
emissions. The Company meets the sulfur dioxide emission standards
scheduled to take effect in the year 2000 as a result of switching to
lower-sulfur fuels. However, some additional capital expenditures
will be required to upgrade existing equipment and to monitor emission
levels. These expenditures are estimated to be in the range of
$15 million to $25 million between 1995 and 1999.
The steam generator tubes at Kewaunee are susceptible to corrosion
characteristics seen throughout the nuclear industry. Annual
inspections are performed to identify degraded tubes which are either
repaired by sleeving or are removed from service by plugging. The
steam generators were designed with approximately a 15% heat-transfer
margin, meaning that full power should be sustainable with the
equivalent of 15% of the steam generator tubes plugged. Tube plugging
and the build-up of deposits on the tubes affect the heat-transfer
capability of the steam generators to the point where eventually full
power operation is not possible, and there is a gradual decrease in
the capacity of the plant. The plant s capacity could be reduced by
as much as 20% by the year 2013. To date, approximately 12% of the
tubes have been plugged, with no reduction in capacity. The Company
continues to evaluate the operation of the steam generators without
replacement and appropriate repair strategies, including replacement.
The Company also continues to evaluate and implement initiatives to
improve the performance of Kewaunee which already performs at above-
average levels for the industry. These initiatives include conversion
from a twelve-month to an eighteen-month refueling and major
maintenance cycle, beginning in the spring of 1995, and numerous other
cost-reduction measures. These initiatives have resulted in
approximately a 25% reduction in Kewaunee operating and maintenance
costs since 1991. The Company intends to operate Kewaunee until at
least the expiration of the present operating license in 2013.
In 1995, the Company is initiating a new demand-side management
("DSM") program which involves loans and shared savings. Prior to
1995, DSM expenditures were recovered from all customers. The new
program provides that those who benefit from energy-saving programs
will finance them. As of December 31, 1994, the Company had
$46.5 million of deferred DSM expenditures which will be recovered in
future rates.
Local 310 of the International Union of Operating Engineers,
representing 1,070 of the Company's employees, ratified a new three-
year contract with the Company. The agreement provides for work force
flexibility in that, for the duration of the contract, Union employees
can perform traditional union work across craft lines, perform non-
union work and perform work traditionally performed by contractors;
and non-union employees can perform some union work. The flexibility
that this contract provides will allow the Company to more easily
adapt to the changing utility environment.
-34-
IMPACT OF INFLATION
Current financial statements are prepared in accordance with generally
accepted accounting principles and report operating results in terms
of historic cost. They provide a reasonable, objective and
quantifiable statement of financial results, but they do not evaluate
the impact of inflation. Under rate treatment prescribed by the
utility s regulatory commissions, projected operating costs are
recoverable in revenues. Because forecasts are prepared assuming
inflation, the majority of inflationary effects on normal operating
costs are recoverable in rates. However, in these forecasts, the
Company is allowed to recover the historical cost of plant via
depreciation.
Although new rates will not be implemented in 1996 due to the two-year
rate order in the Wisconsin jurisdiction, management believes
inflation will be offset by the impact of customer growth and
increased productivity.
-35-
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31
1994
1993 1992
----
---- ----
(Thousands)
Operating Revenues:
Electric $
480,816 $ 493,256 $ 477,625
Gas
182,058 187,376 157,177
- -------- -------- --------
662,874 680,632 634,802
- -------- -------- --------
Operating Expenses:
Operation -
Electric production fuels
111,011 114,051 123,866
Purchased power
38,631 30,703 29,594
Gas purchased for resale
126,351 133,347 109,890
Other
148,382 148,270 135,614
Maintenance
49,983 51,597 46,436
Depreciation and decommissioning
56,365 60,609 58,592
Taxes -
Federal income
24,082 27,654 23,147
Investment credit restored
(2,038) (1,860) (2,022)
State income
7,768 7,313 6,081
Gross receipts and other
26,063 25,204 24,459
- -------- -------- --------
586,598 596,888 555,657
- -------- -------- --------
Operating Income
76,276 83,744 79,145
- -------- -------- --------
Other Income and (Deductions):
Allowance for equity funds used during construction
108 287 494
Other, net
4,750 3,356 6,076
Income taxes
(228) 568 (1,116)
- -------- -------- --------
4,630 4,211 5,454
- -------- -------- --------
Income Before Interest Expense
80,906 87,955 84,599
- -------- -------- --------
Interest Expense:
Interest on long-term debt
23,410 24,393 25,662
Allowance for borrowed funds used during construction
(139) (200) (542)
Other interest
1,793 1,562 1,477
- -------- -------- --------
25,064 25,755 26,597
- -------- -------- --------
Net Income
55,842 62,200 58,002
Preferred Stock Dividend Requirements
3,111 3,311 3,237
- -------- -------- --------
Earnings On Common Stock $
52,731 $ 58,889 $ 54,765
======== ======== ========
The accompanying notes are an integral part of these statements.
