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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, 1997 Commission file number: 10-3140
Northern States Power Company, a Wisconsin corporation, meets the conditions
set forth in general instruction I (1) (a) and (b) of Form 10-K and is
therefore filing this form with the reduced disclosure format. (In general
instruction I(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 54703
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (715) 839-2416
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 24, 1998
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
INDEX
Page No.
PART I
Item 1 Business 1
REGULATION AND RATES
Utility Industry Restructuring Status 1
Construction Authorization 2
Ratemaking Principles in Wisconsin and Michigan 3
Fuel and Purchased Gas Adjustment Clauses 3
Rate Matters by Jurisdiction 4
ELECTRIC OPERATIONS
Competition 6
NSP System 7
Capability and Demand 8
Demand Side Management 8
Interchange Agreement 9
Electric Power Pooling Agreements 9
Fuel Supply 9
Electric Operating Statistics 10
GAS OPERATIONS 10
ENVIRONMENTAL MATTERS 12
CONSTRUCTION AND FINANCING 13
EMPLOYEES AND EMPLOYEE BENEFITS 14
Item 2 Properties 15
Item 3 Legal Proceedings 16
Item 4 Submission of Matters to a Vote of Security
Holders 16
PART II
Item 5 Market Price of and Dividends on the Registrant's
Common Equity and Related Stockholder Matters 17
Item 6 Selected Financial Data 17
Item 7 Management's Discussion and Analysis 18
Item 8 Financial Statements and Supplementary Data 19
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 34
PART III
Item 10 Directors and Executive Officers of the Registrant 35
Item 11 Executive Compensation 35
Item 12 Security Ownership of Certain Beneficial Owners
and Management 35
Item 13 Certain Relationships and Related Transactions 35
PART IV
Item 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K 36
SIGNATURES. . 38
EXHIBITS (EXCERPT)
Statement pursuant to Private Securities Litigation Reform
Act of 1995 39
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, Wis. 54703 (Phone: (715) 839-2416). The
Company is a wholly-owned subsidiary of Northern States Power Company, a
Minnesota corporation (the Minnesota Company or NSPM). NSPM and its
subsidiaries collectively are referred to herein as NSP.
The Company is engaged in the generation, transmission, and
distribution of electricity to approximately 206,700 retail customers in an
area of approximately 18,900 square miles in northwestern Wisconsin, to
approximately 9,200 electric retail customers in an area of approximately
300 square miles in the western portion of the Upper Peninsula of Michigan,
and to ten 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 72,100 customers in Wisconsin and 4,900
customers in Michigan.
In 1997, the Company derived 81 percent of its total operating
revenues from electric utility operations and 19 percent from gas utility
operations. As of Dec. 31, 1997, the Company had 873 full-time equivalent
employees including 761 full-time employees.
As discussed in the Form 8-K filed on May 19, 1997, NSPM and Wisconsin
Energy Corporation (WEC) announced on May 16, 1997 that they mutually
agreed to terminate the proposed merger of the two companies. As a result,
the Company expensed approximately $900,000 of accumulated merger-related
costs during the second quarter of 1997.
Except for the historical information contained herein, the matters
discussed in this Form 10-K are forward-looking statements that are subject
to certain risks, uncertainties and assumptions. Such forward-looking
statements are intended to be identified in this document by the words
"anticipate," "estimate," "expect," "objective," "possible," "potential"
and similar expressions. Actual results may vary materially. Factors that
could cause actual results to differ materially include, but are not
limited to: general economic conditions, including their impact on capital
expenditures; business conditions in the energy industry; competitive
factors; unusual weather; changes in federal or state legislation; and the
other risk factors listed from time to time by the Company in reports filed
with the Securities and Exchange Commission (SEC), including Exhibit 99.01
to this report on Form 10-K.
REGULATION AND RATES
Utility Industry Restructuring Status
Some states have begun to allow retail customers to choose their
electricity supplier, and many other states are considering retail access
proposals. NSP believes that retail competition will result in more
innovative services and lower prices to all customers if the transition is
managed in a thoughtful manner. NSP supports fair and equal treatment for
all competitors, recovery of utilities' investments made under traditional
regulation and a reduction of personal property taxes for NSPM. NSP
supports a plan that would take two or three years to resolve these issues
and develop infrastructure, and another two or three years to phase in
customers' choice.
In 1996, the Public Service Commission of Wisconsin (PSCW) issued its
report to the legislature on restructuring the electric industry. The
report included a 32-step work plan to achieve specified elements with the
ultimate goal of opening a retail market to competition by the year 2001.
Work began on twelve of the 32 steps in 1996. Some of these were
completed, some continue to be worked on and some were rescheduled to begin
in 1997. After receiving comments on the restructuring work plan in July
1997, the PSCW consolidated the 32-step work plan into a 7-step work plan.
However, due to the summer of 1997's electrical reliability concerns in
eastern Wisconsin, the PSCW indicated that industry restructuring efforts
should be subordinate to, and compatible with, reliable electric supply.
The PSCW maintains that the development of a strong Independent System
Operator (ISO) remains of primary importance to retail competition. As a
result of the reliability issue in 1997, the PSCW will focus on the
development of a utility infrastructure necessary to assure reliable
electric service and the removal of barriers to competition at the
wholesale level first. In late 1997, the PSCW stated that although many
parties have concluded that retail competition is a foregone conclusion,
the PSCW never indicated that retail competition was inevitable, nor that
it was in the public interest. At present, a definite timeline has not yet
been established for the implementation of retail competition.
In March 1998 the Governor of Wisconsin (Governor) proposed
reliability legislation that, if enacted, will make dramatic changes in the
state's energy industry and take a number of steps toward industry
restructuring. This proposal will streamline the state's regulatory
process and authorize some form of a merchant plant market. This proposal
will also require, prior to June 30, 2000, transmission system owners to
either transfer control of transmission system assets to an ISO or divest
of assets to an independent transmission owning entity. NSP cannot predict
the final contents of any such legislation or ultimate impact on NSP.
In restructuring the natural gas industry, the PSCW reviewed four
proposed models. The chosen model included deregulation of the gas
purchasing and transportation functions by market segment as competition
becomes effective and sustainable. The PSCW then separated restructuring
into three phases. In Phase I, the PSCW found it necessary to completely
separate the gas purchasing activities associated with providing regulated
services from those associated with providing unregulated services and to
develop standards of conduct to apply to opportunity gas sales and
utilities' relationships with their affiliates. The focus of Phase II was
to develop Standards of Conduct (SOC) intended to ensure that interested
market participants have the opportunity to purchase released pipeline
capacity and gas supply, and that the releasing utility receives the best
price for the sale. In situations in which a gas utility has a gas
marketing affiliate, additional restrictions between the utility and its
affiliate are necessary to ensure fair treatment of all market participants
and to prevent cross-subsidization. Phase III focused on three main issues:
(1) identifying regulatory or structural barriers that may prohibit
competition; (2) identifying standards to determine the level of
competitiveness of the market and the level of necessary regulation and;
(3) identifying conditions to impose on marketers serving formerly
regulated markets. In this phase, it was also decided that gas marketers
should be registered or certified and that consumer protection and customer
service policy issues must be addressed before any markets are deregulated.
