PART I
Item 1. Business
Northern States Power Company ("the Company"), incorporated
in 1901 under the laws of Wisconsin as the La Crosse Gas and
Electric Company, is an operating public utility company with
executive offices at 100 North Barstow Street, Eau Claire,
Wisconsin 54702-0008 (Phone: (715) 839-2621). The Company is a
wholly-owned subsidiary of Northern States Power Company, a
Minnesota corporation ("the Minnesota Company").
The Company is engaged in the generation, transmission, and
distribution of electricity to approximately 208,000 retail
customers in an area of approximately 18,900 square miles in
northwestern Wisconsin, to approximately 9,100 electric retail
customers in an area of approximately 300 square miles in the
western portion of the Upper Peninsula of Michigan, and to 10
wholesale customers in the same general area. The Company is
also engaged in the distribution and sale of natural gas in the
same service territory to approximately 68,200 customers in
Wisconsin and 4,700 customers in Michigan. In Wisconsin, some of
the larger communities the Company provides natural gas to are
Eau Claire, Chippewa Falls, La Crosse, Hudson, Menomonie and
Ashland. In the Upper Peninsula of Michigan, the largest
community to which the Company provides natural gas is Ironwood.
In 1994 the Company derived 83 percent of its total
operating revenues from electric utility operations and 17
percent from gas utility operations. As of December 31, 1994,
the Company had 955 employees including 849 full-time employees.
REGULATIONS AND RATES
Regulation
The Company is experiencing some of the challenges currently
common to regulated electric and gas utility companies, namely
increasing competition for customers and uncertainties in the
future regulatory processes. Currently, as a result of increased
competition, and the desire on the part of some customers for
choice, the Public Service Commission of Wisconsin ("PSCW") is
investigating changes in the structure and regulation of electric
and gas utilities. The Company has filed comments with the
Commission regarding the future of the electric industry. Some
of these comments are included in the Electric Operations section
of this report. A proceeding has also been initiated to explore
similar issues for the Company's gas operations as well as a
review of the purchase gas adjustment clause ("PGAC").
The PSCW and Michigan Public Service Commission ("MPSC")
regulate the rates and service of the Company with respect to
retail sales within the State of Wisconsin and the State of
Michigan, respectively, the issuance of new securities by the
Company and various other aspects of the Company's operations.
The PSCW also exercises jurisdiction over the construction of
certain electric and gas facilities. The Company is also subject
to the jurisdiction of the Federal Energy Regulatory Commission
("FERC") with respect to its sales to wholesale electric
customers and certain other aspects of its operations, including
the licensing and operation of hydro projects and the Company's
Interchange Agreement (see Electric Operations-Interchange
Agreement). Approximately 96.9 percent of the Company's 1994
electric retail revenues from sales and 93.4 percent of its
retail gas revenues from sales were subject to PSCW jurisdiction
with the remaining retail revenues subject to MPSC jurisdiction.
In 1994, the Company's wholesale revenues from sales were
approximately 5.8 percent of the Company's electric revenues from
sales.
Prior to construction of all major projects, the Company is
required to obtain various licenses, permits and a certificate of
public convenience and necessity from the PSCW. As part of this
process, advance plan hearings are held by the PSCW, whereby the
Company's generation and transmission construction plans and
those of several neighboring utilities are reviewed by the PSCW.
For the purpose of rate regulation, all three of the
regulatory jurisdictions allow a "forward looking" test year
corresponding to the time that rates are to be put into effect.
The PSCW has a biennial filing requirement for processing
rate cases and monitoring utilities' rates. By June 1 of each
odd-numbered year, the Company must submit filings for calendar
test years beginning the following January 1. The filing
procedure and subsequent review generally allow the PSCW
sufficient time to issue an order effective with the start of the
test year.
The PSCW reviews each utility's cash position to determine
if a current return on construction work-in-progress (CWIP) will
be allowed. The PSCW will allow either a return on CWIP or
capitalization of AFC at the adjusted overall cost of capital.
The Company currently capitalizes the Allowance for Funds Used
during Construction (AFC) on production and transmission CWIP at
the FERC formula rate and on all other CWIP at the adjusted
overall cost of capital.
Rate Changes
Wisconsin
The Company filed a proposal for a new high load factor rate
with the PSCW in November, 1994, that became effective January 1,
1995. Under the proposal, qualifying customers would receive a
credit on their bills of up to 4.0% depending on their load
factor. This is expected to reduce 1995 revenues by
approximately $1.5 million.
On December 23, 1993, the PSCW issued an order approving a
$1.41 million (2.0 percent) increase on an annual basis in the
Company's gas rates. A January 1, 1994 effective date was
authorized for these rate changes. No change in the retail
electric rates was requested.
The Company plans to file a submittal in June 1995 as
required by the PSCW biennial filing requirement.
Wholesale
The Company plans to announce market-based pricing options
for existing and potential wholesale customers in 1995. The
wholesale customers have new opportunities to purchase power from
power suppliers other than NSP. With open transmission access,
they have the opportunity to purchase power from any producer and
request that, on a comparable basis, the power be delivered from
the producer to their municipality.
In May, 1994, the Company offered its municipal wholesale
customers a discount of one to two percent from the FERC
authorized rate for a long-term full requirements commitment of
five to ten years with comparable cancellation notices. Five of
the ten municipal wholesale customers elected to extend their
contracts to receive the discounts. The total annual decrease in
revenues is approximately $80,000.
NSP(MN) and the Company filed open access transmission
tariffs with the FERC in March 1994. In accepting the filing,
the FERC ruled NSP's tariff would be subject to the requirement
that the NSP system offer transmission service to third parties
using terms and conditions comparable to its own use of the
system. NSP recently reached a settlement in principle with
several parties involved in this proceeding and anticipates
approval of the stipulation in early 1995.
Michigan
There were no changes in the Michigan electric or gas base
rates during 1994.
<PAGE>
Fuel and Purchased Gas Adjustment Clauses
Wisconsin
The Wisconsin automatic retail electric fuel adjustment
clause was eliminated for the Company in the electric retail rate
order issued by the PSCW dated March 11, 1986. The electric fuel
adjustment clause has been replaced by a procedure which compares
actual monthly and anticipated annual fuel costs with those costs
which were included in the latest retail electric rates approved
by the PSCW. If the comparison results in a difference outside a
range of eight percent for the first month, five percent for the
second month, or two percent for the remainder of the year, the
PSCW may hold hearings limited to fuel costs and revise rates.
The Company's retail gas rate schedules include a purchased
gas adjustment clause which provides for inclusion of the current
cost of gas including its transportation. The factors applied
under the purchased gas adjustment clause are adjusted on an
ongoing basis to reflect a reconciliation of gas costs incurred
and recovered.
Michigan
The Company's Michigan retail gas and electric rate
schedules include Gas Cost Recovery Factors (GCRF) and Power
Supply Cost Recovery Factors (PSCRF), respectively, which are
based on a twelve-month projection. The MPSC conducts formal
hearings because approval must be obtained before implementation
of the factors. After each twelve-month period is completed, a
reconciliation is submitted whereby over-collections are refunded
and any under-collections are collected, including interest.
Wholesale
The Company calculates the fuel adjustment factor for the
current month based on estimated fuel costs for that month. The
fuel adjustment factor is adjusted for over or under collected
resale fuel costs from the prior month's actual operations which
provide an ongoing true-up mechanism.
Demand Side Management
The Company continues to implement various Demand Side
Management (DSM) programs designed to improve load factor and
reduce the Company's power production cost and system peak
demands, thus reducing or delaying the need for additional
investment in new generation and transmission facilities. The
Company currently offers a broad range of DSM programs to all
customer sectors, including information programs, rebate and
financing programs, and rate incentive programs. In management's
opinion, these programs need to respond to customer needs and
focus on increasing value of service so that, over the long term,
the programs help its customer base become more stable, energy
efficient and competitive.
During 1994, the Company's programs accomplished
approximately 19 Megawatts (MW) of system peak demand reduction
in the commercial, industrial and agricultural customer sectors
and over 3.5 MW in the residential sector. These impacts were
obtained through appliance, lighting, motor, and cooling
efficiency and process improvements, peak curtailable and time of
use rate applications, and direct load control of water heaters
and air conditioners.
Since 1986, the Company's DSM programs have achieved 149 MW
of summer peak demand reduction, which is equivalent to 15% of
its 1994 summer peak demand. A cumulative goal of 200 MW of peak
demand reduction by 1997 has been established. The Company
continues to focus on improving the cost-effectiveness of its DSM
programs through market research studies and program evaluations.
ELECTRIC OPERATIONS
Competition
On Oct. 24, 1992, the President signed into law the Energy
Policy Act of 1992 (Energy Act). The Energy Act amends the
Public Utility Holding Company Act of 1935 (1935 Act) and the
Federal Power Act. Among many other provisions, the Energy Act
is designed to promote competition in the development of
wholesale power generation in the electric utility industry. It
exempts a new class of independent power producers from
regulation under the 1935 Act. The Energy Act also allows the
FERC to order wholesale "wheeling" by public utilities to provide
utility and non-utility generators access to public utility
transmission facilities. The provision allows the FERC to set
prices for wheeling, which will allow utilities to recover
certain costs. The costs would be recovered from the companies
receiving the services, rather than the utilities' retail
customers.
Many states are currently considering retail competition.
While the topic of retail competition has been discussed in NSP
jurisdictions, no legislation has been formally introduced.
However, the PSCW has opened generic docket 05-EI-114 to examine
various industry restructuring issues. The PSCW has asked each
utility in the state and various other parties for comments
regarding retail competition. In response to the PSCW request,
the Wisconsin Company filed the following recommendations.
Competition should be phased in for retail markets by customer
classes, with all customers having choice of supplier by 2001.
The generation segment of the industry should be deregulated by
2001. NSP proposes that utilities retain operational control of
their transmission and distribution systems and that utilities
should be permitted to recover the cost of investments that were
authorized under traditional regulation, to the extent that these
investments exceed the market price. Finally, utilities and
other competitors should have a level playing field for issues
such as obligation to serve, eminent domain, requirements for
demand side management, funding of social programs, opening of
retail markets to competition and other issues. Also, as an
outcome of the responses to the PSCW, a task force was formed by
the PSCW to analyze the industry restructuring necessary in the
State of Wisconsin. A goal of this task force is to have a list
of recommended legislative changes to the Wisconsin Legislature
for the 1996 session. Retail competition represents yet another
development of a competitive electric industry. Management plans
to continue its ongoing efforts to be a low-cost supplier of
electricity and an active participant in the more competitive
market for electricity expected as a result of the Energy Act.