-36-
B. CONSOLIDATED BALANCE SHEETS
December 31
1994 1993
- ------------ ------------
(Thousands)
Assets
Utility Plant:
In service - Electric $
1,412,666 $ 1,374,662
Gas
202,897 183,798
- ------------ ------------
1,615,563 1,558,460
Less - Accumulated provision for depreciation and decommissioning
846,505 801,056
- ------------ ------------
769,058 757,404
Nuclear decommissioning trusts
64,147 56,699
Construction in progress
11,131 11,781
Nuclear fuel, less accumulated amortization
19,417 17,981
- ------------ ------------
Net utility plant
863,753 843,865
- ------------ ------------
Current Assets:
Cash and equivalents
3,449 5,391
Customer and other receivables, net of reserves
58,036 66,511
Accrued utility revenues
28,820 37,314
Fossil fuel, at average cost
10,505 10,208
Gas in storage, at average cost
15,783 19,885
Materials and supplies, at average cost
20,585 19,411
Prepayments and other
21,091 21,420
- ------------ ------------
Total current assets
158,269 180,140
- ------------ ------------
Regulatory Assets
109,135 110,750
Investments and Other Assets
74,069 64,086
- ------------ ------------
$
1,205,226 $ 1,198,841
============ ============
Capitalization and Liabilities
Capitalization:
Common stock equity $
429,953 $ 434,503
Preferred stock with no mandatory redemption
51,200 51,200
Long-term debt to Parent
6,176 --
Long-term debt
309,945 314,225
- ------------ ------------
Total capitalization
797,274 799,928
- ------------ ------------
Current Liabilities:
Notes payable
10,002 10,000
Commercial paper
12,500 11,000
Accounts payable
65,336 64,113
Accrued taxes
1,199 3,266
Accrued interest
8,068 7,695
Other
6,627 9,956
- ------------ ------------
Total current liabilities
103,732 106,030
- ------------ ------------
Other Long-Term Liabilities and Deferred Credits:
Accumulated deferred income taxes
127,126 138,952
Accumulated deferred investment credits
32,172 34,210
Regulatory liabilities
65,995 61,434
Long-term liabilities
78,927 58,287
- ------------ ------------
304,220 292,883
- ------------ ------------
Commitments and Contingencies (See Note 6)
- ------------ ------------
$
1,205,226 $ 1,198,841
============ ============
The accompanying notes are an integral part of these balance sheets.
-37-
C. CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
1994
1993
- ---------- ----------
(Thousands)
COMMON STOCK EQUITY:
Common stock $
95,588 $ 95,588
Premium on capital stock
73,605 73,605
Retained earnings
280,730 288,693
ESOP loan guarantees
(19,970) (23,383)
- ---------- ----------
Total common stock equity
429,953 434,503
- ---------- ----------
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
5.04% 30,000
3,000 3,000
5.08% 50,000
5,000 5,000
6.76% 150,000
15,000 15,000
6.88% 150,000
15,000 15,000
- ---------- ----------
Total preferred stock
51,200 51,200
- ---------- ----------
LONG-TERM DEBT TO PARENT:
Series Year Due
------ --------
8.76% 2014
6,176 -
- ---------- ----------
LONG-TERM DEBT:
First mortgage bonds -
Series Year Due
------ --------
5-1/4% 1998
50,000 50,000
7.30% 2002
50,000 50,000
6.80% 2003
50,000 50,000
6-1/8% 2005
9,075 9,075
6.90% 2013
22,000 22,000
10-1/8% 2014
- - 1,000
8.80% 2021
60,000 60,000
7-1/8% 2023
50,000 50,000
- ---------- ----------
291,075 292,075
Unamortized discount and premium on bonds, net
(1,153) (1,257)
- ---------- ----------
Total first mortgage bonds
289,922 290,818
ESOP loan guarantees
19,970 23,383
Other long-term debt
53 24
- ---------- ----------
Total long-term debt
309,945 314,225
- ---------- ----------
Total capitalization $
797,274 $ 799,928
========== ==========
The accompanying notes are an integral part of these statements.
-38-
D. CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
1994
1993 1992
- ----------- ----------- -----------
(Thousands)
Cash Flows From Operating Activities:
Net income $
55,842 $ 62,200 $ 58,002
Adjustments to reconcile net income to net cash from
operating activities -
Depreciation and decommissioning
56,365 60,609 58,592
Amortization of nuclear fuel and other
28,811 27,693 20,522
Deferred income taxes
(4,476) (867) 7,266
Investment credit restored
(2,038) (1,860) (2,022)
AFUDC equity
(108) (287) (494)
Pension
(10,808) (9,830) -
Post retirement
7,036 5,915 -
Deferred demand-side management expenditures
(9,659) (18,988) (32,073)
Other, net
(11,037) 14,367 2,688
Changes in -
Customer and other receivables
8,475 (3,938) 3,100
Accrued utility revenues
8,494 (3,434) (4,335)
Fossil fuel
(297) (5,565) 2,788
Gas in storage
4,102 (8,264) (9,807)
Accounts payable
1,223 8,813 (6,886)
Miscellaneous current and accruals
(5,514) 240 2,068
Accrued taxes
(2,067) 2,032 3,425
- ----------- ----------- -----------
Net cash from operating activities
124,344 128,836 102,834
- ----------- ----------- -----------
Cash Flows From (Used For) Investing Activities:
Construction and nuclear fuel expenditures
(68,819) (68,654) (95,211)
Decommissioning funding
(7,448) (5,676) (5,518)
Sale of interest in combustion turbine
- - 7,849 -
Other
2,429 3,515 4,234
- ----------- ----------- -----------
Net cash from (used for) investing activities
(73,838) (62,966) (96,495)
- ----------- ----------- -----------
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
Proceeds from long term debt from parent
6,176 - -
Redemption and maturities of first mortgage bonds
(1,000) (189,973) (55,765)
Change in commercial paper
1,502 1,000 7,000
Preferred stock dividends
(3,111) (3,332) (3,237)
Common stock dividends
(56,015) (42,045) (40,150)
- ----------- ----------- -----------
Net cash from (used for) financing activities
(52,448) (60,657) (6,638)
- ----------- ----------- -----------
Net Increase (Decrease) in Cash and Equivalents
(1,942) 5,213 (299)
Cash and Equivalents at Beginning of Year
5,391 178 477
- ----------- ----------- -----------
Cash and Equivalents at End of Year $
3,449 $ 5,391 $ 178
=========== =========== ===========
Cash Paid During Year For:
Interest, less amount capitalized
$20,693 $21,973 $22,678
Income taxes
$40,333 $33,177 $18,301
Construction and nuclear fuel expenditures, including
accruals, AFUDC and customer contributions
$78,286 $72,731 $102,281
The accompanying notes are an integral part of these statements.