The PSCW then ordered the formation of six work groups to address the
following: Capacity Policy, Market Registration/Certification, Legislation,
End-Use Price Reporting, Market-Based Pricing for Large Volume Customers,
and Consumer Protection and Essential Services. These groups will continue
to meet over the coming years to address the various issues.
On Jan. 14, 1998 the Michigan Public Service Commission (MPSC) issued
an order regarding electric retail competition. The MPSC concluded that all
customers who want to participate in open access should have the
opportunity to do so and that those customers who do not participate should
not pay higher rates because of open access. The order directed the large
Michigan utilities to make 2 1/2 percent of their electric load eligible
for open access in each year from 1997 through 2001. All remaining Michigan
electric customers would be given access in 2002. It also stated that the
phase-in schedule applied to all customer classes, that a bidding process
would be used to allocate the open access capacity, that loads of less than
one megawatt (Mw) would be allowed to participate through an aggregator,
and that prudently incurred stranded costs would be recovered. That plan
was unsuccessfully challenged by the affected Michigan utilities, and the
courts upheld the MPSC's authority to implement retail competition. The
Company, along with the other smaller Michigan utilities, is in the process
of proposing a delayed open access timeline for its customers.
The timing of regulatory actions regarding electric and gas
restructuring and their impact on the Company and the industry cannot be
predicted at this time and may be significant.
Construction Authorization
Prior to the construction of a major electric project, the Company is
required to obtain various licenses and permits, including either a
certificate of authority (CA) or a certificate of public convenience and
necessity (CPCN), from the PSCW. In 1996, the minimum project expenditure
requiring a CA rose generally from $3 million to $3.3 million. Any
transmission projects involving equipment with a capacity less than 100
Kilovolts (Kv), costing less than $3.3 million, and less than 10 miles in
length, may no longer be subject to the full PSCW approval process. A
proposal to increase this limit to $5 million is pending before the PSCW.
Before a major electric generation or transmission project can receive
a CPCN, it must have received PSCW planning approval through the Advance
Plan process. In this process, Wisconsin utilities' twenty year generation
and transmission plant construction plans are reviewed. The Company filed
an Advance Plan most recently in early 1998, and the PSCW's decision is
expected in mid 1998.
In eastern Wisconsin, which is not served by the Company, the compound
effect of simultaneous generating facility outages and a transmission
system already near capacity raised the possibility of rolling blackouts
and system instability in that area during 1997. The PSCW and the
Governor's office are studying proposed amending requirements for new
electric generation and transmission facilities to promote the production
and movement of more electricity to the state.
Ratemaking Principles in Wisconsin and Michigan
The PSCW and 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, and various other aspects of the Company's
operations. The PSCW also exercises jurisdiction over the construction of
certain electric and gas facilities and the issuance of new securities.
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
92.7 percent of the Company's 1997 revenues from sales were subject to PSCW
jurisdiction. Of the 92.7 percent, 71.6 percent was generated from
electric retail revenues and the remaining 21.1 percent from retail gas
revenues. The Company's wholesale revenues from sales subject to FERC
jurisdiction were approximately 3.9 percent of the Company's 1997 revenues
from sales with the remaining 3.4 percent of revenues from sales subject to
MPSC jurisdiction.
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 deviated from this biennial filing requirement while the
proposed merger of NSP and WEC was pending.
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 current return on CWIP or capitalization of
Allowance for Funds Used During Construction (AFC) at the adjusted overall
cost of capital. The Company currently capitalizes AFC on production and
transmission CWIP at the FERC formula rate and on all other CWIP at the
adjusted overall cost of capital.
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 in 1986. The electric fuel adjustment clause was 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. This is subject to two
year approval under the biennial rate case process. Effective Jan. 1,
1996, the fuel costs that are monitored include demand costs for sales,
purchased power costs, and transmission wheeling expenses, which had been
excluded prior to that date.
On June 9, 1997 the Company filed for an interim fuel cost surcharge
to its retail electric rates under the fuel rules provisions of the
Wisconsin Statutes. The surcharge was requested because fuel and purchased
power costs had risen beyond the amount included in the Company's current
rates due to unplanned and extended outages at NSPM's nuclear generating
stations and higher than projected costs to transmit electricity purchased
from other utilities to the Company's service territory. Effective Sept.
25, 1997 the PSCW authorized the Company to increase rates through a fuel
cost surcharge of $0.00043 per Kilowatt-hour (Kwh) to all Wisconsin retail
electric customers, which produced approximately $574,000 of additional
electric revenue in 1997. The surcharge represents less than one percent of
current rates and is the first rate increase implemented since January
1993. The surcharge will continue in effect on an interim basis until the
next rate order is issued and is subject to refund pending final PSCW
review.
Gas rate schedules include a purchased gas adjustment (PGA) clause
that provides for rate adjustments to compensate for any difference between
the current price of purchased gas and the price of purchased gas already
included in rates. The current month's factor is based on the estimated
purchased gas costs for that month.
In March 1996, the PSCW conducted a generic hearing to consider
alternative incentive-based gas cost recovery mechanisms to replace the
current purchased gas adjustment clause (PGA). In November 1996, the PSCW
issued an order with general guidelines for incentive-based gas cost
recovery mechanisms as well as "modified one-for-one" gas cost recovery
mechanisms. All major gas utilities in Wisconsin were required to file a
proposal to replace their current PGA. On Sept. 29, 1997 the Company filed
its proposal with the PSCW. In the Company's proposal, allowable gas
commodity cost recovery would be based on a benchmark index which is, in
turn, based on the market price of gas. The allowable cost recovery of the
remaining components of the cost of gas (for example, fixed pipeline
transportation costs, supply reservation costs, and other costs approved by
the FERC) would be based on actual costs incurred, as is the case with the
Company's current PGA. The PSCW's decision is expected in June 1998. If
the Company's proposal is approved, the financial impact of the new gas
cost recovery mechanism will be substantially the same as with the current
PGA. Approximately 70 percent of the Company's gas revenues represent
recovery of gas costs through the PGA mechanism.
Michigan
The Company's Michigan retail gas and electric rate schedules include
Gas Cost Recovery Factors and Power Supply Cost Recovery Factors,
respectively, which are based on a twelve-month projection of costs. 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-recoveries are
refunded and any under-recoveries are collected, including interest.
On Aug. 25, 1997, the MPSC approved the Company's application to
reinstate a Power Supply Cost Recovery (PSCR) factor for Michigan electric
customers in 1998. On Sept. 29, 1997, the Company filed its request for a
1998 PSCR factor of $.00172 per Kwh which would produce about $250,000 of
additional revenue in 1998. The Company had suspended the PSCR during 1997
while the merger between NSPM and WEC was pending. The PSCR provides for
recovery of the cost of fuel for electric generating plants and for
purchased electricity.