The Michigan Public Service Commission has determined that
Michigan should recodify statutes governing energy production.
They will be working with the governor's office to initiate that
process. Michigan also has a retail wheeling experiment, limited
to its two largest utilities and customers larger than $ 50
million, currently underway. The Company's customers are not
included in this experiment which is currently being challenged
in court.
NSP System
The Company's electric production and transmission systems
are interconnected with the production and transmission system of
the Minnesota Company. The combined electric production and
transmission systems of the Company and the Minnesota Company are
hereinafter called the "NSP System."
The facilities of the NSP system include coal and nuclear
generating plants, hydro, gas fired combustion turbines, waste
wood, and waste wood/refuse derived fuel ("RDF") generating
plants, an interconnection with Manitoba Hydro Electric Board for
the purpose of exchanging power, and extra-high voltage
transmission facilities for interconnection to Kansas City,
Milwaukee and St. Louis to provide the necessary back-up for the
large plants.
The NSP System added the Angus Anson 232 MW gas-fired
combustion turbines generation facility, located in Sioux Falls,
South Dakota on September 24, 1994. Also in 1994, the MN Company
signed a long-term power purchase contract with LSP-Cottage Grove
for 245 MW of annual capacity for thirty years.
The Minnesota Company operates two nuclear generating
plants: the single unit, 539 Mw Monticello Nuclear Generating
Plant and the Prairie Island Nuclear Generating Plant with two
units totaling 1,025 Mw. The Monticello Plant received its 40-
year operating license from the Nuclear Regulatory Commission
(NRC) on Sept. 8, 1970, and commenced operation on June 30, 1971.
Prairie Island Units 1 and 2 received their 40-year operating licenses
on Aug. 9, 1973, and Oct. 29, 1974, respectively, and commenced
operation on Dec. 16, 1973, and Dec.21, 1974, respectively.
The Minnesota Company has contracted with the DOE for the
disposal of spent nuclear fuel. The DOE charges a quarterly
disposal fee based on nuclear electric generation sold. This fee
ranges from approximately $10 million to $12 million per year,
which NSP recovers from its customers in cost-of-energy rate
adjustments or through base rates. In 1985, the Minnesota
Company paid the DOE a one-time fee of $95 million for fuel used
prior to April 7, 1983.
In 1979 the Minnesota Company began expanding the used
nuclear fuel storage facilities at its Monticello Plant by
replacement of the racks in the storage pool. Also, in 1987, the
Company completed the shipment of 1,058 spent fuel assemblies
from the Monticello Plant to a General Electric storage facility
in Morris, Illinois. As a result, the plant now has sufficient
pool storage capacity to operate until 2008.
In 1976 the Minnesota Company began expanding the used
nuclear fuel storage facilities at its Prairie Island Plant by
replacement of the racks in the storage pool. Total capacity was
increased from 210 fuel assemblies to 1,386 fuel assemblies. In
1994 the spent nuclear fuel storage facilities at the Minnesota
Company's Prairie Island Plant were expected to reach full
capacity. In May 1994 additional on-site dry cask fuel storage
facilities were approved by the Minnesota Legislature which are
expected to provide sufficient storage capacity to operate until
at least 2002.
Capability and Demand
The Company's record peak demand occurred on January 20,
1994, and was recorded at 1,032 MW.
The NSP System's net generating capability, plus commitments
for capacity purchases, less commitments for capacity sales, must
be at least equal to the NSP System obligation which is the sum
of its maximum demand and its reserve requirements. Being a
member of the Mid-Continent Area Power Pool ("MAPP"), NSP's
reserve requirement is determined jointly with the other parties
to the MAPP Agreement.
Currently, the reserve requirement equals 15 percent of the
NSP System's maximum demand. The reserve requirement reflects
the benefit of MAPP members sharing their reserves to protect
against equipment failures on their systems (See Electric Power
Pooling Agreements). The NSP System carried a reserve margin of
23% in 1994.
The Company primarily relies on the Minnesota Company,
through the Interchange Agreement (see Electric Operations -
Interchange Agreement), for base load generation. Approximately
81 percent of the total kilowatt hour requirements of the Company
were provided by the Minnesota Company generating facilities or
purchases made by the Minnesota Company for system uses in the
year 1994.
The Company also has two electric steam generating
facilities. One is the Bay Front Generating Plant which is
located in Ashland, Wisconsin. The plant is fueled primarily by
natural gas, coal and wood residue. Recent modifications to the
facility allow for more effective utilization of additional waste
wood fuel supplies and have extended the useful life of the
facility approximately 20 years from their completion in 1992.
In 1992 the Company received authorization from the Wisconsin
Department of Natural Resources ("DNR") to burn tire derived fuel
on a regular basis.
The Company's second electric steam generating plant is the
French Island plant located in La Crosse, Wisconsin, which has
two fluidized bed boilers modified for the purpose of burning a
mixture of waste wood and RDF. The Bay Front plant in Ashland
and the French Island steam plant are primarily used on an
intermediate load basis.
The Company's thermal peaking capability consists of two
oil-fired gas turbine peaking plants and a gas and oil turbine
peaking plant. The Company also has 19 hydro plants that operate
as peaking facilities or run-of-river facilities.
<PAGE>
Interchange Agreement
The electric production and transmission costs of the NSP
System are shared by the Company and the Minnesota Company. The
cost-sharing arrangement between the companies is the Agreement
to Coordinate Planning and Operation and Interchange Power and
Energy between Northern States Power (Minnesota) and Northern
States Power (Wisconsin) ("Interchange Agreement"). It is a FERC
regulated agreement and has been accepted by the PSCW and the
MPSC for determination of costs recoverable in rates by the
Company for charges from the Minnesota Company in rate cases.
Historically the Company's share of the NSP System annual
production and transmission costs has been in the 14 to 17
percent range. Revenues received from billings to the Minnesota
Company for its share of the Company's production and
transmission costs are recorded as electric operating revenues on
the Company's income statement. The portions of the Minnesota
Company's production and transmission costs that were charged to
the Company were recorded as purchased and interchange power
expenses and other operation expenses, respectively, on the
Company's income statement. (See Note 6 to Financial
Statements).
Under the Interchange Agreement, the Company could be
charged a portion of the cost of an assessment made against the
Minnesota Company pursuant to the Price-Anderson liability
provisions of the Atomic Energy Act of 1954. (See Note 3 to
Financial Statements).
Electric Power Pooling Agreements
Many of NSP's power purchases from other utilities are
coordinated through the regional power organization MAPP,
pursuant to an agreement dated March 31, 1972. NSP is one of 49
participants in MAPP consisting of 10 investor-owned systems,
eight generation and transmission cooperatives, three public
power districts, seven municipal systems and the Department of
Energy's Western Area Power Administration, and 20 Associate
Participants. The MAPP agreement provides for the members to
coordinate the installation and operation of generating plants
and transmission line facilities. The terms and conditions of
the MAPP agreement and transactions between MAPP members are
subject to the jurisdiction of the FERC. The 1972 MAPP agreement
was accepted for filing with the FERC, effective Dec. 1, 1972.
Fuel Supply
In 1994 the Company shared in the fuel supply costs incurred
by the Minnesota Company in accordance with the Interchange
Agreement. Coal and nuclear fuel will continue to dominate the
NSP System fuel requirements for the generation of electricity.
It is expected that approximately 98 percent of the NSP System
annual fuel requirements will be provided by these two sources
and that 2 percent of NSP's annual fuel requirements for
generation will be provided by other fuels (including natural
gas, oil, refuse derived fuel, waste materials, and wood) over
the next several years.
Fuel Use on Btu Basis
(Est.) (Est.)
1994 1995 1996
Coal 60.9% 61.1% 63.1%
Nuclear 37.4% 37.1% 35.1%
Other * 1.7% 1.8% 1.8%
* Includes oil, gas, refuse derived fuel and wood
<PAGE>
Electric Operating Statistics
The follow table summarizes the revenues, sales and
customers from NSP's electric business:
Operating Statistics
1994 1992 1991 1990
y contracted winter
peaking supplies thus reducing costs and providing greater
reliability.
The Company is continuing its pursuit of growth and
profitability through expansion of its distribution system and
services both inside and outside of its existing service
territories. In 1994 the Company extended service to the
communities of Fall Creek and Elk Mound. Applications for
Certificates of Authority have been filed with the PSCW to serve
filed with the PSCW to serve
the Township of Pleasant Valley, the Town of Washington, and the
Townships of Tainter and Cedar Falls. On March 14, 1995, the
Company received approval of its application to provide gas
service to Pleasant Valley in the Town of Washington.
The Company began limited services under a pilot project
approved by the PSCW which allows the Company to take advantage
of its unique position in the United States and Canadian supply
markets. Examples of non-traditional activities may include:
energy management services, sales of unused system supply if
profitable, and brokerage of gas not purchased or required for
system needs. These non-traditional marketing opportunities are
a result of deregulation in the natural gas industry.
Traditional regulated services would not have allowed a mark-up
on gas costs.
ENVIRONMENTAL MATTERS
The Wisconsin DNR has been authorized by the United States
Environmental Protection Agency to administer the National
Pollutant Discharge Elimination System Permits under the Federal
Water Pollution Control Act Amendments of 1977. Such permits are
required for the lawful discharge of any pollutant into navigable
waters from any point source (e.g. power plants). Permits have
been issued for all of the Company's affected plants and all
plants are in compliance with permit requirements.
The DNR has jurisdiction over emissions to the atmosphere
from the Company's power plants. The operation of the Company's
generating plants substantially conforms to federal and state
limitations pertaining to discharges to the air. Occasional,
infrequent exceedances of Wisconsin DNR air emission limitations
occurred in 1994 at the Company's Bay Front facility. These are
being resolved through operating changes and the installation of
continuous emission monitors and no agency enforcement action has
resulted. The Company presently operates hydro, coal, natural
gas, tire-derived fuel, railroad tie, oil-fired, wood and refuse-
derived fuel/wood-fired generation equipment.