-39-
E. CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year
Ended December 31
1994
1993 1992
----------
- ---------- ----------
(Thousands)
Balance at Beginning of Year $ 288,693 $
272,019 $ 257,404
Add - Net income 55,842
62,200 58,002
----------
- ---------- ----------
344,535
334,219 315,406
----------
- ---------- ----------
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) 1,032
384 -
7.72% Series ($7.72 per share) -
868 1,158
Dividends declared on common stock 59,915
42,045 40,150
Other 779
150 -
----------
- ---------- ----------
63,805
45,526 43,387
----------
- ---------- ----------
Balance at End of Year $ 280,730 $
288,693 $ 272,019
==========
========== ==========
The accompanying notes are an integral part of these statements.
-40-
F. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) BUSINESS - Wisconsin Public Service Corporation ("Company")
is a public utility operating company engaged in supplying
electrical energy and natural gas to its customers who are
located primarily in northeastern Wisconsin and Upper
Michigan. The Company follows Statement of Financial
Accounting Standards ("SFAS") No. 71, Accounting for the
Effects of Certain Types of Regulation, and its financial
statements reflect the effects of the different ratemaking
principles followed by the various jurisdictions regulating
the company. These include the Public Service Commission of
Wisconsin ("PSCW"), 89% of revenues, the Michigan Public
Service Commission ("MPSC"), 2% of revenues, and the Federal
Energy Regulatory Commission ("FERC"), 9% of revenues.
(b) CORPORATE REORGANIZATION - On September 1, 1994,
WPS Resources Corporation ("WPSR"), pursuant to a one-for-
one share exchange, acquired all of the common stock of the
Company. As a result, the Company became a wholly-owned
subsidiary of the WPSR.
(c) CONSOLIDATION - The consolidated financial statements
include the Company and its wholly-owned subsidiary,
WPS Leasing, Inc. All significant intercompany transactions
and accounts have been eliminated.
(d) UTILITY PLANT - Utility plant is stated at the original cost
of construction which includes an allowance for funds used
during construction ("AFUDC"). Approximately 50% of retail
jurisdictional construction work in progress ("CWIP"),
except for major new generating facilities which earn AFUDC
on the full amount, is subject to AFUDC using a rate based
on the Company's overall cost of capital. For 1994, the
retail AFUDC rate was approximately 10.1%.
AFUDC is recorded on wholesale jurisdictional electric
construction work in progress at debt and equity percentages
specified in the FERC Uniform System of Accounts. For 1994,
this rate was approximately 4.3%.
Substantially all of the Company's utility plant is subject
to a first mortgage lien.
(e) PROPERTY ADDITIONS, MAINTENANCE AND RETIREMENTS - The cost
of renewals and betterments of units of property (as
distinguished from minor items of property) is charged to
utility plant accounts. The cost of units of property
retired, sold or otherwise disposed of, plus removal costs,
less salvage, is charged to the accumulated provision for
depreciation. No profit or loss is recognized in connection
-41-
with ordinary retirements of utility property units.
Maintenance and repair costs and replacement and renewal of
items less than units of property are generally charged to
operating expense.
In October 1993, the Company sold, at cost, a 32% interest
in a combustion turbine to a municipality for $7.8 million.
(f) DEPRECIATION - Straight-line composite depreciation expense
is recorded over the estimated useful life of the property
and includes estimated salvage and cost of removal. These
rates have been approved by the PSCW. Effective January 1,
1994, depreciation rates were revised based on new estimates
which decreased annual depreciation expense by approximately
$5.8 million. This decrease was considered in setting
customer rates.
=============================================================
1994 1993 1992
-------------------------------------------------------------
ANNUAL COMPOSITE DEPRECIATION RATES
Electric 3.41% 3.89% 3.87%
Gas 3.37% 3.81% 3.81%
=============================================================
(g) NUCLEAR DECOMMISSIONING - Nuclear decommissioning costs are
accrued over the estimated service life of the Kewaunee
Nuclear Power Plant ("Kewaunee"), currently recovered from
customers in rates and deposited in external trusts. Such
costs totaled $4.0, $2.4 and $2.4 million for 1994, 1993 and
1992, respectively. In July 1994, the PSCW issued a generic
order covering utilities with nuclear generation. This order
standardizes the escalation assumptions used in determining
nuclear decommissioning liabilities. The undiscounted
amount of decommissioning costs estimated to be expended
between the years 2014 to 2050 are $785 million. Long-term
after-tax earnings of 5.5% are assumed. As a result of this
change, annual decommissioning costs recovered in customer
rates in 1995 will be approximately $8.7 million. As of
December 31, 1994, the accumulated provision for
depreciation and decommissioning included accumulated
provisions for decommissioning totaling $64.1 million.
The Company's share of Kewaunee decommissioning costs are
estimated to be $147 million in current dollars based on a
site-specific study, performed in 1992, using immediate
dismantlement as the method of decommissioning. As of
December 31, 1994, the external trusts totaled $64.1 million
and were valued at market.
Depreciation expense includes decommissioning costs
recovered in customer rates and a charge to offset earnings
from the external trusts. Trust earnings totaled $2.4, $3.5
and $3.3 million for the years ended December 31, 1994, 1993
and 1992, respectively.
-42-
(h) NUCLEAR FUEL - The cost of nuclear fuel is amortized to
electric production fuel expense based on the quantity of
heat produced for the generation of electric energy by
Kewaunee. The costs amortized to electric fuel expense
(which assume no salvage values for uranium or plutonium)
include an amount for ultimate disposal and are recovered
through current rates. As required by the Nuclear Waste
Policy Act of 1982, a contract with the Department of Energy
("DOE") has been signed, and quarterly payments are being
made to the DOE for the fuel storage based on generation.
Interim storage space for spent nuclear fuel is provided at
Kewaunee, and expenses associated with this storage are
recognized as current operating costs. Currently, there is
on-site storage capacity for spent fuel through the year
2013. As of December 31, 1994 and 1993, the accumulated
provisions for nuclear fuel totaled $136.5 million and
$130.0 million, respectively.