Wholesale
For the eight wholesale customers on the W-1 wholesale rate, the
Company calculates the fuel adjustment factor for the current month based
on estimated electric fuel costs for that month. The fuel adjustment
factor is adjusted for over- or under- collected fuel costs allocable to
wholesale customer sales from the prior month's actual operations which
provide an ongoing true-up mechanism. The remaining two wholesale customers
have fixed rate contracts which do not have a fuel adjustment factor.
Rate Matters by Jurisdiction
Wisconsin
The Company filed retail electric and gas rate cases with the PSCW on
Nov. 14, 1997 for the test year 1998. The Company requested a 4.3 percent
increase, approximately $12.7 million annually, in retail electric rates
and a 1.9 percent or $1.7 million decrease in retail gas rates. The
Company has requested that these changes take effect during the second
quarter of 1998.
Network Transmission Service (NTS) is a form of transmission service
that was created under FERC Order No. 888 (as discussed later). Under NTS,
NSP and other participating utilities share the net cost of operating and
maintaining the regional transmission network that NSP uses based on each
participants' share of the network load. The additional cost of
participating in this regional network had not been included in the
Company's 1997 Wisconsin rates. In July 1997 the Company received
authorization from the PSCW to defer NTS costs related to Wisconsin retail
electric customers that were incurred after the May 23, 1997 request,
subject to review by the PSCW. Through Dec. 31, 1997, $1.7 million of NTS
costs had been deferred. Recovery of deferred NTS costs has been sought in
the Company's 1998 Wisconsin retail electric rate case.
In its order regarding the Company's 1997 rates, the PSCW denied current
rate recovery of the federal government's assessment for the
decommissioning and decontamination of federal uranium enrichment
facilities based on a court decision involving another utility that these
assessments were unlawful. However, the PSCW did state that they would
allow future rate recovery of these costs with interest if the courts
ultimately decided the assessments must be paid. The Company continued to
pay the assessments and has deferred $564,000 as of Dec. 31, 1997 as a
regulatory asset. On May 6, 1997, the United States Court of Appeals
reversed the lower court's earlier decision that these assessments were
unlawful. Accordingly, the Company has requested recovery of current and
deferred assessments in its 1998 retail electric rate filing.
On Dec. 31, 1997, the Company requested permission to implement an
amortization method of asset recovery for certain qualifying equipment
classified as General Plant. The method being proposed was generically
approved by the PSCW on Dec. 19, 1989. Historically, the Company has
adhered to the concept of retirement units and has maintained an individual
Continuing Property Record (CPR) for all such equipment. The proposed
method does not require unitization nor the recording of individual items
of property in the CPR. It allows for recording of the total cost of the
capital equipment acquired in a year as a vintaged group. The current list
of units of property will be maintained. Capital versus expense
determinations for the qualifying equipment will remain unchanged. The
Company would adopt amortization periods within the range certified by the
PSCW. Application of the certified amortization periods as proposed by the
Company would result in an annual increase in depreciation expense of
approximately $400,000 based upon estimated property balances for 1998. The
increase in depreciation has been included in the 1998 Wisconsin retail
rate filing.
Michigan
There were no changes in the Michigan Electric or Gas base rates
during 1997. The Company is currently assessing its need to file for a
change in rates during 1998.
FERC-Gas
The Company's Eau Claire Liquefied Natural Gas (LNG) `peak shaving'
plant stores LNG that can be used to supplement the Company's natural gas
supply during periods of high demand. In the past this plant was also used
to supplement the gas supply of other utilities and, as a result, was
subject to FERC jurisdiction. Since the Company no longer provides this
service to other utilities, it filed an application with the FERC to
abandon its jurisdiction over the Eau Claire LNG plant, which would leave
the PSCW with sole jurisdiction. In June 1997 the FERC dismissed the filing
in its entirety. In late October 1997, the FERC voted to grant (in part)
the Company's request for a rehearing of the filings seeking abandonment of
the FERC's jurisdiction over the Eau Claire LNG plant.
In September 1997, the FERC ruled that Kansas gas producers must
refund improperly collected Kansas ad valorem tax collected from 1982 to
1988 plus interest to its customers. During this period, Northern Natural
Gas (NNG) had bought gas from Kansas producers and resold it to the Company
under terms that require NNG to pass any refund from the producer back to
the Company. In December 1997 NNG received one $30 million refund and, in
turn, refunded $538,000 to the Company. However, the Kansas producers are
appealing the FERC order and are also pursuing federal legislation to
overturn the FERC order. In February 1998, the FERC ruled that the Kansas
producers could place disputed refunds in escrow and that pipelines such as
NNG could recollect refunded amounts if final refunds are less than those
already paid.
In July 1997, NSP and thirteen other parties appealed a July 1995 FERC
order regarding rate treatment of a Great Lakes Gas Transmission Company
(GLGT) expansion project. GLGT transports natural gas for the Company. In
the early 1990's GLGT completed two expansion projects which did not
improve service to the Company but which quadrupled the `rate base' (which
is GLGT's investment in facilities - and a factor in calculating the rate
the Company pays GLGT for transmitting gas). The FERC's July 1995 order
allowed GLGT to increase its rates to recover the cost of these expansion
projects which increased the Company's transport costs on GLGT's system by
61 percent annually, and to add surcharges for services received since
November 1991. The Company and other parties to the appeal requested that
the cost of the expansion projects be recovered only from customers who
benefit from them and not from all GLGT customers. In January 1998, the
District of Columbia Court of Appeals ruled that the July 1995 FERC order
was lawful. The additional transportation costs have been recovered
through the Purchased Gas Adjustment clause to the Company's rates, so
there was no impact on the Company's earnings.
In February 1997, the FERC issued its order on remand in the appeals
of FERC Order No. 636 (restructuring interstate natural gas pipeline rates
and services). The decisions most significant to the Company are that the
FERC affirmed its decision to allow 100 percent recovery of a pipeline's
prudently incurred stranded costs created by restructuring and that
existing shippers need only agree to a five year contract extension to
obtain a right of first refusal on continued access to the shipper's
expiring capacity. Originally, the FERC required a 20 year commitment.
FERC-Electric
In response to changes in the wholesale electric market, the Company
is providing discounts and negotiated services to be competitive. Due to
these changes, 1997 revenues decreased from 1996 by $0.8 million. All ten
municipal wholesale customers have current power supply arrangements under
which they will purchase the majority of their power supply requirements
from the Company.
In 1996 the FERC issued Orders No. 888 and 889, which have had a
significant impact on wholesale electric markets by giving competitors the
ability to transmit electricity through utilities' transmission systems.
Order No. 888 granted nondiscriminatory access to transmission service.
Order No. 889 ensures a fair market by imposing standards of conduct on
transmission system owners, by requiring separation of the power supply
function from the transmission system operation function and by mandating
the posting of transmission availability and pricing information on an
electronic bulletin board. In 1997, the FERC issued orders clarifying
Orders No. 888 and 889 in response to rehearing requests from market
participants. These clarifying orders are currently being appealed in
federal court. NSP has made the necessary filings with the FERC and
believes it is taking the proper steps to comply with the new rules as they
become effective.