Regulatory approval is required for the construction of
generating plants and major transmission lines. Also, additional
regulations have been instituted governing the use, transport,
disposal and inspection of hazardous material and electrical
equipment containing polychlorinated biphenyls. The Company has
procedures in place to comply with these regulations.
The NSP Wisconsin policy is to proactively prevent adverse
environmental impacts, regularly monitor operations to ensure the
environment is not adversely affected, and take timely corrective
actions where past practices have had a negative impact on the
environment. Significant resources are dedicated to
environmental training, monitoring and compliance matters. The
Company strives to maintain compliance with all applicable
environmental laws.
Both the Company and the Minnesota Company have received
notices for requests for information concerning groundwater
contamination at a landfill site in Wisconsin. While neither the
Company nor the Minnesota Company have been named potentially
responsible parties (PRP's), both companies voluntarily joined a
group of other parties to address the contamination at this site.
A preliminary estimate of total remediation costs at the site is
approximately $6 million. The Company's and the Minnesota
Company's share of this cost is currently estimated to be
approximately 1%. The Company's share alone is estimated to be
$20,000.
In addition, the administrator of a group of PRP's has
notified the Company that it might be responsible for cleanup of
a solid and hazardous waste landfill site. The Company contends
that it did not dispose of hazardous wastes in the subject
landfill during the time period in question. Because neither the
amount of cleanup costs nor the final method of their allocation
among all designated PRP's has been determined, it is not
feasible to predict the outcome of the matter at this time.
On March 2, 1995, the Wisconsin Department of Natural
Resources (WDNR) notified the Company that it is a PRP on a
creosote/coal tar contamination site in Ashland, WI. The Company
has informed the WDNR of its belief that two sites exist. The
first site, formerly a coal gas plant site, is NSP property. The
second site is adjacent to the NSP site and is not owned by the
Company. An existing condition report has been completed on an
adjacent site. An estimate of site remediation costs, and the
extent of the Company's responsibility, if any, for sharing such
costs, is not known at this time. Investigations are underway to
determine the Company's responsibility as well as that of
predecessor companies contributing to the contamination on the
adjacent site. The current estimate of the Company's share of
future remediation costs at the NSP site is less than $500,000.
This estimate is not based upon a formal remediation
investigation and feasability study. To the Company's knowledge,
no study has been completed for the adjacent site, that describes
remedial alternatives and clean-up cost estimates. The Company
intends to seek rate recovery of significant costs it incurs
associated with the clean-up of either Ashland Site.
In late December 1994, the Company completed installation of
a control center monitoring system at the Bay Front generating
plant in Ashland, Wisconsin. The control center which will
monitor emission from the four generating units, was mandated by
the Clean Air Act. The total cost of the project was
approximately $1.3 million.
CONSTRUCTION AND FINANCING
Expenditures for the Company's construction program in 1994
totaled $53 million. The 1995 construction expenditures are
estimated to be $55.2 million with approximately $33.7 million
for electric facilities, $5.8 million for gas facilities and
$15.7 million for general plant and equipment.
<PAGE>
Expenditures for the Company's construction programs for the
next five-year period 1995-1999, are estimated to be as follows:
Year Estimated Construction Expenditures
1995 $ 55 million
1996 $ 53 million
1997 $ 59 million
1998 $ 62 million
1999 $ 57 million
TOTAL $286 million
It is presently estimated that approximately 93 percent of
the 1995-1999 construction expenditures will be provided by
internally generated funds and the remainder from short-term and
long-term external financing. At December 31, 1994, the
Company's short-term borrowings outstanding were $41.3 million.
The foregoing estimates of construction expenditures,
internally generated funds and external financing requirements
can be affected by numerous factors, including load growth,
competition, inflation, changes in the tax laws, rate relief,
earnings and regulatory actions. Major electric and gas utility
projects are currently subject to the jurisdiction of the PSCW
and require its approval. Hence, the above estimated
construction program and financing program could change from time
to time due to variations in these other factors.
During the five years ended December 31, 1994, the Company
had gross additions to utility plant in service of approximately
$250.3 million. Included in the Company's gross additions is
$28.2 million for electric production facilities, $153.7 million
for other electric properties, $37.6 million for gas utility
properties, and $30.8 million for other utility properties.
Retirements during the same period were approximately $37.0
million. Based on studies made by the Company, the weighted
average age of depreciable property was 12.5 years at December
31, 1994.
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1994 the total number of full- and part-time
employees of NSP-Wisconsin was approximately 955. About 430
employees of NSP are represented by one local IBEW labor union.
On May 2, 1994, the IBEW members voted to ratify a three year
labor agreement retroactive to Jan. 1, 1994. Labor and
employee benefit costs are not expected to be materially affected
by the terms of the new agreement.
NSP recently reviewed employee and retiree benefits and
implemented the following changes effective in 1994. These
changes support NSP's goal of providing market-based benefits,
and did not materially affect employee compensation and benefit
costs in 1994.
Active nonbargaining medical premium increases: A two-year
cost sharing strategy for medical benefits for nonbargaining
employees was implemented in 1994. The strategy consisted of
employees contributing 10% in 1994 and 20% in 1995 of the total
medical cost.
Retiree medical premium increases: Retiree medical premiums
were increased in 1994 for existing and future retirees. For
existing qualifying retirees, pension benefits have been
increased to offset some of the premium increase. For future
retirees, a six-year cost-sharing strategy was outlined.
Nonbargaining pension plan lump sum option changes: Prior to
1994, nonbargaining employees had the option to receive their
pension in either a lump sum or in monthly installments.
Beginning in 1994, nonbargaining employees can choose a lump sum
distribution in 25% increments upon termination of employment.
Employees taking less than 100 percent will receive the rest of
their benefits in monthly installments. At the end of 1994, this
benefit was modified to allow a lump sum option only on the
portion of pension benefit earned through Dec. 31, 1994.
401(k) changes: NSP currently offers eligible employees a
401(k) Retirement Savings Plan. In 1994, NSP matched employees'
pre-tax 401(k) contribution up to $500 per year for nonbargaining
employees and up to $400 per year for bargaining. In 1995, NSP's
annual match will increase to $700 for nonbargaining employees.
Under the terms of the bargaining agreement implemented in 1994,
NSP's annual match will increase to $500 in 1995 and $600 in
1996.
Wage increases: No base wage scale increases were
implemented in January 1994. In 1994 bargaining employees
received 3.0% lump sum payment. Effective in 1994, NSP
implemented a market-based pay structure for nonbargaining
employees. NSP's new pay system uses the latest salary surveys
that indicate how local and regional companies pay their
employees for comparable positions. In January 1995,
nonbargaining employees will receive an average wage scale
increase of 3.5%, while bargaining employees will receive a 2%
wage base increase and a 1.5% lump sum payment.<PAGE>
Item 2. Properties
Electric Utility
The Company's major electric generating facilities consist
of the following:
Projected
Year 1994-5 Winter
Station and Units Fuel Installed Capability (MW)
Combustion Turbine:
Flambeau Station Gas/Oil 1969 17
(1 unit)
Park Falls, WI
Wheaton Oil 1973 440
(6 units)
Eau Claire, WI
French Island Oil 1974 192
(2 units)
La Crosse, WI
Steam:
Bay Front Coal/Wood/ 1960-1974 73
(3 units) Gas
Ashland, WI
French Island Wood/RDF 1940-1948 29
(2 units)
La Crosse, WI
Hydro Plants:
(19 plants) - Various dates 248
TOTAL 999
At December 31, 1994, the Company owned approximately 2,394
pole miles of overhead electric transmission lines, 8,044 pole
miles of overhead electric distribution lines, 37 conduit miles
and 1,011 direct buried cable miles of underground electric
lines. Virtually all of the land and personal property owned by
the Company is subject to the lien of their first mortgage bond
indentures pursuant to which they have issued first mortgage
bonds.
Gas Utility
The gas properties of the Company include approximately
1,399 miles of natural gas distribution mains. The Company owns
two liquefied natural gas facilities with a combined storage
capacity of the equivalent of 400,000 Mcf to supplement the
available pipeline supply of natural gas during periods of peak
demands. The two liquified natural gas facilities are located in
Eau Claire and La Crosse, Wisconsin. In January of 1993, the
Company installed temporary propane air facilities with a
capacity of 144,000 gallons to further supplement its gas supply
in the La Crosse, Wisconsin area during peak periods.
Item 3. Legal Proceedings
The Company is currently involved in various claims and
lawsuits incidental to its business. In the opinion of
management, if the Company were ultimately found to be liable in
these claims and lawsuits, such liability would not have a
material effect on the financial statements of the Company.
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
Omitted per conditions set forth in general instruction J
(1) and (a) and (b) of Form 10-K for wholly-owned subsidiaries
(reduced disclosure format).<PAGE>
PART II
Item 5. Market Price of and Dividends on the Registrant's
Common Equity and Related Stockholder
Matters
This is not applicable as the Company is a wholly owned
subsidiary.
Item 6. Selected Financial Data
This is omitted per conditions set forth in general
instructions J (1) (a) and (b) of Form 10-K for wholly owned
subsidiaries (reduced disclosure format).
Item 7. Management Discussion and Analysis of Financial
Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition
and Results of Operations is omitted per conditions as set forth
in general instructions J (1) (a) and (b) of Form 10-K for wholly
owned subsidiaries. It is replaced with management's narrative
analysis of the results of operations set forth in general
instructions J (2) (a) of Form 10-K for wholly owned subsidiaries
(reduced disclosure format). This analysis will primarily set
forth the Company's accounting changes and compare its revenue
and expense items for the year ended December 31, 1994 with the
year ended December 31, 1993.
The Company's net income for year ended December 31, 1994
was $38.5 million, up from the $38.0 million earned in the same
period of 1993. The 1994 operating income decreased by $0.2
million from the 1993 level.
Accounting Changes
Postemployment Benefits During 1994, the Company adopted
SFAS No. 112 - Employers' Accounting for Postemployment Benefits.