(I) CASH AND EQUIVALENTS - The Company considers short-term
investments with an original maturity of three months or
less to be cash equivalents.
(j) REVENUE AND CUSTOMER RECEIVABLES - The Company accrues
revenues related to electric and gas service, including
estimated amounts for service rendered but not billed.
As of December 31, 1994, energy conservation loans to
customers amounting to $1.7 million are included in customer
receivables and in investments and other assets. The
carrying amount of the loans closely approximates their
market value.
Automatic fuel-adjustment clauses are used for FERC
wholesale-electric and MPSC retail-electric portions of the
Company s business. The PSCW retail-electric portion of the
business uses a cost variance range approach. This range
is based on a specific estimated annual fuel cost. If the
Company's actual fuel costs fall outside this range, a
hearing may be held and an adjustment to future rates may
result. The Company has a purchased gas adjustment clause
which allows it to pass on to all classes of gas customers
changes in the cost of gas purchased from its suppliers,
subject to PSCW and MPSC review.
The Company is required to provide service and grant credit
to customers within its defined service territory and is
precluded from discontinuing service to residential
customers during certain periods of the year. The Company
continually reviews its customers' credit-worthiness and
obtains deposits or refunds deposits accordingly. The
Company is permitted to recover bad debts in utility rates.
Approximately 8% of the Company's total revenues are from
companies in the paper products industry.
-43-
(k) REGULATORY ASSETS AND LIABILITIES - The Company is subject
to the provisions of SFAS No. 71, Accounting for the Effects
of Certain Types of Regulation. Regulatory assets represent
probable future revenue associated with certain costs which
will be recovered from customers through the ratemaking
process. Regulatory liabilities represent costs previously
collected that are refundable in future rates. The
following regulatory assets and liabilities were reflected
in the Consolidated Balance Sheets as of December 31:
============================================================
(Thousands) 1994 1993
------------------------------------------------------------
REGULATORY ASSETS
DSM expenditures $46,510 $ 46,219
Coal and rail contract
buy-out costs 18,228 24,269
Environmental remediation
costs 27,361 16,667
Debt refinancing costs 5,314 7,725
Enrichment facility fee 6,744 5,830
Natural gas obligations 1,856 3,713
Other 3,122 6,327
------------------------------------------------------------
TOTAL $109,135 $110,750
============================================================
REGULATORY LIABILITIES
Income tax related $38,599 $33,030
Pensions 17,342 22,021
Conservation costs 7,221 3,494
Other 2,833 2,889
------------------------------------------------------------
TOTAL $65,995 $61,434
============================================================
As of December 31, 1994, most of the Company's regulatory
assets are being recovered through rates charged to
customers over periods ranging from two to ten years.
Pursuant to a PSCW rate order, effective January 1, 1995,
the Company is to recover approximately $23.6 million of
regulatory costs in 1995 and 1996.
Based on prior and current rate treatment of such costs,
management believes it is probable that the Company will
continue to recover from ratepayers the deferred charges
described above.
See notes (1)(m) and (1)(n) for specific discussion of
pension and deferred tax regulatory liabilities, and note 6
for discussion of environmental-remediation deferred costs.
(l) INVESTMENTS AND OTHER ASSETS - Investments include various
immaterial affiliates whose income is included in other
income and deductions using the equity method of accounting.
-44-
Other assets include prepaid pension assets, operating
deposits for jointly-owned plants, the cash surrender value
of life insurance policies and the long-term portion of
energy conservation loans to customers.
(m) EMPLOYEE BENEFIT PLANS - The Company has non-contributory
retirement plans covering substantially all employees under
which annual contributions are made to an irrevocable trust
established to provide retired employees with a monthly
payment if conditions relating to age and length of service
have been met. The plans are fully funded, and no
contributions were made in 1994, 1993 or 1992. Prior to
January 1, 1993, the PSCW required the recognition of the
funded amounts for ratemaking purposes. Concurrent with a
rate order, effective January 1, 1993, the Company began
recovering pension costs in customer rates under SFAS
No. 87, Employers Accounting for Pensions, and began
returning to ratepayers, over five years, the cumulative
excess of amounts recovered from customers over SFAS No. 87
costs.
The tables below set forth the plans' funded status and
expense (income).
==============================================================================
============
As of December 31 (Thousands, except for percentages)
1994 1993
- ------------------------------------------------------------------------------
- ------------
Vested benefit obligation
$(162,435) $(162,304)
Non-vested benefit obligation
(7,868) (8,084)
- ------------------------------------------------------------------------------
- ------------
TOTAL ACTUARIAL PRESENT VALUE
OF ACCUMULATED BENEFIT OBLIGATION
$(170,303) $(170,388)
==============================================================================
============
Projected benefit obligation for service rendered to
date $(231,134) $(235,661)
Plan assets at fair value
329,424 342,540
- ------------------------------------------------------------------------------
- ------------
Plan assets in excess of projected benefit obligation
98,290 106,879
Unrecognized net gain
(47,670) (59,024)
Prior service cost not yet recognized
6,297 7,044
Unrecognized net asset
(26,920) (30,384)
- ------------------------------------------------------------------------------
- ------------
PREPAID RETIREMENT PLAN COST
$ 29,997 $ 24,515
==============================================================================
============
THE NET RETIREMENT PLAN EXPENSE (INCOME) INCLUDES
THE FOLLOWING COMPONENTS
1994 1993 1992
---- ---- ----
Service cost
$ 6,333 $ 5,935 $ 4,251
Interest cost
17,308 16,375 15,003
Actual return on plan assets
2,555 (37,856) (25,826)
Net amortization and deferral
(31,678) 11,042 463
Regulatory adjustment to funded amount
(5,326) (5,326) 6,109
- ------------------------------------------------------------------------------
- ------------
Net retirement plan expense (income)
$(10,808) $ (9,830) $ -
==============================================================================
============
THE ASSUMED RATES FOR CALCULATIONS USED IN
THE ABOVE TABLES WERE
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
8.00% 7.50% 7.50%
==============================================================================
============
The Company also offers medical, dental and life insurance
benefits to employees, retirees and their dependents. The
expenses for active employees are expensed as incurred.