On Feb. 17, 1998 NSP filed a rate application with the FERC to update
its rates for point-to-point transmission service. As filed, the proposed
rates increase annual transmission revenues by approximately $4 million.
The FERC's Order No. 888 requires utilities to offer, among other
services, NTS to qualifying customers. Under NTS, NSP and other qualifying
regional utilities share the total annual costs of operating and
maintaining the regional transmission network which NSP uses, net of
related network revenues, based on each company's share of the total
network load. Each FERC regulated utility files a transmission tariff
containing cost information that is used as the basis for NTS rates. NSP
reviewed the information from other participating utilities and commenced
negotiations with them regarding the final amount to be paid by NSP for
participating in NTS for 1997. NSP has recorded a liability for what
management believes is a reasonable estimate of the net cost of
participating in NTS for 1997. On March 2, 1998, NSP filed with the FERC a
revision to update its NTS costs to match those in the February 17 filing
for point-to point transmission service. This filing is expected to
support reductions in NSP's NTS costs.
Both of these tariff changes are subject to FERC approval. The
approval process is lengthy but interim rates could be in effect as early
as May 1, 1998.
As discussed previously, the PSCW has approved the regulatory deferral
of the share of NSP's NTS costs which apply to Wisconsin retail electric
customers, effective in 1997.
ELECTRIC OPERATIONS
The Company's electric production and transmission systems are
interconnected with the production and transmission system of NSPM. The
combined electric production and transmission systems of the Company and
NSPM are hereinafter called the "NSP System".
Competition
The Company's electric sales are subject to competition in some areas
from municipally owned systems, rural electric cooperatives and, in certain
respects, other private utilities and independent power producers. Electric
service also increasingly competes with other forms of energy. The degree
of competition may vary from time to time, depending on relative costs and
supplies of other forms of energy. Although the Company cannot predict the
extent to which its future business may be affected by supply, relative
cost or promotion of other electricity or energy suppliers, the Company
believes that it will be in a position to compete effectively.
In October 1992, President Bush signed into law the Energy Policy Act
of 1992 (Energy Act). The Energy Act amends the Public Utility Holding
Company Act of 1935 (PUHCA) 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 PUHCA. 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. The
market-based power agreement filings with FERC and the open access orders
issued by FERC (as discussed in "Regulation and Rates," herein) reflect the
trend toward increasing transmission access under the Energy Act.
The Energy Act is a catalyst for comprehensive and significant changes
in the operation of electric utilities, including increased competition.
The Act's reform of the PUHCA promotes creation of wholesale non-utility
power generators and authorizes the FERC to require utilities to provide
wholesale transmission services to third parties. The legislation allows
utilities and nonregulated companies to build, own and operate power plants
nationally and internationally without being subject to restrictions that
previously applied to utilities under the PUHCA. Management believes this
legislation will increase competition in the electric energy markets. NSP
plans to be a competitively priced supplier of electricity and an active
participant in the competitive market for electricity.
The NSP System is experiencing a continuing increase in the number of
requests for the use of its transmission facilities as power marketers
continue to enter the electric industry. In 1997, NSP filed 61
transmission service agreements for FERC approval. Also, as of Dec. 31,
1997, 73 customers, including NSP's own Energy Marketing area and other
independent power brokers, were registered to buy transmission service from
NSP.
Many states are currently considering proposals to increase
competition in the supply of electricity. The Company believes the
transition to a more competitive electric industry will be beneficial for
all consumers. It is likely that retail competition will provide more
innovative services and lower prices. The Company supports an orderly
transition to an open, fair and efficient competitive energy market for all
customers and suppliers. As discussed previously in "Regulation and
Rates," regulators in Wisconsin and Michigan are currently considering what
actions they should take regarding electric industry competition, including
restructuring. The Company believes that, under such restructuring plans,
utilities should retain direct operational responsibility of their
transmission and distribution systems, and that utilities should be
permitted to recover the cost of their investments made under traditional
regulation, including any "stranded costs." The timing of regulatory
actions regarding restructuring and their impact on the Company cannot be
predicted at this time and may be significant.
NSP System
The NSP System includes coal, natural gas, waste wood, refuse derived
fuel (RDF) and nuclear steam generating plants, gas and oil fired
combustion turbines, hydroelectric plants, an interconnection with the
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 large
power plants in those service territories.
NSPM operates two nuclear generating plants: the single unit, 539 Mw
Monticello Nuclear Generating Plant and the Prairie Island Nuclear
Generating Plant with two units having a total capacity of 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
ability of these nuclear plants to continue operating until the end of the
license periods is dependent upon the availability of storage facilities
for used nuclear fuel. The Monticello plant has sufficient temporary
storage for used fuel to operate until 2010. With the additional on-site
dry cask fuel storage facilities approved by the Minnesota Legislature in
1994, the Prairie Island plant is expected to have sufficient temporary
storage capacity to operate until 2007.
NSPM has contracted with the U.S. Department of Energy (DOE) for the
disposal of used nuclear fuel. The DOE charges a quarterly disposal fee
based on nuclear electric generation sold. While the DOE has contracted to
begin accepting used nuclear fuel in 1998, it has indicated it may not
actually be ready until after 2010. Consequently, NSPM may have to rely on
on-site or contracted off-site facilities for storage of used fuel to
continue operations of its nuclear plants until a DOE disposal or storage
facility is ready. (See related legal proceedings under Item 3 - Legal
Proceedings, herein.)
Capability and Demand
The Company's record peak demand occurred on July 17, 1997, and was
1,093 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 American Power Pool
(MAPP), NSP's reserve requirement is determined jointly with the other
parties to the MAPP Agreement. Currently, the minimum reserve requirement
is 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 Company primarily relies on plants operated by NSPM for base load
generation. Approximately 80 percent of the total Kwh requirements of the
Company were provided by NSPM generating facilities or purchases made by
NSPM for system use in the year 1997.
The Company has two steam generating facilities. One is the Bay Front
Generating Plant which is located in Ashland, Wis. 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
(WDNR) to also burn tire derived fuel at the Ashland plant on a regular
basis.
The Company's second steam generating plant is the French Island plant
located in La Crosse, Wis., which has two fluidized bed boilers modified
to burn 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.
Most of the Company's thermal generating capacity is with combustion
turbine units that are called into service during periods of high demand
for electricity, or "peaking plants". The 6 unit, 443 Mw Wheaton plant is
located near Eau Claire, Wis. During the third quarter of 1997, the Company
converted units 2 and 4 of the Wheaton generating facility to operate on
both oil and natural gas. Previously, the units operated on oil
exclusively. The conversion, which cost approximately $3 million, will
decrease the cost of producing electricity and reduce plant emissions.
There are also two combustion turbines at the French Island plant which
have a combined capability of 192 Mw, and one 17 Mw unit at Park Falls,
Wis.
The Company also has 19 hydro plants with a projected capability of
249 Mw.
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, incentive programs,
and rate incentive programs. In management's opinion, these programs
respond to customer needs and focus on increasing the value of service that
will, over the long term, reduce the company's capital requirements and
help its customer base become more stable, energy efficient and
competitive.