SFAS No. 112 requires the accrual of certain employee costs (such
as injury compensation and severance) to be paid in future
periods. Its adoption did not have a material effect on the
Company's results of operations or financial condition.
Electric Sales and Revenues
Electric revenues for 1994 increased $12.3 million, a 3.4
percent increase from the 1993 revenues. Revenues from retail
sales, which accounted for 75 percent of the electric revenues in
1994, increased $8.8 million or 3.2 percent. Residential sales
growth in 1994 was 0.9%. Included in the 1994 retail increase is
$5.9 million related to the Company's large commercial and
industrial customers, some of which expanded their operations,
increasing energy needs. Also reflected in the retail revenue
increase is a decrease of $0.6 million due to the cooler summer
weather of 1994.
The Company's wholesale customers accounted for 4.6 percent
of the total electric revenues. Wholesale revenues increased
$1.4 million or 8.8 percent in 1994. In addition to fuel clause
revenues having increased, there was a 5.0 percent growth in
sales for resale. Long-term contracts signed with five wholesale
customers during 1994 did not materially affect revenues.
Another major component (approximately 19.6 percent) of
electric revenues is charges billed to the Minnesota Company
through the Interchange Agreement (see Part I, Item 1; Business-
Electric Operations). Interchange Agreement billings charged to
the Minnesota Company increased $1.3 million as a result of
increased fuel being burned in the Wisconsin Company to support
the systems' increased requirements.
Other electric revenues increased $0.8 million in 1994,
largely due to an increase in recorded fuel clause adjustments.
<PAGE>
Gas Sales and Revenues
Gas revenues in 1994 increased by $4.0 million or 5.4
percent as compared with 1993. This is the net impact of
increased revenues due to the $1.4 million rate increase
effective January 1994, increased revenues due to a 1.8% increase
in firm sales due to customer and usage growth, and decreased
revenues of $1.1 million due to 1994's comparably more moderate
winter weather.
Operating Expenses and Other Factors
Electric Production The cost of interchange power increased
$11.6 million or 7.2 percent in 1994 compared to the same period
one year ago. This expense represents charges billed from the
Minnesota Company through the Interchange Agreement (see Part I,
Item 1: Business-Electric Operations). The company's increased
electric sales during 1994 over 1993, combined with increased
costs per MWH for nuclear and fossil fuels and increased costs
associated with capacity charges from the power purchase
agreements with Manitoba Hydro-Electric Board, which went into
effect in May 1993, resulted in the company's purchased power and
fuel purchased under its interchange agreement with its parent to
increase by approximately $10.7 million. Total interchange power
also increased by $0.4 million as a result of increased operation
and maintenance expenses and by $0.5 million as a result of
increased fixed charges such as depreciation and property taxes.
Fuel for Electric Generation Fuel for electric generation,
which represents the Company's portion of the NSP System's fuel
generation, increased $2.2 million or 70.0 percent in 1994 from
1993. This is due to the Minnesota Company's decreased fuel
generation combined with the Company's increased requirements due
to the increased sales in 1994.
Gas Purchased for Resale This cost increased $2.0 million
or 3.9 percent. A seven percent increase in total gas deliveries
was responsible for $3.6 million of increase in 1994. A 1.3
percent decrease in prices resulted in the balance of the change
from 1993.
Administrative and General, Other Operation and Maintenance
The $1.6 million increase in Other Operation expense is partially
due to demand side management expense increases ($0.7 million)
and increases in transmission expenses charged from the Minnesota
Company ($0.3 million). The remaining increases were related to
postemployment benefit costs and general increases in operating
expenses.
Depreciation and Amortization The increase in depreciation
between 1994 and 1993 primarily reflects higher levels of
depreciable plant, particularly shorter-lived computer equipment.
Property and General Taxes The property and general taxes
increase is primarily due to higher gross receipts tax (a tax
assessed on prior year revenues) as a result of 1993 revenues
increasing over 1992 revenues.
Income Taxes $2.2 million of the decrease in income taxes
in 1994 below 1993 is the result of a non-recurring adjustment to
the balance of the tax accruals for prior years due to the recent
conclusion by the Internal Revenue Service of audits of all the
Company's tax years through 1988. The balance of the change is
primarily attributable to the decrease in pretax book income.
See Note 8 to the Financial Statements for a detailed
reconciliation of effective tax rates and statutory rates.
Allowances for Funds Used During Construction (AFC) The
differences in AFC for the reported periods are attributable to
varying levels of qualifying construction and lower AFC rates
associated with increased use of low-cost short-term borrowings.
Interest Charges In March 1993, the Company issued $110.0
million of first mortgage bonds due March 1, 2023 with an
interest rate of 7-1/4%. The proceeds from these bonds were used
to redeem $47.5 million of 9-1/4% bonds, $38.4 million of 9-
3/4%bonds, and $7.8 million of 9-1/4% bonds. In October 1993,
the Company issued $40.0 million of first mortgage bonds due
October 1, 2003 with an interest rate of 5-3/4%. The proceeds
from these bonds were used to redeem $24.3 million of 7-3/4%
bonds and $10.8 million of 4-1/2% bonds.
These transactions caused decreases in the 1994 interest and
amortization charges compared to the charges of 1993 because in
1993 for one year only, all costs associated with the redemption
of these bonds were treated on a basis by which all savings of
interest due to refinancing was offset by the amortization of the
costs as required and approved by the PSCW.
In February 1995, the Company purchased $2.9 million of it's
9 1/8 Series bonds at the rate of
101 1/8.
<PAGE>
Item 8 Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for financial statements
included herein.
See Note 12 to the financial statements for summarized
quarterly financial data.
INDEPENDENT AUDITORS' REPORT
Northern States Power Company (Wisconsin):
We have audited the accompanying financial statements, of
Northern States Power Company (Wisconsin), listed in the
accompanying table of contents of Item 14(a)1. These financial
statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on the 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, such financial statements present fairly, in all
material respects, the financial position of the Company at
December 31, 1994 and 1993 and the results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1994 in conformity with generally accepted
accounting principles.
Minneapolis, Minnesota
January 27, 1995
<PAGE>
Item 8 Financial Statements and Supplementary Data
Statements of Income and Retained Earnings Year Ended December 31
(Thousands of dollars) 1994 1993 1992
Operating Revenues
Electric $ 374 777 $ 362 473 $ 345 289
Gas 76 715 72 760 61 071
Total 451 492 435 233 406
360
Operating Expenses
Purchased and interchange power 174 144 162 510 156 196
Fuel for electric generation 5 414 3 185 2 034
Gas purchased for resale 53 484 51 501 41 814
Administrative and general 26 487 26 842 21 610
Other operation 44 260 43 351 42 254
Conservation 7 211 6 556 5 216
Maintenance 22 385 21 703 21 806
Depreciation and amortization 30 736 28 585 26 832
Property and general taxes 13 710 13 091 12 925
Income taxes 19 077 23 103 22 184
Total operating expenses 396 908 380 427 352 871
Operating Income 54 584 54 806 53 489
Other Income and Deductions
Allowance for funds used
during construction-equity 671 694 907
Other income and deductions 864 844 1 361
Total Other Income 1 535 1 538 2 268
Income Before Interest Charges 56 119 56 344 55 757
Interest Charges
Interest on long-term debt 15 995 16 343 17 269
Other interest and amortization 2 060 2 406 857
Allowance for funds used
during construction-debt (481) (411) (569)
Total interest charges 17 574 18 338 17 557
Net Income 38 545 38 006 38 200
Retained Earnings, January 1 205 114 192 816 179 510
Dividends (24 826) (25 708)(24 894)
Retained Earnings, December 31 $ 218 833 $ 205 114 $ 192 816
See Notes to Financial Statements.
Item 8 Financial Statements and Supplementary Data
Statements of Cash Flow Year Ended December 31
(Thousands of dollars) 1994 1993 1992
Cash Flows from Operating Activities:
Net Income $38 545 $38 006 $38 200
Adjustments to reconcile net
income to cash from operating activities:
Depreciation and amortization 32 382 33 580 28 179
Deferred income taxes 7 614 7 228 3 089
Investment tax credit adjustments (943) (948) (956)
AFC-equity (671) (694) (907)
Insurance receivable (3 091)
Other (6 076) (2 440)
Cash (used for) provided by changes
in certain working capital items (9 568) 299 2 438
Net Cash Provided by Operating Activities58 192 77 471 67 603
Cash Flows from Financing Activities:
Proceeds from issuance of
long-term debt 0 146 587 0
Proceeds from issuance of
notes payable-parent company 17 800 0 12 600
Repayment of notes payable-parent company 0 (800) 0
Repayment of long-term debt (990) (136 090) (1 415)
Dividends paid to parent (24 826) (25 708) (24 894)
Net Cash Used for Financing Activities (8 016) (16 011) (13 709)
Cash Flows from Investing Activities:
Construction expenditures capitalized (52 639) (59 954) (54 588)
Decrease in construction payables (633) (2 143) (2 013)
AFC-equity 671 694 907
Other 2 037 (489) 0
Net Cash Used for Investing Activities (50 564) (61 892) (55 694)
Net Decrease in Cash (388) (432) (1 800)
Cash at Beginning of Period 449 881 2 681
Cash at End of Period $ 61 $ 449 $ 881
Cash (used for) provided by changes in certain working capital items:
Accounts receivable-net $ 770 $ (1 597) $ 921
Materials and supplies( (4 708) (453) (647)
Accounts payable and accrued liabilities 332 7 633 412
Payables to affiliated companies (2 655) 127 2 444
Income and other taxes accrued (4 174) (2 762) 634
Other 867 (2 649) (1 326)
Net $ (9 568) $ 299 $ 2 438
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest
(net of amount capitalized) $ 15 870 $ 17 440 $ 17 136
Income taxes $18 773 $ 18 825 $ 19 256
See Notes to Financial Statements.