-45-
Prior to 1993, the Company expensed amounts related to post-
retirement health and welfare plans to the extent that such
amounts were funded to external trusts.
Effective January 1, 1993, and concurrent with a rate order,
the Company adopted SFAS No. 106, Employers' Accounting for
Post-Retirement Benefits Other Than Pensions, which requires
the cost of post-retirement benefits for employees to be
accrued as expense over the period in which the employee
renders service and becomes eligible to receive benefits.
In adopting SFAS No. 106, the Company elected to recognize
the transition obligation for current and future retirees
over twenty years.
Since 1981, the Company has been funding amounts to
irrevocable trusts as allowed for income tax purposes.
These funded amounts have been expensed and recovered
through customer rates. The investments in the trust
covering administrative employees are subject to federal
income taxes at a 39.6% tax rate, while the non-
administrative trust is tax-exempt.
The tables below set forth the plans' accrued post-
retirement benefit obligation ("APBO") as of December 31,
1994 and 1993 and the expense provision for the years then
ended.
==============================================================================
============
(THOUSANDS)
1994 1993
- ------------------------------------------------------------------------------
- ------------
APBO ATTRIBUTABLE TO
Retirees and dependents
$ (53,060) $ (47,095)
Fully eligible active plan participants
(5,559) (5,671)
Other active plan participants
(68,084) (66,681)
- ------------------------------------------------------------------------------
- ------------
Total APBO
(126,703) (119,447)
Fair value of plan assets
70,460 68,408
- ------------------------------------------------------------------------------
- ------------
APBO in excess of plan assets
(56,243) (51,039)
Unrecognized net loss
63 (632)
Unrecognized transition obligation
43,321 45,756
- ------------------------------------------------------------------------------
- ------------
ACCRUED POST-RETIREMENT BENEFIT OBLIGATION
$ (12,859) $ (5,915)
==============================================================================
============
Service cost
$ 4,853 $ 4,379
Interest cost
8,830 8,248
Actual return on plan assets
(946) (3,993)
Net amortization and deferral
(1,774) 1,394
- ------------------------------------------------------------------------------
- ------------
POST-RETIREMENT BENEFIT COST
$ 10,963 $ 10,028
==============================================================================
============
The assumed expected long-term return on investments and the
discount rate used to measure the APBO under SFAS No. 106
are consistent with rates used to calculate the pension
plans funded status and expense under SFAS No. 87. The
assumed health care cost trend rates for 1995 are 11.5% for
medical and 8.5% for dental, decreasing to 7.0% and 5.0%,
respectively, by the year 2006. Increasing each of the
medical and dental cost trend rates by 1% in each year would
increase the total APBO as of December 31, 1994 by
-46-
$24.7 million and the total net periodic post-retirement
benefit cost for the year then ended by $4.1 million.
During 1992, the cost of post-retirement health care
benefits was $2.7 million. As of December 31, 1994, the
Company had approximately 1,000 retirees eligible to receive
health care benefits.
Concurrent with a rate order which was effective January 1,
1994, the Company adopted SFAS No. 112, Employers'
Accounting for Post-Employment Benefits, which establishes
accounting and reporting standards for post-employment
benefits other than those covered by SFAS Nos. 87 and 106.
In connection therewith, the Company expensed in 1994 the
transition obligation of $1.8 million and recovered this
cost through its customer rates.
The Company has a leveraged Employee Stock Ownership Plan
and Trust ("ESOP") that held 2,240,500 shares of WPSR common
stock (market value of approximately $59.9 million) at
December 31, 1994. At that date, the ESOP also had loans
guaranteed by the Company and secured by the common stock.
At December 31, 1994, these loans had recorded values of
$1.8 million (bearing an interest rate of 73.5% of prime
rate) and $18.2 million (bearing an interest rate of 9.33%).
The estimated market value of these loans at December 31,
1994 totaled $20.5 million.
Principal and interest on the loans are to be paid through
the Company contributions and through dividends on WPSR
common stock held by the ESOP. Shares in the ESOP are
allocated to participants as the loans are repaid. Tax
benefits from dividends paid to the ESOP are recognized as a
reduction in the Company's cost of providing service to
customers. The PSCW has allowed the Company to include in
cost of service an additional employer contribution to the
plan. The net effect of the tax benefits and of the
employee contribution is an approximately equal sharing of
benefits of the program between customers and employees.
(n) INCOME TAXES - Effective January 1, 1993, the Company
adopted the liability method of accounting for income taxes
as prescribed by SFAS No. 109, Accounting for Income Taxes.
Under the liability method, deferred income tax liabilities
are established based upon enacted tax laws and rates
applicable to the periods in which the taxes become payable.
The adoption of this accounting standard had an
insignificant impact on the Company s net income. The
excess deferred income taxes, resulting from taxes provided
at rates greater than current rates, and the previously
unrecorded deferred income taxes, have been recorded as a
net regulatory liability to be refunded to customers in
future years. Such net regulatory liability totaled
$38.6 million as of December 31, 1994.
-47-
The effective income tax rates are computed by dividing
total income tax expense, including investment credit
restored, by the sum of such expense and net income.
Previously deferred investment tax credits are being
restored over the life of the related utility plant. The
components of income tax expense are set forth in the tables
below.