During 1997, the Company's programs accomplished approximately 21 Mw
of system peak demand reduction in the commercial, industrial and
agricultural customer sectors and over 2.2 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 retail DSM programs have achieved 219 Mw of
summer peak demand reduction, exceeding the Company's goal of reducing
summer peak demand by 200 Mw by the end of 1997. This is equivalent to
almost 20 percent of the Company's 1997 summer peak demand. The Company
continues to focus on improving the cost-effectiveness of its DSM programs
through market research studies and program evaluations.
Since Jan. 1, 1996, the Company has been allowed to expense rather
than defer and amortize certain DSM program expenditures. Expenditures
incurred prior to 1996 continue to be amortized.
The electricity market is expected to become competitive in the
future, and utilities' ability to implement DSM programs may no longer
exist. The Company remains committed to helping customers manage their
energy costs, so it and the PSCW have been and will continue to encourage
the development of a competitive market for energy efficiency programs.
The Company anticipates that, in the future, it will act as a facilitator
between customers and providers of energy-efficiency services.
Interchange Agreement
The electric production and transmission costs of the NSP System are
shared by the Company and NSPM. The cost-sharing arrangement between the
companies is the Agreement to Coordinate Planning and Operation and
Interchange Power and Energy between the Company and NSPM (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 NSPM 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 NSPM 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 NSPM'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 NSPM pursuant to the
Price-Anderson liability provisions of the Atomic Energy Act of 1954. (See
Note 8 to Financial Statements).
Electric Power Pooling Agreements
Many of the NSP System's power purchases from other utilities are
coordinated through the regional power organization MAPP. The NSP System
is one of 70 members, 21 associate members and eight regulatory
participants in MAPP. 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 most recent MAPP agreement, converting MAPP
to a Regional Transmission Group, was approved by the FERC Sept. 12, 1996
and has been in effect since Nov. 1, 1996.
Fuel Supply
In 1997 the Company shared in the fuel supply costs incurred by NSPM
in accordance with the Interchange Agreement. Coal and nuclear fuel is
expected to provide approximately 96 percent of the energy required to fuel
NSP System generating plants over the next several years and that the
remaining energy requirements will be provided by natural gas, oil, refuse
derived fuel, waste materials, renewable sources, and wood. The actual
fuel mix for 1997, and the estimated fuel mix for 1998 and 1999, are as
follows:
Fuel Use on Btu Basis
(Est.) (Est.)
1997 1998 1999
Coal 62.2% 60.4% 59.6%
Nuclear 33.9% 36.0% 36.8%
Other 3.9% 3.6% 3.6%
Electric Operating Statistics
The following table summarizes the revenues, sales and customers from
the Company's electric business, excluding sales to NSPM and miscellaneous
revenues:
Operating Statistics
1997 1996 1995 1994 1993
Electric Revenue (thousands)
Residential $ 117 490 $ 118 557 $ 121 073 $ 115 949 $ 114 718
Commercial and industrial 175 438 169 189 169 416 165 639 158 085
Total retail 292 928 287 746 290 489 281 588 272 803
Sales for resale 16 429 17 391 17 902 17 414 16 009
Total $ 309 357 $ 305 137 $ 308 391 $ 299 002 $ 288 812
Sales (millions of kilowatt-hours)
Residential 1 681 1 706 1 718 1 642 1 627
Commercial and industrial 3 528 3 405 3 327 3 212 3 045
Total retail 5 209 5 111 5 045 4 854 4 672
Sales for resale 455 458 456 438 417
Total 5 664 5 569 5 501 5 292 5 089
Customer accounts (Dec. 31)
Residential 184 921 183 036 181 151 178 473 176 066
Commercial and industrial 31 002 30 695 30 388 29 704 29 088
Total retail 215 923 213 731 211 539 208 177 205 154
Sales for resale 10 10 10 10 10
Total 215 933 213 741 211 549 208 187 205 164
In early 1998, officials of Fort James Corp. announced that its
Ashland, Wis. paper mill will close on or about March 21. The mill is the
third largest employer in Ashland County and is one of the Company's ten
largest electric and gas customers with revenues in excess of $2 million.
The effect of losing this customer has been included in the 1998 rate
filing.
GAS OPERATIONS
During 1997, the Company continued its strategy of holding a
diversified portfolio of natural gas supplies and transportation
arrangements. Since 1993, the Company has complied with the requirements
of FERC Order No. 636, which significantly changed the services available
to, and provided by, local distribution companies and interstate pipelines.
The Company is now relying entirely on third party suppliers for its
natural gas supply needs, and is utilizing the pipelines only for
transportation and storage services.
The natural gas supply network throughout North America has been
transformed into an integrated gas transportation grid enabling the Company
to purchase natural gas from numerous suppliers, obtain contracts for
transportation service on directly connected and upstream pipelines, and to
flexibly deliver the supplies to the Company's gas service territory. In
addition, the Company has directly contracted for underground storage and
owns and operates liquefied natural gas and propane-air peak shaving
facilities. The Company's diversified supply and transportation contracts,
as well as underground storage and peak shaving facilities, provide the
Company with the ability to meet customer needs with reliable and economic
natural gas supply.
The PSCW is continuing to investigate the need to change natural gas
regulation in Wisconsin as a result of changes in the structure of natural
gas utility pipeline services provided to all gas utilities. The PSCW is
advocating a market model in which gas costs will be deregulated by
segment, where competition is effective. Distribution service will remain
regulated.
The Company continues to hold annual and/or winter peaking
transportation contracts with Northern Natural Gas Company, Great Lakes
Transmission Limited Partnership, Northern Border Pipeline Company, Viking
Gas Transmission Company (Viking), another subsidiary of NSPM, and
TransCanada Pipeline, LTD.
The Company's ability to operate in a competitive gas market was
expanded through NSPM's acquisitions of Viking in June 1993 and the
formation of an energy services business, Cenerprise Inc. (now Energy
Masters International, Inc. or EMI), in October 1993. Viking allows NSP
continued access to competitive interstate natural gas transportation. EMI
allows the Company to provide more customized value-added energy services
to retail gas customers without increasing costs within the regulated
retail gas distribution business.
In January 1997, the PSCW adopted "Standards of Conduct" for retail
natural gas utilities (LDCs) serving Wisconsin consumers. The standards are
similar to, but much more extensive than, the standards of conduct FERC has
imposed on Viking under Order No. 497 and on NSP's wholesale electric
transmission functions under Order No. 889. The PSCW standards require
separation of the LDC delivery function from any affiliate which engages in
"gas functions" and impose extensive reporting and other administrative
requirements. The Company filed its compliance plan in February 1997.
The Company signed a 10-year contract with the U.S. Army to build, own,
and operate a natural gas system at Fort McCoy, a regional U.S. Army
training center near Sparta, Wis. At the end of January 1998, $820,000 of
the approximately $2.0 million total cost of the project had been spent.