<PAGE>
Item 8 Financial Statements and Supplementary Data
Balance Sheets December 31
(Thousands of dollars) 1994 1993
Assets
Utility Plant
Electric-including construction work in progress:
1994, $14,599; 1993, $16,697 $ 836 665 $ 810 691
Gas 88 350 81 567
Other 54 675 43 279
Total 979 690 935 537
Accumulated provision for depreciation (344 675) (320 938)
Net utility plant 635 015 614 599
Other Property and Investments
Nonutility property - at cost 3 082 3 157
Accumulated provision for depreciation (365) (364)
Other investments -
at cost which approximates market 3 974 4 094
Total other property and investments 6 691 6 887
Assets
Cash 61 449
Accounts receivable 37 484 38 424
Accumulated provision
for uncollectible accounts (538) (708)
Materials and supplies - at average cost
Fuel 3 413 2 293
Other 12 280 8 692
Accrued utility revenues 16 409 17 230
Prepayments and other 11 030 9 855
Deferred tax asset 1 415 1 254
Total current assets 81 554 77 489
Other Assets
Unamortized debt expense 2 928 3 078
Regulatory assets 31 376 30 036
Federal Income tax receivable 3 307 0
Insurance receivable 3 091 0
Other 4 338 4 890
Total deferred debits 45 040 38 004
Total $ 768 300 $ 736 979
See Notes to Financial Statements.
<PAGE>
Item 8 Financial Statements and Supplementary Data
December 31
(Thousands of dollars) 1994 1993
Liabilities and Equity
Capitalization
Common stock-authorized 870,000 shares of $100 par value;
issued shares: 1994 and 1993, 862,000 $ 86 200 $ 86 200
Premium on common stock 10 461 10 461
Retained earnings 218 833 205 114
Total common equity 315 494 301 775
Long-term debt 213 700 217 600
Total capitalization 529 194 519 375
Current Liabilities
Notes payable - parent company 41 300 23 500
Long-term debt due within one year 2 910 0
Accounts payable 14 415 15 264
Salaries, wages, and vacation pay accrued 6 028 5 481
Payables to affiliated companies
(principally parent) 8 982 11 636
Federal income taxes accrued 0 1 606
Other taxes accrued 936 2 492
Interest accrued 5 485 4 823
Other 1 463 1 917
Total current liabilities 81 519 66 719
Deferred Credits
Accumulated deferred income taxes 99 748 88 426
Accumulated deferred investment tax credits 22 332 23 653
Regulatory liability 17 961 22 416
Customer advances 5 543 5 071
Other 12 003 11 319
Total deferred credits 157 587 150 885
Commitments and Contingent Liabilities
Total $ 768 300 $ 736 979
See Notes to Financial Statements.
NORTHERN STATES POWER COMPANY (WISCONSIN)
NOTES TO FINANCIAL STATEMENTS
1. Summary of Accounting Policies
System of Accounts Northern States Power Company (Wisconsin),
("the Company"), maintains the accounting records in accordance
with either the uniform system of accounts prescribed by the
Federal Energy Regulatory Commission (FERC) or those prescribed by
the Public Service Commission of Wisconsin (PSCW) and the Michigan
Public Service Commission (MPSC), which systems are the same in all
material respects.
Investment in Subsidiaries The Company carries its investment
in its subsidiaries (Chippewa and Flambeau Improvement Company,
75.86% owned; NSP Lands, Incorporated, 100% owned; and Clearwater
Investments, Incorporated, 100% owned) at cost plus equity in
earnings since acquisition. The impact of consolidation of these
subsidiaries is considered immaterial to the Company's financial
position.
Utility Plant and Retirements Utility Plant is stated at
original cost. The cost of additions to utility plant includes
contracted work, direct labor and materials, allocable overheads
and allowance for funds used during construction (AFC). The cost
of units of property retired, plus net removal cost, is charged to
the accumulated provision for depreciation and amortization.
Maintenance and replacement of items determined to be less than
units of property are charged to operating expenses.
Insurance Receivable The Company has incurred repair costs on
a gas turbine that will be recovered from insurance. These costs
have caused the Company to pay out approximately $ 3 million.
Federal Income Tax Receivable The Company has filed an
amended tax return for the year 1992 which has resulted in a
reduction in taxes owed of approximately $3.3 million. The two
major items for the Wisconsin Company were the additional deduction
for the prepaid Wisconsin Annual License Fee and an additional
deduction for a change in Depreciation Expense.
Allowance for Funds Used during Construction (AFC) AFC, a
non-cash item, is computed by applying a composite pretax rate,
representing the cost of capital used to fund utility construction,
to qualified Construction Work in Progress (CWIP). The rates used
for the FERC calculation were 7.55 percent in 1994, 7.93 percent in
1993 and 8.78 percent in 1992. The rates used for the PSCW
calculation were 10.13 percent in 1994, 10.84 percent in 1993 and
11.52 percent in 1992. The amount of AFC capitalized as a
construction cost in CWIP is credited to other income and interest
charges. AFC amounts capitalized in CWIP are included in utility
rate base for establishing utility service rates.
Related Party Transactions All significant intercompany
transactions and balances have been eliminated in consolidation
except for intercompany and intersegment profits for sales among
the electric and gas utility businesses of the Company, the
Minnesota Company and Viking, which are allowed in utility rates.
Depreciation For financial reporting purposes, depreciation
is computed on the straight-line method based on the annual rates
certified by the PSCW and MPSC for the various classes of property.
Depreciation provisions, as a percentage of the average balance of
depreciable property in service, were 3.45% in 1994, 3.40% in 1993,
and 3.38% in 1992.
Revenues Customers' meters are read and bills rendered on a
cycle basis. The Company accrues the amount of estimated unbilled
revenues for services provided from the monthly meter reading date
to month-end. The current asset, accrued utility revenues, is
being adjusted monthly, with a corresponding adjustment to
revenues, to reflect changes in unbilled revenues.
Regulatory Deferrals As a regulated utility, the Company
accounts for certain income and expense items under the provisions
of SFAS No. 71 - Accounting for the Effects of Certain Types of
Regulation. In doing so, certain costs which would otherwise be
charged to expense are deferred as regulatory assets based on
expected recovery from customers in future rates. Likewise,
certain credits which would otherwise be reflected as income are
deferred as regulatory liabilities based on expected flowback to
customers in future rates. Management's expected recovery of
deferred costs and expected flowback of deferred credits is
generally based on specific ratemaking decisions or precedent for
each item. Regulatory assets and liabilities are being amortized
consistent with ratemaking treatment as established by regulators.
Income Taxes The Company records income taxes in accordance
with Statement of Financial Accounting Standards No. 109 (SFAS 109)
- Accounting For Income Taxes. SFAS 109 requires the use of the
liability method of accounting for deferred income taxes. Before
1993, the Company followed Statement of Accounting Standards No. 96
(SFAS 96) - Accounting for Income Taxes, resulting in substantially
the same accounting for the Company as SFAS No. 109.
Income taxes are deferred for temporary differences between
pretax financial and taxable income, and between the book and tax
bases of assets and liabilities. Deferred taxes are recorded using
the tax rates scheduled by tax law to be in effect when the
temporary differences reverse. Due to the effects of regulation,
income tax expense is provided for the reversal of some temporary
differences previously accounted for by the flow-through method.
Deferred income tax expense for 1994, 1993, and 1992 consists
primarily of excess tax depreciation over book depreciation of
$4,800,000, $5,413,000, and $5,526,000, respectively.
Investment tax credits are deferred and amortized over the
estimated lives of the related property.
Purchased Tax Benefits The Company purchased tax-benefit
transfer leases under the Safe Harbor Lease provisions of the
Economic Recovery Tax Act of 1981. For both financial reporting
and regulatory purposes, the Company is amortizing the difference
between the cost of the purchased tax benefits and the amounts to
be realized through reduced current income tax liabilities over the
remaining terms of the lease after the initial investments have
been recovered.
Environmental Costs Accruals for environmental costs are
recognized when it is probable that a liability has been incurred
and the amount of the liability can be reasonably estimated. When
a single estimate of the liability cannot be determined, the low
end of the estimated range is recorded. Costs are charged to
expense (or deferred as a regulatory asset based on expected
recovery from customers in future rates) if they relate to the
remediation of conditions caused by past operations or if they are
not expected to mitigate or prevent contamination from future
operations. Where environmental expenditures related to facilities
currently in use (such as pollution control equipment), the costs
may be capitalized and depreciated over the future service periods.
Estimated remediation costs are recorded at undiscounted amounts,
independent of any insurance or rate recovery, based on prior
experience, assessments and current technology. Accrued
obligations are regularly adjusted as environmental assessments and
estimates are revised, and remediation efforts proceed. For sites
where NSP has been designated as one of several potentially
responsible parties, the amount accrued represents NSP's estimated
share of the cost. NSP intends to treat any future costs related
to decommissioning and restoration of its power plants and
substation sites as a removal cost of retirement through plant
depreciation expense.
2. Rate Matters
The Company filed a proposal for a new high load factor rate
with the PSCW in November, 1994, that becomes effective January 1,
1995. Under the proposal, qualifying customers would receive a
credit on their bills of up to 3.0% depending on their load factor.
This is expected to reduce 1995 revenues by approximately $1.5
million.
On December 23, 1993, the PSCW issued an order approving a $1.41
million (2.0 percent) increase on an annual basis in the Company's
gas rates. A January 1, 1994 effective date was authorized for
these rate changes. No change in the retail electric rates was
requested.
The Company will file a submittal in June 1995 as required by
the PSCW biennial filing requirement.
<PAGE>
In May, 1994, the Company offered its municipal wholesale
customers a discount of one to two percent off the FERC authorized
rate for a long-term full requirements commitment between five and
ten years with comparable cancellation notices. Five of the ten
municipal wholesale customers signed up for the discounts. The
total annual decrease in revenues is approximately $80,000.
3. Accounting Changes
Postemployment Benefits Effective January 1, 1994, the Company
adopted the provisions of Statement of Financial Accounting
Standards (SFAS) No. 112---Employer's Accounting for Postemployment
Benefits. This standard required the accrual of certain
postemployment costs (such as injury compensation and severance)
that are payable in future time periods. The annual expense for
costs accrued under SFAS No. 112 is not materially different than
amounts recognized under the Company's prior accounting method.
The Company has recorded as expense its full liability related to
such costs in 1994.
4. Investments Accounted for by the Equity Method
NSP has subsidiaries with investments in domestic affordable
housing and real estate projects. The equity method of accounting
is applied to such investments.