==============================================================================
=========================
(Thousands, except for percentages) 1994
1993 1992
- ------------------------------------------------------------------------------
- -------------------------
RATE
AMOUNT Rate Amount Rate Amount
- ------------------------------------------------------------------------------
- -------------------------
Statutory federal income tax 35.0%
$29,899 35.0% $33,159 34.0% $29,350
State income taxes, net 6.2
5,180 4.9 4,636 5.2 4,518
Investment credit restored (2.4)
(2,038) (2.0) (1,860) (2.3) (2,022)
Rate difference on reversal of
income tax temporary differences (1.6)
(1,344) (1.5) (1,441) (2.1) (1,843)
Dividends paid to ESOP (1.7)
(1,445) (1.5) (1,434) (1.6) (1,381)
Other differences, net (0.8)
(668) (0.5) (521) (0.4) (300)
- ------------------------------------------------------------------------------
- -------------------------
EFFECTIVE INCOME TAX 34.7%
$29,584 34.4% $32,539 32.8% $28,322
==============================================================================
=========================
CURRENT PROVISION
Federal
$28,577 $28,212 $18,284
State
7,274 7,054 4,794
- ------------------------------------------------------------------------------
- ------------------------
TOTAL CURRENT PROVISION
35,851 35,266 23,078
==============================================================================
=========================
DEFERRED PROVISION (BENEFIT)
(4,229) (867) 7,266
INVESTMENT CREDIT RESTORED, NET
(2,038) (1,860) (2,022)
- ------------------------------------------------------------------------------
- -------------------------
TOTAL INCOME TAX EXPENSE
$29,584 $32,539 $28,322
==============================================================================
=========================
As of December 31, 1994 and 1993, the Company had the
following significant temporary differences that created
deferred tax assets and liabilities:
==============================================================================
(THOUSANDS) 1994
1993
- ------------------------------------------------------------------------------
DEFERRED TAX ASSETS
Plant related $ 50,537
$ 48,853
Other 26,391
17,207
- ------------------------------------------------------------------------------
TOTAL 76,928
66,060
==============================================================================
DEFERRED TAX LIABILITIES
Plant related 161,606
162,752
DSM expenditures 18,359
18,242
Coal and rail contract
buy-out costs 7,043
9,154
Other 17,046
14,864
- ------------------------------------------------------------------------------
TOTAL 204,054
205,012
==============================================================================
NET DEFERRED TAX LIABILITIES $ 127,126
$ 138,952
==============================================================================
-48-
(2) COMMERCIAL PAPER AND LINES OF CREDIT
To support outstanding commercial paper, the Company maintains
unused bank lines of credit. Some of these lines may be
withdrawn at the discretion of the lenders. While some cash
balances represent compensating balances for credit lines and
bank services, there are no legal restrictions as to withdrawal
of these funds. The majority of the lines of credit require a
fee based on the unused balance.
The following information relates to short-term borrowings and
lines of credit for the years indicated:
==============================================================================
===================
(Thousands, except for percentages) 1994
1993 1992
- ------------------------------------------------------------------------------
- -------------------
AS OF END OF YEAR
Discount rate on outstanding commercial paper 6.0%
3.4% 3.4%
Interest rate on note payable 6.0%
3.3% 3.5%
Unused lines of credit $22,870
$22,970 $23,150
Compensating balance requirements $ 94
$ 99 $ 108
==============================================================================
===================
FOR THE YEAR
Maximum amount of borrowings $26,000
$27,000 $22,500
Average amount of borrowings $10,844
$12,263 $12,414
Weighted average interest rate on borrowings 4.3%
3.2% 3.8%
==============================================================================
===================
Included in the above lines of credit are agreements with
commercial banks that permit the Company to borrow up to
$16 million at any time provided there is compliance with certain
financial covenants. These agreements extend for thirteen months
or more. As of December 31, 1994, no borrowings were outstanding
under these agreements.
(3) JOINTLY-OWNED FACILITIES
Information regarding the Company's share of major jointly-owned
electric generating facilities in service at December 31, 1994 is
as follows:
==============================================================================
===================
Columbia
Edgewater
(Thousands, except for percentages) Energy
Center Unit No. 4 Kewaunee
- ------------------------------------------------------------------------------
- -------------------
Ownership 31.8%
31.8% 41.2%
Plant capacity (Mw) 335.2
104.9 221.0
Utility plant in service $107,868
$21,874 $132,227
Accumulated provision for depreciation $ 56,361
$11,562 $ 74,449
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
consolidated statements of income, and the Company has supplied
its own financing for all jointly-owned projects.
(4) LONG-TERM DEBT
Sinking fund requirements on first mortgage bonds may be
satisfied by the deposit of cash or reacquired bonds with the
-49-
trustee and, for certain series, by the application of net
expenditures for bondable property in an amount equal to 166-2/3%
of the annual requirements.
All series requiring the deposit of cash or reacquired bonds for
sinking fund purposes have been satisfied to maturity. For those
series requiring unpledged property to satisfy sinking fund
requirements, the Company has adequate unpledged property to
satisfy the requirement for at least ten years.
In 1998, $50 million of 5-1/4% bonds will mature.
As of December 31, 1994, the market value of the Company's first
mortgage bonds was $273.0 million. These bonds have a recorded
value of $291.1 million. Historically, gains or losses resulting
from the settlement on long-term debt obligations have been
deferred as required by regulators.
(5) COMMON EQUITY
At December 31, 1994, the Company had $279.8 million of retained
earnings available for dividends; however, the Company is
restricted by a PSCW order to paying normal dividends of no more
than 109% of the previous year's common stock dividend without
prior notice to the PSCW. Also, Wisconsin law prohibits the
Company from making loans to WPSR and its subsidiaries and from
guaranteeing their obligations. The Company's equity
capitalization ratio at December 31, 1994 was 54% which is the
same rate approved by the PSCW for ratemaking purposes.
(6) COMMITMENTS AND CONTINGENCIES
COAL CONTRACTS
To ensure a reliable, low-cost supply of coal, the Company
entered into certain long-term contracts that have take-or-pay
obligations totaling $323.7 million from 1995 through 2016. The
obligations are subject to force majeure provisions which provide
the Company other options if the specified coal does not meet
emission limits which may be mandated in future legislation. In
the opinion of management, any amounts paid under the take-or-pay
obligations described above would be legitimate costs of service
subject to recovery in customer rates.
GAS COSTS
The Company also has natural gas supply and transportation
contracts that require total demand payments of $412.3 million
through October 2003. Management believes that these costs will
be recoverable in future customer rates.