The Company began providing gas to 169 buildings that were already served
by the Fort's existing natural gas distribution system on Feb. 2, 1998, and
by July 1998 an additional 746 services should be added as the Fort's
propane equipment is converted to use natural gas. The contract should
produce about $1.7 million of additional revenue each year. The Company has
received orders from the PSCW allowing the Company to treat the investment
as utility property and to include the cost of gas purchased for the
project in the PGA. The project is expected to be complete in July 1998.
In 1997 the Company signed a purchase agreement to acquire Natural Gas,
Inc., a privately owned natural gas utility serving 1,900 customers in the
New Richmond, Wis. area. The transaction will be structured as a tax-free
reorganization for income tax purposes and a pooling of interests for
accounting purposes. PSCW approval is required, and a decision is expected
to be received by July 1998.
Gas Operating Statistics
The following table summarizes the revenues, sales and customers from
the Company's gas business, excluding sales to NSPM and miscellaneous
revenues (including purchased gas adjustments):
1997 1996 1995 1994 1993
Revenues (thousands)
Residential $39 989 $41 382 $37 251 $34 297 $32 564
Commercial & Industrial 49 459 47 033 43 189 40 404 38 990
Total $89 448 $88 415 $80 440 $74 701 $71 554
Sales (thousands of mcf)
Residential 5 848 6 457 5 873 5 316 5 293
Commercial & Industrial 13 132 13 557 13 078 11 750 11 650
Total 18 980 20 014 18 951 17 066 16 943
Customer Accounts (Dec. 31)
Residential 68 631 65 868 63 176 60 194 57 530
Commercial & Industrial 8 809 8 657 8 377 8 012 7 625
Total 77 440 74 525 71 553 68 206 65 155
ENVIRONMENTAL MATTERS
The Company's policy is to proactively prevent adverse environmental
impacts, regularly monitor operations to ensure the environment is not
adversely affected, and to 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.
The WDNR 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 applicable
plants and all plants are in compliance with permit requirements.
The Company presently operates hydro, coal, natural gas, tire-derived
fuel, railroad tie, oil-fired, wood and refuse-derived fuel/wood-fired
generation equipment. The WDNR has jurisdiction over emissions to the
atmosphere from the operation of this equipment at the Company's power
plants. The operation of the Company's generating plants substantially
conforms to federal and state limitations pertaining to discharges into the
air.
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 (PCB's). The Company has procedures in place to comply with
these regulations.
The administrator of a group of PRPs has notified the Company that it
might be responsible for the cleanup of solid and hazardous waste landfill
sites in Eau Claire, Rice Lake, and Amery, Wis. The Company contends that
it did not contribute significant amounts of waste to these landfills.
Based on this minimal contribution, the Company does not expect that
significant liability will occur. However, because neither the amount of
cleanup costs nor the final method of their allocation among all designated
PRPs has been determined, it is not feasible to predict the outcome of the
matter at this time or any potential future impact on the Company's
financial condition or operating results.
In 1997 the WDNR named the Company as one of three Responsible Parties
for creosote and coal tar contamination at an Ashland, Wis. site adjacent
to Lake Superior. The site has three distinct portions - the Company
portion of the site, the Kreher Park portion of the site and the
Chequamegon Bay (of Lake Superior) portion of the site. The Company
portion of the site, formerly a coal gas plant site, is Company property.
The Kreher Park portion of the site is adjacent to the Company portion of
the site and is not owned by the Company. The Chequamegon Bay portion of
the site is adjacent to the Kreher Park portion of the site and is not
owned by the Company. The Company is discussing its potential involvement
in the Kreher Park and Chequamegon Bay portions of the site with WDNR and
the City of Ashland.
WDNR's consultant is preparing a remedial option study for the entire
Ashland site, which includes the Company's portion and the two other
adjacent portions. Until this study is completed and more information is
known concerning the extent of the final remediation required by the WDNR,
the remediation method selected, the related costs, the various parties
involved and the extent of the Company's responsibility, if any, for
sharing the costs, the ultimate cost to the Company and timing of any
payments related to the Ashland site are not determinable. As of Dec. 31,
1997, the Company had recorded an estimated liability of $880,000 for
future remediation costs for the Company owned portion of the site. Actual
costs incurred through 1997 were $646,000. The PSCW authorized recovery of
the amount paid through 1995, $353,000, over a two year period beginning in
1997. Based on the PSCW decision to allow recovery of remediation costs
incurred, the Company recorded a regulatory asset of $1,526,000 (of which
$176,500 has been amortized to expense as of Dec. 31, 1997). The ultimate
cleanup and remediation cost at the Ashland site and the extent of the
Company's responsibility, if any, for sharing such costs are not known at
this time, but may be significant.
In 1996, the Company received a Letter of Non-compliance (LON) from
the WDNR for failing to meet the emission guidelines for carbon monoxide
(CO) at its Bay Front generating facility. The Company worked with the
WDNR to establish mutually agreed-upon CO emission limits for the Bay Front
facility. The Company has been advised by WDNR staff that, based on
monitoring during 1997, the plant is in compliance with the new emission
limits. The Company has now been advised in writing that the LON has been
formally closed. No enforcement action or fines resulted from the LON.
In 1996, the Company received a Notice of Violation (NOV) from the
WDNR stating that emissions from the Company's French Island facility had
exceeded allowable levels for dioxin. The Company's initial investigation
and response, including a re-test of Unit No. 1, resulted in the WDNR
clearing the NOV on Unit No. 1 in September 1996. In October 1996, the
Company received a letter from the WDNR reiterating the outstanding NOV on
Unit No. 2 and requesting a written response. The Company responded by
providing a written response to the WDNR setting forth the Company's plans
for bringing the emissions levels back into compliance. By year end 1997,
subsequent compliance tests had demonstrated that dioxins no longer
exceeded acceptable limits. The Company expects that by early 1998 the
WDNR will formally close the NOV. No fines are expected.
In late 1996, the Company completed installation of continuous
emission monitors for carbon monoxide (CO) at the French Island Generating
facility in La Crosse, Wis. The continuous emissions system which will
monitor CO emissions from the two generating units was mandated by the Air
Pollution Control Permit issued by the WDNR in 1994.
In December 1997, nearly 160 nations adopted the "Kyoto Protocol to
the United Nations Framework Convention on Climate Change" (the Kyoto
Protocol). The Kyoto Protocol obligates developed nations to meet certain
emissions targets; specific limits vary from country to country. If the
Kyoto Protocol is approved internationally and the U.S. is a party, the
Kyoto Protocol would impose, during the first commitment period of 2008 -
2012, a binding obligation on the U.S. to reduce its emissions of carbon
dioxide, methane and nitrous oxide to a level 7 percent below 1990 levels
and its emissions of hydrofluorocarbons, perfluorocarbons and sulfur
hexafluoride by 7 percent below 1990 or 1995 levels. The Kyoto Protocol
must be ratified by the U.S. Senate in order for the U.S. to become a party
to the protocol. Major provisions of the Kyoto Protocol, such as an
international emissions trading program, have yet to be developed. Until
they are developed the impact on NSP cannot be predicted.