5. Long-Term Debt
First Mortgage Bonds - less reacquired bonds of $490 and $0 at
December 31, 1994
and 1993, respectively:
December 31 December 31
Series due: 1994 1993
Apr. 1, 2021, 9-1/8% $ 48 010 $ 49 000
Mar. 1, 2023, 7 1/4% 110 000 110 000
Oct. 1, 2003, 5 3/4% 40 000 40 000
Total $198 010 $199 000
Less April 1, 2021, 9 1/8%
bonds redeemed in February 1995 2 910
Net $195 100 $199 000
City of LaCrosse Resource Recovery Revenue Bonds -
Series due Nov. 1, 2011, 7 3/4% 18 600 18 600
Total long-term debt $ 213 700 $ 217 600
The Supplemental and Restated Trust Indenture dated March 1,
1991, permits an amount of established Permanent Additions to be
deemed equivalent to the payment of cash necessary to redeem 1% of
the highest principal amount of each series of first mortgage bonds
(other than pollution control financing) at any time outstanding.
This Supplemental and Restated Trust Indenture became effective for
the Company on October 1, 1993.
On March 16, 1993 the Company issued $110.0 million of first
mortgage bonds due March 1, 2023, with an interest rate of 7 1/4%.
NSP entered into an interest rate swap agreement with $20.0 million
of this first mortgage bonds. This agreement effectively converts
the interest costs of this debt issue from fixed to variable rates
based on six-month London Interbank Offered Rates (LIBOR) with the
rates changing semi-annually, March 1 and September 1. This Series
is due March 1, 2023, has a Swap Agreement Term dated March 1, 1998
and had a net effective interest rate of 7.43% at December 31,
1994.
Market risks associated with this agreement results from
short-term interest rate fluctuations. Credit risk related to non-
performance of the counterparties is not deemed significant, but
would result in NSP terminating the swap transaction and
recognizing a gain or loss, depending on the fair market value of
the swap. While such agreements are not reflected on NSP's balance
sheets, interest rate swap transactions are recognized as an
adjustment of interest expense over the terms of the agreements.
The interest rate swaps serve to hedge the interest rate risk
associated with fixed rate debt in a declining interest rate
environment. This hedge is produced by the tendency for changes in
the fair market value of the swap to be offset by changes in the
present value of the liability attributable to the fixed rate debt
issued in conjunction with the interest rate swap. If the interest
rate swap had been terminated at Dec. 31, 1994, $1.7 million would
have been payable by NSP while the present value of the fixed rate
debt issued with the swaps was $3.1 million below par value.
On February 1, 1995, the Company redeemed $2.9 million of its
9 1/8% bonds at 101-1/8%; this amount has, therefore, been
classified as current on the December 31, 1994 financial
statements.
Maturities on capital leases in the next five years are
approximately $943,000, $1,034,000, $724,000, $409,000, and
$92,000, respectively for the years 1995-1999.
Except for minor exclusions, all real and personal property is
subject to the lien of the Company First Mortgage Bond Trust
Indenture.
6. Commitments and Contingent Liabilities
The Company presently estimates capital expenditures will be
$55.2 million in 1995 and $286 million for
1995-99.
Rentals under operating leases were approximately $1,792,000,
$2,651,000, and $2,547,000, for 1994, 1993, and 1992, respectively.
Although the Company does not own a nuclear facility, any
assessment made against Northern States Power Company (Minnesota),
the parent company, ("Minnesota Company") and under the Price-
Anderson liability provisions of the Atomic Energy Act of 1954,
would be a cost included under the Interchange Agreement (Note 9)
and the Company would be charged its proportion of the assessment.
Such provisions set a limit of $8.9 billion for public liability
claims that could arise from a nuclear incident. The parent
company has secured insurance of $200 million to satisfy such
claims. The remaining $8.7 billion of exposure is funded by the
Secondary Financial Protection Fund, a fund available from
assessments by the Federal government in the event of nuclear
incidents. The parent company is subject to an assessment of $79.3
million for each of its three licensed reactors to be applied for
public liability arising from a nuclear incident at any licensed
nuclear facility in the United States with a maximum funding
requirement of $10 million per reactor during any one year.
The NSP Wisconsin policy is to proactively prevent adverse
environmental impacts, regularly monitor operations to ensure the
environment is not adversely affected, and take timely corrective
actions where past practices have had a negative impact on the
environment. Significant resources are dedicated to environmental
training, monitoring and compliance matters. The Company strives
to maintain compliance with all applicable environmental laws. A
preliminary allocation has been established for one of the
landfills for those contributing any type of wastes to it. Based
on the preliminary allocation of costs, the Company's share of one
of the landfills would be less than $20,000. An allocation has not
yet been made on the second landfill site.
On March 2, 1995, the Wisconsin Department of Natural
Resources (WDNR) notified the Company that it is a PRP on a
creosote/coal tar contamination site in Ashland, WI. The Company
has informed the WDNR of its belief that two sites exist. The
first site, formerly a coal gas plant site, is NSP property. The
second site is adjacent to the NSP site and is not owned by the
Company. An existing condition report has been completed on an
adjacent site. An estimate of site remediation costs, and the
extent of the Company's responsibility, if any, for sharing such
costs, is not known at this time. Investigations are underway to
determine the Company's responsibility as well as that of
predecessor companies contributing to the contamination on the
adjacent site. The current estimate of the Company's share of
future remediation costs at the NSP site is less than $750,000.
This estimate is not based upon a formal remediation investigation
and feasability study. To the Company's knowledge, no study has
been completed for the adjacent site, that describes remedial
alternatives and clean-up cost estimates. The Company intends to
seek rate recovery of significant costs it incurs associated with
the clean-up of either Ashland Site.
7. Fair Value of Financial Instruments
Statement of Financial Accounting Standards No. 107 (SFAS 107)
- Disclosures About Fair Value of Financial Instruments became
effective in 1992. For cash and investments, the carrying amount
approximates fair value. The fair value of the Company's long term
debt is estimated based on the quoted market prices for the same or
similar issues, or on the current rates offered to the Company for
debt of the same remaining maturities. The estimated fair value of
the Company's long term debt (including debt due within one year
classified as current) of $216.6 million at December 31, 1994, and
$217.6 million at December 31, 1993, is $196.2 million and $233.3
million, respectively.
8. Pension Plans and Other Post Retirement Benefits
Employees of the Company participate in the Northern States
Power Company Pension Plan. This noncontributory defined benefit
pension plan covers substantially all employees. Benefits are
based on a combination of years of service, the employees highest
average pay for 48 consecutive months and Social Security benefits.
The Company's portion of annual pension costs was $(631,000) for
1994, $1,236,000 for 1993, and $2,400,000 for 1992.
Until 1993, for financial reporting and regulatory purposes,
the Company's pension expense was determined and recorded under the
aggregate cost method, using market value of assets of the trust
fund. Statement of Financial Accounting Standards No. 87 -
Employers' Accounting for Pensions (SFAS 87) provides that any
difference between the pension expense recorded for rate making
purposes and the amounts determined under SFAS 87 should be
recorded as an asset or liability on the balance sheet.
Effective January 1, 1993, for financial reporting and
regulatory purposes, the Company's pension expense was determined
and recorded under the SFAS-87 method and the Company's accumulated
SFAS-87 asset is being amortized over a 15-year period.
<PAGE>
Net periodic pension costs for the total (the Company and
Minnesota Company) plan include the following components:
1994 1993 1992
(Thousands of dollars)
Service Cost - benefits earned
during the period $ 27 536 $ 25 015 $ 24 080
Interest cost on projected
benefit obligation 65 107 71 075 69 853
Actual return on assets (12 668)(152 019)(115 455)
Net amortization and deferral (82 114) 66 299 39 019
Net periodic pension cost
determined under SFAS 87 (2 139) 10 370 17 497
Expenses recognized (deferred)
due to actions
of regulators 3 922 5 117 2 741
Pension expense recorded
during the period 1 783 15 487 20 238
Portion of expense recognized for early retirement
program 0 0 ( 165)
Net periodic pension cost
recognized for ratemaking $ 1 783 $ 15 487 $ 20 073
The funding status for the total plan is as follows:
Actuarial present value of benefit obligation:
Vested $ 571 254 $ 655 002
Nonvested 120 420 139 346
Accumulated benefit obligation $ 691 674 $ 794 348
Projected benefit obligation $ 836 957 $974 160
Plan assets at fair value 1 165 584 1 244 650
Plan assets in excess
of projected benefit obligation (328 627) (270 490)
Unrecognized prior service cost (21 538) (22 580)
Unrecognized net (gain) 370 289 315 049
Unrecognized net transitional (asset) 691 767
Net pension liability recorded $ 20 815 $ 22 746
The weighted average discount rate used in determining the
actuarial present value of the projected obligation was 8% in 1994
and 7% in 1993. The rate of increase in future compensation levels
used in determining the actuarial present value of the projected
obligation was 5% in 1994 and 1993. The assumed long-term rate of
return on assets used for cost determinations under SFAS 87 was 8%
in 1994, 1993 and 1992. Plan assets consist principally of common
stock of public companies and U.S. Government Securities.
Effective Jan. 1, 1993, the Company adopted the provisions of
SFAS No. 106 - Employers' Accounting for Postretirement Benefits
Other Than Pensions. SFAS No. 106 requires that the actuarially
determined obligation for postretirement health care and death
benefits is to be fully accrued by the date employees attain full
eligibility for such benefits, which is generally when they reach
retirement age. This is a significant change from the Company's
pre-1993 policy of recognizing benefit costs on a cash basis after
retirement. In conjunction with the adoption of SFAS No. 106, for
financial reporting purposes, NSP elected to amortize on a
straight-line basis over 20 years the unrecognized accumulated
postretirement benefit obligation (APBO) of approximately $215.6
million (including the Company and Minnesota Company) for current
and future retirees. This obligation considered 1994
plan design changes, including Medicare integration, increased
retiree cost sharing and managed indemnity measures not in effect
in 1993.
Before 1993, NSP funded payments for retiree benefits
internally. While the Company generally prefers to continue using
internal funding of benefits paid and accrued, there have been some
external funding requirements imposed by the Company's regulators,
as discussed below, including the use of tax advantaged trusts.