-50-
ANR Pipeline Company ("ANR"), the Company's primary pipeline
supplier, filed with the FERC for approval to recover a portion
of certain take-or-pay costs it incurred from renegotiating its
long-term gas contracts. As a result of the filing, ANR was
allowed to recover a portion of these costs from its customers.
The Company began paying its share of these take-or-pay costs to
ANR in 1989 and recovering these costs directly from customers
through its purchased-gas-adjustment clause. In March 1991, the
FERC approved the settlement under which the Company will pay ANR
monthly take-or-pay amounts. Additional take-or-pay claims by
ANR may be filed with FERC. To date, the PSCW has granted the
Company recovery of all take-or-pay costs.
In April 1992, the FERC issued Order No. 636 ("Order") which
requires natural gas pipelines to restructure their sales and
transportation services. As a result of this Order, the Company
is obligated to pay for a portion of ANR's transition costs
incurred to comply with the Order. At December 31, 1994, the
Company has an accrued liability with an offsetting regulatory
asset in the amount of $1.9 million for a portion of these
transition costs. Though there may be additional costs, which
could be significant, the amount and timing of these costs are
unknown at this time. Management expects to recover these costs
in future customer rates.
The Company will be billed $3.3 million in 1995 for their
allocation of ANR's above-market costs of gas purchases from the
Dakota Gasification Plant. The Company is protesting the
legality of these costs which could total $49.0 million through
2009.
NUCLEAR LIABILITY
The Price-Anderson Act provides for the payment of funds for
public liability claims arising out of a nuclear incident. In
the event of a nuclear incident involving any of the nation's
licensed reactors, the Company is subject to a proportional
assessment which is approximately $32.7 million per incident, not
to exceed $4.1 million per incident, per calendar year. These
amounts represent the Company's 41.2% ownership share in
Kewaunee.
CLEAN AIR REGULATIONS
In 1990, the Federal Clean Air Act Amendments ("Act") were signed
into law. The Act requires the Company to meet new emission
limits for sulfur dioxide and nitrogen oxide in 1995 (Phase I)
and in the year 2000 (Phase II). Since Wisconsin had already
mandated reduced sulfur dioxide emissions by 1993, which were
lower than the Federal levels mandated for 1995, the Company was
already working on lowering emissions. The Company has complied
with both the Federal and Wisconsin sulfur dioxide laws primarily
through fuel-switching. The Company was in compliance with the
-51-
Wisconsin sulfur dioxide limits and the Federal Phase II limits
in 1994.
The final Federal regulations for nitrogen oxide are not known at
this time; however, based on draft rules, the Company expects to
make additional capital expenditures in the range of $15 million
to $25 million between 1995 and 1999 for Wisconsin and Federal
air quality compliance. Management believes that all costs
incurred to comply with these laws will be recoverable in future
customer rates.
MANUFACTURED GAS PLANT REMEDIATION
The Company currently is investigating the need for environmental
clean up of eight manufactured gas plant sites which it
previously operated. An environmental consultant has been
engaged to develop cost estimates. These estimates are based
upon an investigation of two of the sites and assumes excavation
of impacted soils, thermal treatment of soils, on-site
groundwater extraction and treatment and post-clean up and
monitoring for twenty-five years. The consultant has not yet
performed detailed investigations of the remaining six sites
and, therefore, comparable information on these sites is not
available.
The Company used the estimates for these two sites as a basis for
making projections on cleanup costs at the other sites because of
certain similar characteristics at the other sites. Thus, for
all sites, cleanup costs reflecting anticipated inflation,
current technology and no change in regulatory requirements are
estimated to be in the range of $14.8 million to $29.3 million.
Management has accrued $26.9 million for future cleanup costs for
all eight sites which will be spent over the next thirty-four
years. However, as further investigations are performed on all
sites, this estimate may change significantly.
The $26.9 million estimate has been recorded as a liability with
an offsetting deferred charge (regulatory asset). Based on a
recent rate order, these costs (less any insurance recoveries)
will be recoverable in future rates as expenditures are made.
However, carrying costs are not recoverable.
As additional site-specific studies are completed (three are
anticipated in 1995), these estimates will be adjusted to reflect
site-specific data. Other factors that can impact these estimates
are the volume of contaminated soil, changes in remediation
technology and regulatory requirements.
In June, the Wisconsin Supreme Court ("Court") issued a decision
regarding recoveries from insurance companies for environmental
remediation costs. The Court held that insurance coverage was
not available for environmental cleanup costs to the extent the
clean up is done to prevent or mitigate future injury. In
addition, the Court held that a notification letter from a
-52-
government agency about an environmental situation did not
constitute a suit which triggers the insurers' duty to defend.
The Company is exploring alternative approaches to pursuing
claims against its carriers in light of the decision.
The Company has made minor payments for the investigation and
potential clean up of certain other waste disposal sites.
Management believes the Company has been a minor contributor to
the total contamination at these sites and, accordingly, does not
believe its share of cleanup costs to be material.
LONG-TERM POWER SUPPLY
The Company has signed a contract to build a 122-megawatt
cogeneration facility with Rhinelander Paper Company and has
filed an application for a Certificate of Public Convenience and
Necessity with the PSCW requesting approval for the project.
Estimated cost for the project is $169 million.
Management estimates 1995 utility plant construction expenditures
to be approximately $84.2 million. DSM expenditures are
estimated to be $25.8 million, of which approximately
$15.0 million will be deferred and amortized over the next ten
years consistent with rate recovery.
-53-
(7) SEGMENTS OF BUSINESS
The following table presents information for the respective years
pertaining to the Company's operations segmented by lines of
business.