CONSTRUCTION AND FINANCING
During the five years ended Dec. 31, 1997, the Company had gross
additions to utility plant in service of approximately $262.1 million.
Included in the Company's gross additions is $25.7 million for electric
production facilities, $152.9 million for other electric properties, $36.3
million for gas utility properties, and $47.2 million for other utility
properties. Based on studies made by the Company, the weighted average age
of depreciable property was 14.5 years at Dec. 31, 1997.
Expenditures for the Company's construction programs for the five-year
period 1998-2002, are estimated to be as follows:
Year Estimated Construction Expenditures
(millions of dollars)
1998 $68
1999 78
2000 90
2001 80
2002 69
TOTAL $385
The largest projects included in these estimates are to construct a
new 230 Kv electric transmission line between Chisago County, Minn. and
Amery, Wis. and a new 161 Kv line between Stone Lake, Wis. and the Bay
Front Generating Plant in Ashland, Wis., and to rebuild transmission lines
between Baldwin and Abbotsford, Wis. These projects' estimated total cost
is $73 million, of which about $6.8 million will be spent in 1998. The 1998
construction expenditures are estimated to include approximately $50.1
million for electric facilities, $6.6 million for gas facilities and $11.0
million for general plant and equipment. It is presently estimated that
approximately 77 percent of the 1998-2002 construction expenditures will be
provided by internally generated funds, with the remainder from issues of
common stock equity and short-term debt to NSPM, and long-term debt to
external investors. At Dec. 31, 1997, the Company's short-term borrowing
payable to NSPM were $45.3 million. The PSCW has authorized up to $80.0
million of short-term borrowing. The Company currently projects the need
for $10 million of common stock equity from NSPM in 1998 and $50 million of
long-term debt in 1999 to finance the estimated construction expenditures
for the 1998-2002 construction program.
The foregoing estimates of future 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.
Bond Ratings
The Company's first mortgage bonds are currently rated AA by Standard
and Poor's Corporation, AA by Duff & Phelps, Inc., and AA by Fitch
Investors Service, Inc. On July 15, 1997, Moody's Investors Service
upgraded the credit ratings of the Company's first mortgage bonds from A1
to Aa3, and the unsecured resource recovery bonds guaranteed by the Company
from A2 to A1. The Company's financial and competitive position were among
the factors cited for the upgrade. These ratings are the opinions of the
rating agency and an explanation of the significance of these ratings may
be obtained from them. A security rating is not a recommendation to buy,
sell or hold securities and is subject to revision or withdrawal at any
time by the rating agency.
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1997, the total number of full- and part-time employees of
the Company was 873. About 400 employees of the Company are represented by
one local of the International Brotherhood of Electrical Workers under a
three year collective bargaining agreement which was ratified by the
Company's union membership on April 10, 1997. All provisions of this new
agreement were effective retroactively to Jan. 1, 1997 and extend to Dec.
31, 1999.
Recent changes to the Company's employee and retiree benefits, which
support a broad NSP goal of providing market-based benefits, include:
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 implemented with retirees paying 15 percent of the total cost of health
care in 1994, increasing gradually each year to a total of 40 percent in
1999.
401(k) changes: The Company currently offers eligible employees a
401(k) Retirement Savings Plan. Since 1994, the Company has been matching
employees' pre-tax 401(k) contributions. Such matching contributions were
$0.5 million in 1997, based on matching up to $900 per year for each
nonbargaining employee and up to $700 per year for each bargaining
employee. Matching contributions for bargaining employees will increase to
a maximum of $800 per year in 1998 and $900 per year in 1999.
Wage increases: The Company uses data from surveys of other local and
regional companies to determine the rate of compensation for its
nonbargaining employees. In 1997 and 1998 non bargaining employees received
average wage increases of 4 percent and 3.2 percent, respectively.
Bargaining employees received 2 percent per year wage increases in 1997 and
1998 under the new collective bargaining agreement.
Item 2 - Properties
Electric Utility
The Company's major electric generating facilities consist of the
following:
Year 1997-8 Winter
Station and Units Fuel Installed Capability (Mw)
Combustion Turbine:
Flambeau Station Gas/Oil 1969 17
Park Falls, WI
(1 unit)
Wheaton Gas/Oil 1973 443
Eau Claire, WI
(6 units)
French Island Oil 1974 192
La Crosse, WI
(2 units)
Steam:
Bay Front Coal/Wood/ 1945-1960 75
Ashland, WI Gas
(3 units)
French Island Wood/RDF 1940-1948 29
La Crosse, WI
(2 units)
Hydro Plants:
(19 plants) Various dates 249
TOTAL 1 005
At Dec. 31, 1997, the Company owned approximately 2,390 pole miles of
overhead electric transmission lines, 8,462 pole miles of overhead electric
distribution lines, 39 conduit miles and 1,078 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 its first mortgage bond
indentures pursuant to which the Company has issued first mortgage bonds.
Gas Utility
The gas properties of the Company include approximately 1,620 miles of
natural gas distribution mains. The Company owns two LNG facilities with a
combined storage capacity of 400,000 Million Cubic Feet (Mcf) to supplement
the available pipeline supply of natural gas during periods of peak
demands. The two LNG facilities are located in Eau Claire and La Crosse,
Wis. The La Crosse LNG facility is currently nonoperational. In January
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, Wis. area during peak periods. This propane air facility was not
operational during the 1995-96 winter, but has been in service since.
Item 3 - Legal Proceedings
In the normal course of business, the Company is a party to routine
claims and litigation arising from prior and current operations. The
Company is actively defending these matters and has recorded an estimate of
the probable cost of settlement or other disposition.
NSP and other affected parties have commenced lawsuits against the DOE
to require the DOE to meet their contractual obligations (including damages
for nonperformance) and to request authority to place in escrow payments
currently being made to the DOE for the permanent disposal program. The
U.S. Court of Appeals for the District of Columbia circuit ruled favorably
for NSP on the first lawsuit and NSP and other utilities are currently
analyzing claims against the DOE for costs incurred as a result of the
DOE's failure to meet its statutory and contractual obligations. No ruling
has been made on the second lawsuit regarding escrow of payments. With the
dry cask storage facilities approved in 1994 for the Prairie Island nuclear
generating plant, NSP believes it has adequate storage capacity to continue
operation of its Prairie Island nuclear plant until at least 2007. The
Monticello nuclear plant has storage capacity sufficient to continue
operations until 2010. Storage availability to permit operation beyond
these dates is not assured at this time. In the meantime, NSP is
investigating all of its alternatives for used fuel storage until a DOE
facility is available, including pursuing the establishment of a private
facility for the interim storage of used nuclear fuel as part of a
consortium of electric utilities. If on-site temporary storage at NSP's
nuclear plants reaches approved capacity, NSP could seek interim storage at
this or another contracted private facility, if available.
For a discussion of environmental proceedings, see "Environmental
Matters" under Item 1, incorporated herein by reference. For a discussion
of proceedings involving the Company's utility rates, see "Regulation and
Rates" under Item 1, incorporated herein by reference.