Plan assets held in such trusts as of Dec. 31, 1994, consisted of
investments in equity mutual funds and cash equivalents. The
<PAGE>
following table sets forth the total (the Company and Minnesota
Company) health care plans funded status at December 31.
(Millions of dollars)
1994 1993
APBO:
Retirees $132.2 $120.2
Fully eligible plan participants 21.5 18.8
Other active plan participants 79.4 90.8
Total APBO 233.1 229.8
Plan Assets 8.0 6.1
APBO in excess of plan assets 225.1 223.7
Unrecognized net actuarial gain (loss) 2.3 (1.3)
Unrecognized transition obligation (194.0) (204.8)
Postretirement benefit obligation
included in balance sheet $ 33.4 $ 17.6
The assumed health care cost trend rate used in measuring the
APBO at Dec. 31, 1994 and 1993, respectively, were 11.0 and 14.1
percent for those under age 65 and 7.5 and 8.0 percent for those
over age 65. The assumed cost trend rates are expected to decrease
each year until they reach 5.5 percent for both age groups in the
year 2004, after which they are assumed to remain constant. A one
percent increase in the assumed health care cost trend rate for
each year would increase the APBO as of December 31, 1994, by
approximately 13 percent and service and interest cost components
of the net periodic postretirement cost by approximately 16
percent. The assumed discount rate used in determining the APBO
was 8 percent for Dec. 31, 1994, 7 percent for Dec. 31, 1993 and 7
percent for Jan. 1, 1993, compounded annually. The assumed long-
term rate of return on assets used for cost determinations under
SFAS No. 106 was 8 percent for all periods. While the 1994
assumption changes had no effect on 1994 benefit costs, the effect
of the changes in 1995 is expected to be a cost increase of
approximately $0.6 million (for the Company and the Minnesota
Company). Similarly, the assumption changes made for the Dec. 31,
1993 calculations had no effect on 1993 benefit costs, but
decreased 1994 costs by approximately $2 million (for the Company
and the Minnesota Company).
In 1992, the Company recognized $1.9 million as the cost
attributable to postretirement health care and death benefits based
on payments made. The net annual periodic postretirement benefit
cost recorded for 1994 and 1993 consists of the following
components (millions of dollars):
1994 1993
Service cost-benefits earned during the year $ 0.6 0.6
Interest cost (on service cost and APBO) 2.3 2.4
Amortization of transition obligation 1.5 1.5
Return on assets (.2) (.1)
Net periodic postretirement health care
cost under SFAS No. 106 4.2 4.4
The Company's regulators have allowed full recovery of increased
benefit costs under SFAS No. 106, effective in 1993. External
funding was required in Wisconsin and Michigan to the extent it is
tax advantaged. The FERC has required external funding for all
benefits paid and accrued under SFAS No. 106. Funding began for
both retail and FERC in 1993.
401(k) NSP has a contributory, defined contribution Retirement
Savings Plan (the Plan), which complies with section 401-K of the
Internal Revenue code and covers substantially all employees. The
NSP match to this Plan began in 1994 and is required to match a
specified amount of employee contributions. The Company's
contribution to the Plan in 1994 was $0.3 million. <PAGE>
9.
Parent Company and Intercompany Agreements
The Company is wholly-owned by Northern States Power Company
(Minnesota). The electric production and transmission costs of the
NSP system are shared by the Company and the Minnesota Company. A
FERC approved agreement (Interchange Agreement) between the Company
and the Minnesota Company provides for the sharing of all costs of
electric generation and transmission facilities of the NSP System,
including capital costs. Billings under the Interchange Agreement
and an intercompany gas agreement which are included in the
statement of income are as follows:
Year Ended December 31
1994 1993 1992
(Thousands of dollars)
Operating revenues:
Electric $ 73 503 $ 72 162 $ 70 671
Gas 50 56 55
Operating expenses:
Purchased &interchg power 174 144 162 510 156 196
Gas purchased for resale 227 267 214
Other operation 12 824 12 515 11 668
10. Regulatory Assets and Liabilities
The following summarizes the individual components of
unamortized regulatory assets and liabilities shown on the Balance
Sheet at Dec. 31:
(Thousands of dollars) Amortization Period 1994 1993
AFC recorded in plant
on a net-of-tax basis Plant Lives 8 325 8 795
Losses on reacquired
debt Term of Debt 10 303 10 857
Conservation and energy
management programs Up to 10 years 10 622 8 291
Pensions and other 3-15 years 2 126 2 093
Total Regulatory Assets 31 376 30 036
Excess deferred income taxes collected
from customers 2 853 5 914
Investment tax credit deferrals 14 950 15 841
Fuel refunds and other 158 661
Total Regulatory Liabilities 17 961 22 416
The AFC regulatory asset and the tax-related regulatory
liabilities result from the Company's adoption of SFAS No. 96 in
1988 and SFAS No. 109 in 1993. The excess deferred income tax
liability represents the net amount expected to be reflected in
future customer rates based on the collection in prior ratemaking
of deferred income tax amounts in excess of the actual liabilities
currently recorded by the Company. This excess is the net effect
of the use of "flow through" tax accounting in prior ratemaking and
the impact of changes in statutory tax rates in 1981, 1986-87 and
1993. This regulatory liability will change each year as the
related deferred income tax liabilities reverse.
11. Income Tax Expense
The Company is included in the consolidated Federal income tax
return filed by the Minnesota Company and files separate state
returns for Wisconsin and Michigan. The Company records current
and deferred income taxes at the statutory rates as if it filed a
separate return for Federal income tax purposes. All tax payments
are made directly to the taxing authorities.
<PAGE>
The total income tax expense differs from the amount computed by
applying the Federal income tax statutory rate of 35% to net income
before income tax expense. The reasons for the difference are as
follows:
1994 1993 1992
(Thousands of dollars)
Tax computed at statutory rate $ 20 074 $ 21 387 $20 434
Increases (decreases) in tax from:
State income taxes, net of
Federal income tax benefit 2 393 3 165 3 037
Allowance for funds used during
construction (235) (243) (284)
Investment tax credit
adjustments - net (943) (948) (956)
Use of the flow-through method for
depreciation in prior years 551 474 673
Effect of tax rate changes for
plant related items (498) (487) (420)
Gain on sale of tax benefit
transfer leases 0 (88) 0
Non-recurring adjustment for tax
accrual of prior years (2 430)
Other - net (101) (162) (583)
Total income tax expense $ 18 811 $ 23 098 $ 21 901
Effective income tax rate
32.8% 37.8% 36.4%
Income tax expense is comprised of the following:
Included in income taxes:
Current Federal tax expense 8 075 $ 12 919 $15 340
Current state tax expense 2 810 3 180 3 598
Deferred Federal tax expense 7 967 6 173 3 075
Deferred state tax expense 1 168 1 778 1 127
Investment tax credit
adjustments - net (943) (948) (956)
Total 19 077 23 103 22 184
Included in income deductions:
Current Federal tax expense 1 039 875 953
Current state tax expense 216 (90) (123)
Deferred Federal and state
tax expense (1 521) (790) (1 113)
Total income tax expense $ 18 811 $ 23 098 $ 21 901
The components of the Company's net deferred tax liability at Dec.
31 were as follows:
(Thousands of dollars) 1994 1993
Deferred tax liabilities:
Differences between book and
tax bases of property $ 98 526 $ 91 195
Tax benefit transfer leases 4 950 6 146
Regulatory assets 11 626 11 371
Other 3 332 398
Total deferred tax liabilities 118 434 109 110
Deferred tax assets:
Deferred investment tax credits 7 409 9 487
Regulatory liabilities 8 955 8 726
Deferred compensation accrued vacation
and other reserves not currently
deductible 3 155 3 193
Other 582 532
Total deferred tax assets 20 101 21 938
Net deferred tax liability $ 98 333 $ 87 172<PAGE>
The Omnibus Budget Reconciliation Act of 1993 (Act) was signed
into law on August 10, 1993, and increased the federal corporate
income tax rate from 34 percent to 35 percent retroactive to
January 1, 1993. Deferred tax liabilities were increased for the
rate change by $2.7 million. However, due to the effects of
regulation, earnings were reduced only by immaterial adjustments to
deferred tax liabilities related to nonutility operations.
12. Segment Information
Year Ended December 31
1994 1993 1992
(Thousands of dollars)
Operating revenues:
Electric $374 777 $362 473 $345 289
Gas 76 715 72 760 61 071
Total operating revenues $451 492 $435 233 $406 360
Operating income before income taxes:
Electric $ 67 164 $ 73 012 $ 70 202
Gas 6 498 4 897 5 471
Total operating
income before
income taxes $ 73 662 $ 77 909 $ 75 673
Depreciation and amortization:
Electric $26 836 $ 25 179 $ 23 870
Gas 3 900 3 406 2 962
Total depreciation & amortization $ 30 736 $ 28585 $26832
Construction expenditures:
Electric $ 42 820 $ 49 664 $ 44 332
Gas 9 895 10 258 10 235
Total construction expenditures $ 52 715 $ 59 922 $ 54 567
Net utility plant:
Electric $575 059 $560 999 $537 576
Gas 59 956 53 600 47 419
Total net utility plant 635 015 614 599 584 995
Other corporate assets 133 285 122 380 109 474
Total assets $768 300 $736 979 $694 469
13. Short-Term Borrowings
The Company had bank lines of credit aggregating $1,000,000 at
December 31, 1994. Compensating balance arrangements in support of
such lines of credit were not required. These credit lines make
short-term financing available by providing bank loans. During
1994 and 1993 there were no bank loans outstanding as the Company
obtained short-term borrowings from the Minnesota Company at the
Minnesota Company's average daily interest rate, including the cost
of their compensating balance requirements.
<PAGE>
The Company had short-term borrowings of the following for the
years ended December 31,
1994 1993 1992
Balance at the end of the period 41 300 23 500 24300
Weighted average interest rate 5.0% 3.3% 3.5%
Maximum amount outstanding during
the period 45 700 28 200 24 300
Average amount outstanding
during the period 13 124 10 693 8 837
Weighted average interest
rate during the period 5.0% 3.4% 3.7%
14. Common Stock
The Company's common shares have a par value of $100 per share.
At December 31, 1994 and 1993, 870,000 shares were authorized and
862,000 shares were issued.
15. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended
March 31, June 30, September 30 December31
1994 1994 1994 1994
(Thousands of dollars)
Operating revenues $ 134 004 $ 100 105 $ 101 100 $ 116 283
Operating income 22 268 7 273 9 416 15 627
Net income 18 306 3 441 4 894 11 904
Quarter Ended
March 31, June 30, September 30 December31
1993 1993 1993 1993
(Thousands of dollars)
Operating revenues $ 124 285 $ 97 107 $ 97 821 $ 116 020
Operating income 20 080 10 199 7 986 16 541
Net income 15 857 6 062 3 762 12 325
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
During 1994 there were no disagreements with the Company's
independent certified public accountants on accounting procedures
or accounting and financial disclosures.<PAGE>
PART III
Part III of Form 10-K has been omitted from this report in
accordance with conditions set forth in general instructions J (1)
(a) and (b) of Form 10-K for wholly-owned subsidiaries.
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of certain beneficial Owners
and Management
Item 13. Certain Relationships and Related Transactions<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules
Page
and Reports on Form 8-K
(a) 1. Financial Statements
Included in Part II of this report:
Report of Independent Public Accountants. 13
Statements of Income and Retained Earnings for
the three years ended December 31, 1994. 14
Statements of Cash Flows for the three
years ended December 31, 1994. 15
Balance Sheets, December 31, 1994 and 1993. 16
Notes to Financial Statements. 18
2. Financial Statement Schedules
Schedules above are omitted because of the absence of the
conditions under which they are required or because the
information required is included in the financial
statements or the notes.
3. Exhibits
* indicates incorporation by reference
3.01*Restated Articles of Incorporation as of December
23, 1987.
(Filed as Exhibit 30.01 to Form 10-K Report 10-3140 for
the year 1987)
3.02* Copy of the By-Laws of the Company as amended
August 19, 1992.
(Filed as Exhibit 3.02 to Form 10-K Report 10-3140
for the year 1992)
4.01* Copy of Trust Indenture, dated April 1, 1947,
From the Wisconsin Company to First Wisconsin Trust
Company. (Filed as Exhibit 7.01 to Registration
Statement 2-6982)
4.02* Copy of Supplemental Trust Indenture, dated
March 1, 1949.
(Filed as Exhibit 7.02 to Registration Statement 2-
7825)
4.03* Copy of Supplemental Trust Indenture, dated
June 1, 1957.
(Filed as Exhibit 2.13 to Registration Statement 2-
13463)
4.04* Copy of Supplemental Trust Indenture, dated
August 1, 1964.
(Filed as Exhibit 4.20 to Registration Statement 2-
23726)
4.05* Copy of Supplemental Trust Indenture, dated
December 1, 1969.
(Filed as Exhibit 2.03E to Registration Statement 2-
36693)
4.06* Copy of Supplemental Trust Indenture, dated
September 1, 1973.
(Filed as Exhibit 2.01F to Registration Statement 2-
48805)
4.07* Copy of Supplemental Trust Indenture, dated
February 1, 1982.
(Filed as Exhibit 4.01G to Registration Statement 2-
76146)
4.08* Copy of Supplemental Trust Indenture, dated
March 1, 1982.
(Filed as Exhibit 4.08 to form 10-K Report 10-3140
for the year 1982)
4.09* Copy of Supplemental Trust Indenture, dated
June 1, 1986.
(Filed as Exhibit 4.09 to Form 10-K Report 10-3140
for the year 1986)
4.10* Copy of Supplemental Trust Indenture, dated
March 1, 1988.
(Filed as Exhibit 4.10 to Form 10-K Report 10-3140
for the year 1988)
4.11* Copy of Supplemental and Restated Trust
Indenture, dated March 1, 1991. (Filed as Exhibit
4.01K to Registration Statement 33-39831)
4.12* Copy of Supplemental Trust Indenture, dated
April 1, 1991.
(Filed as Exhibit 4.01 to Form 10-Q Report 10-3140
for the
quarter ended March 31, 1991)
4.13* Copy of Supplemental Trust Indenture, dated
March 1, 1993.
(Filed as Exhibit to Form 8-K Report dated March 3,
1993)
4.14* Copy of Supplemental Trust Indenture, dated
October 1, 1993.
(Filed as Exhibit 4.01 to Form 8-K Report dated
September 21, 1993)
10.01 *Copy of MAPP Agreement, dated March 31, 1972,
between the local power suppliers in the North
Central States area.
(Filed as Exhibit 5.06B to Registration Statement 2-
44530)
10.02* Copy of Interchange Agreement dated September
17, 1984, and
Settlement Agreement dated May 31, 1985, between the
Company, the
Minnesota Company and LSDP. (Filed as Exhibit 10.10
to Form 10-K
Report 10-3140 for the year 1985)
(b) Reports on Form 8-K
On December 20, 1994, a Form 8-K was filed reporting (as Item
4, Changes in Registrant's Certifying Accountant and Item 7,
Financial Statements and Exhibits), the Company's change in
Certifying Accountant.
<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 annual report to be
signed on its behalf by the undersigned, thereunto
authorized.
NORTHERN STATES POWER COMPANY
/s/
John A. Noer
President and Chief Executive
Pursuant to the requirements of the Securities
Exchange Act of 1934, this report signed below
by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
/s/
John A. Noer
(Principal Executive Officer)
/s/ /s/
M. N. Gregerson H. Lyman Bretting
Vice President-Customer Services Director
/s/ /s/
A. G. Schuster P. M. Gelatt
Vice President Director
Power Delivery and Generation
/s/ /s/
Patrick D. Watkins Wayne E. Harrison
Vice President-Corporate Services Director
/s/ /s/
John P. Moore, Jr. Loren L. Taylor
General Counsel and Secretary Director
/s/ /s/
Kenneth J. Zagzebski Ray A. Larson, Jr.
Controller Director
(Principal Accounting Officer)
/s/ /s/
Neal A. Siikarla Larry G. Schnack
Treasurer Director
(Principal Financial Officer)<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 annual report to be signed
on its behalf by the undersigned, thereunto
authorized.
NORTHERN STATES POWER COMPANY
John A. Noer
President and Chief Executive
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report signed below
by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
John A. Noer
President and Director
(Principal Executive Officer)
M. N. Gregerson H. Lyman Bretting
Vice President-Customer Services Director
A. G. Schuster P. M. Gelatt
Vice President Director
Power Delivery and Generation
Patrick D. Watkins Wayne E. Harrison
Vice President-Corporate Services Director
John P. Moore, Jr. Loren L. Taylor
General Counsel and Secretary Director
Kenneth J. Zagzebski Ray A. Larson, Jr.
Controller Director
(Principal Accounting Officer)
Neal A. Siikarla Larry G.Schnack
Treasurer Director
(Principal Financial Officer)<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X Annual report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 (fee required)
or
Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
(no fee required)
For the fiscal year ended December 31, 1994
Commission file number: 10-3140
Northern States Power Company, a Wisconsin
corporation, meets the conditions set forth in general
instruction J (1) (a) and (b) of Form 10-K and is therefore
filing this form with the reduce disclosure format.
(In general instruction J(2)
Northern States Power Company
(Exact name of registrant as specified in its charter)
Wisconsin 39-0508315
(State or other jurisdiction of
(I.R.S. employer identification number)
incorporation or organization)
100 North Barstow Street 54702-0008
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (715) 839-2621
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
None
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 .
Indicate the number of shares outstanding of each of the
registrant's classes of common stock as of the latest practicable date.
Class Outstanding at March 23, 1995
Common Stock, $100 Par Value 862,000 Shares
All outstanding common stock is owned beneficially and of
record by Northern States Power Company, a Minnesota
corporation.
Documents Incorporated by Reference
None
<PAGE>
INDEX Page No.
PART I
Item 1 Business . . . . . . . . . . . . . . . . . . . . . . . 1
REGULATION AND RATES
Regulation . . . . . . . . . . . . . . . . . . . .. . 1
Rate Changes . . . . . . . . . . . . . . . . . . .. . 2
Fuel and Purchased Gas Adjustment Clauses. . . . .. . 3
Demand Side Management . . . . . . . . . . . . . .. . 3
ELECTRIC OPERATIONS
Competition. . . . . . . . . . . . . . . . . .. . . . 4
NSP System . . . . . . . . . . . . . . . . . .. . . . 4
Capability and Demand. . . . . . . . . . . . .. . . . 5
Interchange Agreement. . . . . . . . . . . . .. . . . 6
Electric Power Pooling Agreements. . . . . . .. . . . 6
Fuel Supply. . . . . . . . . . . . . . . . . .. . . . 6
Electric Operating Statistics . . . . . . . .. . . . 7
GAS OPERATIONS . . . . . . . . . . . . . . . . .. . . . 7
ENVIRONMENTAL MATTERS . . . . . . . . . . . .. . . . . 8
CONSTRUCTION AND FINANCING . . . . . . . . . . . . . . 9
EMPLOYEES AND EMPLOYEE BENEFITS. . . . . . . .. . . . . 10
Item 2 Properties . . .. . . . . . . . . . . . . . . . . . . . 12
Item 3 Legal Proceedings. . .. . . . . . . . . . . . . . . . . 12
Item 4 Submission of Matters to a Vote of
Security Holders . . .. . . . . . . . . . . . 13
PART II
Item 5 Market Price of and Dividends on the Registrant's Common Equity
and Related Stockholder Matters. . . . . . . . 14
Item 6 Selected Financial Data. . . . . . . . . . . . . . . . . 14
Item 7 Management's Discussion and Analysis . . . . . . . . . . 14
Item 8 Financial Statements and Supplementary Data. . . . . . . 17
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure . . . . 32
PART III
Item 10 Directors and Executive Officers of the
Registrant . . . . . . . . . . . . . . . . . . 33
Item 11 Executive Compensation . . . . . . . . . . . . . . . . . 33
Item 12 Security Ownership of Certain Beneficial
Owners and Management. . . . . . . . . . . . . 33
Item 13 Certain Relationships and Related Transactions . . . . . 33
PART IV
Item 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K. . . . . . . . . . . . . . 34
SIGNATURES . . . .. . . . . . . . . . . . . . . . . . . . . . . . 36