==============================================================================
=========================================
(Thousands) 1994 1993
1992
- ------------------------------------------------------------------------------
- -----------------------------------------
Electric Gas Total Electric Gas
Total Electric Gas Total
- ------------------------------------------------------------------------------
- -----------------------------------------
Operating revenues $480,816 $182,058 $ 662,874 $493,256 $187,376 $
680,632 $477,625 $157,177 $ 634,802
Operating expenses
Operation and
maintenance 312,208 162,150 474,358 310,534 167,434
477,968 304,347 141,053 445,400
Depreciation 50,540 5,825 56,365 54,498 6,111
60,609 52,819 5,773 58,592
Other taxes 22,488 3,575 26,063 22,064 3,140
25,204 21,687 2,772 24,459
Income taxes 27,320 2,492 29,812 30,599 2,508
33,107 25,746 1,460 27,206
- ------------------------------------------------------------------------------
- -----------------------------------------
412,556 174,042 586,598 417,695 179,193
596,888 404,599 151,058 555,657
- ------------------------------------------------------------------------------
- -----------------------------------------
Operating income $ 68,260 $ 8,016 $ 76,276 $ 75,561 $ 8,183 $
83,744 $ 73,026 $ 6,119 $ 79,145
==============================================================================
=========================================
Identifiable assets(a) $937,481 $188,554 $1,126,035 $938,951 $184,880
$1,123,831 $951,074 $158,314 $1,109,388
- -------------------------------------------- ----------------------
---------------------- -
Assets not allocated(b) 79,191
75,010 36,162
- ------------------------------------------------------------------------------
- -----------------------------------------
Total assets $1,205,226
$1,198,841 $1,145,550
==============================================================================
=========================================
Construction and
nuclear fuel
expenditures
including AFUDC $ 58,674 $ 19,612 $ 78,286 $ 59,038 $ 13,693 $
72,731 $ 91,272 $ 11,009 $ 102,281
==============================================================================
=========================================
(a) At December 31 and net of the respective accumulated provisions
fordepreciation.
(b) Primarily includes cash, investments, pension assets, nonutility property
and other receivables.
-54-
(8) QUARTERLY FINANCIAL INFORMATION
==============================================================================
=========================================
(Thousands, except for share amounts)
Three Months Ended
- ------------------------------------------------------------------------------
- -----------------------------------------
1994
March June
September December Total
- ------------------------------------------------------------------------------
- -----------------------------------------
Operating revenues $200,730 $147,569
$149,630 $164,945 $662,874
Operating income $ 27,654 $ 13,235
$ 18,459 $149,630 $ 76,276
Net income $ 22,375 $ 8,188
$ 13,684 $ 11,595 $ 55,842
Earnings on common stock $ 21,597 $ 7,410
$ 12,906 $ 10,818 $ 52,731
Average number of shares of common stock outstanding 23,897 23,897
23,897 23,897 23,897
==============================================================================
=========================================
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
==============================================================================
=========================================
Because of various factors which affect the utility business, the quarterly
results of operations are not necessarily
comparable.
(1) In the quarter ended December 1993, the Company recorded an adjustment as
a result of its annual coal inventory
observation.
This adjustment increased net income and earnings per average share of
common stock by $1.2 million and $.05,
respectively, for 1993.
-55-
G. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
To Wisconsin Public Service Corporation:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Wisconsin Public Service
Corporation (a Wisconsin corporation) and subsidiary as of
December 31, 1994 and 1993, and the related consolidated statements of
income, retained earnings and cash flows for each of the three years
in the period ended December 31, 1994. These financial statements are
the responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the financial position
of Wisconsin Public Service Corporation and subsidiary as of
December 31, 1994 and 1993, and the results of their operations and
their cash flows for each of the three years in the period ended
December 31, 1994 in conformity with generally accepted accounting
principles.
As discussed in notes (1)(m) and (1)(n) to the financial statements,
effective January 1, 1993, Wisconsin Public Service Corporation
changed its method of accounting for post-retirement benefits other
than pensions and income taxes.
Milwaukee, Wisconsin,
January 26, 1995
ARTHUR ANDERSEN LLP
-56-
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
All information required by Part III, with the exception of
information concerning executive officers which appears in Item 4A of
Part I hereof, is incorporated by reference to WPSR's proxy statement
for the annual meeting of the shareholders which is scheduled to be
held on May 4, 1995 [File No. 1-11337].
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Documents filed as part of this report:
(1) The following financial consolidated statements are
included in Part II at Item 8 above:
Pages in
Description 10-K
----------- --------
Consolidated Statements of Income for the 36
three years ended December 31, 1994, 1993,
and 1992
Consolidated Balance Sheets as of 37
December 31, 1994 and 1993
Consolidated Statements of Capitalization 38
as of December 31, 1994 and 1993
Consolidated Statements of Cash Flows for 39
the three years ended December 31, 1994,
1993, and 1992
Consolidated Statements of Retained 40
Earnings for the years ended December 31,
1994, 1993, and 1992
Notes to Consolidated Financial Statements 41
Report to Independent Public Accountants 56
(2) Financial statement schedules.
-57-
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.
(3) All exhibits, including those incorporated by
reference.
-58-
PAGE
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 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
-59-
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENTS
(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
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).
-60-
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENTS
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.
(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).
-61-
EXHIBIT PAGE IN
NUMBER DESCRIPTION OF DOCUMENTS 10-K
18 Letter re change in accounting principles
(Not applicable).
19 Previously unfiled documents (None).
22 Subsidiaries of the Registrant. 64
24.1 Consent of Independent Public Accountants. 65
25 Powers of Attorney. 66
27 Financial Data Schedule. 72
-62-
PAGE
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 March 23, 1995
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 --------------------------------
D. A. Bollom
Director Attorney-in-Fact
- -------------------------------
James L. Kemerling
Director
- -------------------------------
Linus M. Stoll
/s/ D. A. Bollom Principal Executive March 23, 1995
- -------------------------------Officer and Director
D. A. Bollom
/s/ P. D. Schrickel Principal Financial March 23, 1995
- -------------------------------Officer
P. D. Schrickel
/s/ D. L. Ford Principal Accounting March 23, 1995
- -------------------------------Officer
D. L. Ford
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