Item 4 - Submission of Matters to a Vote of Security Holders
None
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 I (1)
(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure
format).
Item 7 - Management's 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 I (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 I (2) (a) of Form 10-K for
wholly owned subsidiaries (reduced disclosure format). This analysis will
primarily compare its revenue and expense items for the year ended Dec. 31,
1997 with the year ended Dec. 31, 1996.
The Company's net income for year ended Dec. 31, 1997 was $37.4
million, down from the $38.7 million earned in the same period of 1996.
The 1997 operating income decreased $3.0 million from the 1996 level.
Electric Sales and Revenues
Electric Revenues in total increased $5.8 million in 1997. Sales to
customers increased $3.9 million or 1.3 percent in 1997 as compared to 1996
primarily due to higher sales levels and a fuel-related rate increase.
Total electric sales volumes increased 1.7 percent in 1997 as compared to
1996 due to customer and sales growth, partially offset by less favorable
weather in 1997. The Company was allowed to increase rates to reflect an
interim fuel cost surcharge effective Sept. 25, 1997 as discussed in the
Fuel and Purchased Gas Adjustment Clauses section. The remaining $1.9
million increase in electric revenues relates to higher Interchange
Agreement billings to NSPM as discussed in Note 6 to the Financial
Statements.
Gas Sales and Revenues
Gas Revenues in 1997 increased $1.0 million or 1.2 percent as compared
with 1996 primarily due to natural gas-related price increases, net of
lower sales levels. Total gas sales volumes decreased 5.2 percent in 1997
from 1996 primarily due to unfavorable winter weather in 1997. More than
offsetting the sales decline were higher costs per unit of purchased gas,
as discussed below, which are reflected in customer rates through the
purchased gas adjustment clause mechanism.
Operating Expenses and Other Factors
Purchased and Interchange Power and Fuel for Electric Generation
together increased $11.1 million or 6.2 percent in 1997 from 1996 mainly
due to additional power purchases from NSPM and the usage of higher cost
peaking plants to support increased sales levels. These power purchases
from NSPM were generally more expensive than 1996 due to unplanned and
extended outages at NSPM's nuclear generating stations in 1997.
Gas Purchased for Resale increased $2.8 million or 4.9 percent in 1997
primarily due to higher costs per unit of gas partially offset by reduced
purchases to support lower sales volumes.
Other Operation, Maintenance, and Administrative and General expenses
together decreased $5.2 million or 5.9 percent in 1997 as compared to 1996
primarily due to reduced employee benefit expenses as discussed in Note 5
to the Financial Statements, lower employee levels, and lower transmission
expense billings from NSPM. Partially offsetting these decreases were
increased customer service expenses in 1997.
Depreciation and Amortization increased $2.1 million or 5.8 percent in
1997 from 1996 due to increases in the Company's plant in service.
Income tax decreased $0.6 million in 1997 from 1996 reflecting lower
pretax operating income in 1997.
Other income (expense)-net increased $0.5 million (net of income
tax effects) in 1997 from 1996 primarily due to higher subsidiary company
earnings and a tax settlement. In September 1997, the Company received
$825,000 of a $1.8 million refund of tax and interest due from the State of
Wisconsin. The refund resulted from a favorable court decision regarding a
disputed tax issue. The Company expects to receive the balance of the
refund in mid 1998. Partially offsetting these increases was the pretax
write-off of approximately $900,000 of deferred merger-related costs
resulting from the termination of the proposed merger between NSPM and WEC
in May 1997.
Other interest and amortization (before AFC) decreased $1.2 million or
6.6 percent in 1997 from 1996. A decrease in interest paid to NSPM for
short-term borrowings and a reversal of interest previously accrued on the
tax issue in dispute with the State of Wisconsin were partially offset by
higher interest expense on long-term debt.
Technology Changes for the year 2000
Like many other companies, NSP expects to incur significant costs to
modify or replace existing technology, including computer software, for
uninterrupted operation in the year 2000 and beyond. In 1996, NSP's Board
of Directors approved funding to address development and remediation
efforts related to the year 2000. A committee made up of senior management
is leading NSP's initiatives to identify year 2000 related issues and
remediate business processes as necessary in 1998. Testing of computer
software modifications and other remediated processes is scheduled for
1999. NSP is also working with major suppliers so that NSP does not
experience business interruptions due to year 2000 issues in the suppliers'
business processes. The amount of additional development and remediation
costs necessary after 1997 for the Company to prepare for the year 2000 is
estimated to be approximately $900,000. In 1997 the Company expensed
approximately $105,000 for this modification effort.
Accounting Changes
Effective Jan. 1, 1998, the Company changed its method of accounting
for pension costs under SFAS No. 87. The new method was adopted to reduce
the volatility of accrued pension costs by amortizing actuarial gains and
losses related to pension asset performance over the longest period allowed
by SFAS No. 87. The effect of this change is expected to be a decrease in
pension costs (represented by an increase in pension accrual credits) of
approximately $2.5 million in 1998, including $1.8 million related to
periods prior to the change.
Item 8 - Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for financial statements included herein.
See Note 10 to the financial statements for summarized quarterly
financial data.
REPORT OF INDEPENDENT ACCOUNTANTS
To The Shareholder of Northern States Power Company (Wisconsin):
In our opinion, the accompanying balance sheets and the related statements
of income and retained earnings and of cash flows present fairly, in all
material respects, the financial position of Northern States Power Company,
a Wisconsin corporation, at Dec. 31, 1997 and 1996, and the results of its
operations and its cash flows for each of the three years in the period
ended Dec. 31, 1997, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with generally accepted auditing standards which
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, assessing the
accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for the opinion expressed above.
/s/
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
Feb. 2, 1998
Statements of Income and Retained Earnings Year Ended December 31
(Thousands of dollars) 1997 1996 1995
Operating Revenues
Electric $ 382 859 $ 377 073 $ 381 040
Gas 89 790 88 756 78 058
Total 472 649 465 829 459 098
Operating Expenses
Purchased and interchange power 179 708 173 492 173 743
Fuel for electric generation 10 023 5 165 4 703
Gas purchased for resale 61 195 58 347 52 356
Other operation 45 534 46 920 46 534
Maintenance 19 734 19 617 20 780
Administrative and general 17 845 21 814 25 264
Conservation and demand side management 8 935 9 117 7 674
Depreciation and amortization 37 815 35 731 33 097
Property and general taxes 14 140 14 332 14 109
Income taxes 24 120 24 688 24 662
Total operating expenses 419 049 409 223 402 922
Operating Income 53 600 56 606 56 176
Other Income (Expense)
Allowance for funds used during construction-equity 246 339 445
Other income and deductions-net of applicable
income taxes 1 253 677 1 698
Total Other Income (Expense)-Net 1 499 1 016 2 143
Income Before Interest Charges 55 099 57 622 58 319
Interest Charges
Interest on long-term debt 16 322 15 918 16 038
Other interest and amortization 1 688 3 406 3 548
Allowance for funds used during construction-debt (328) (399) (484)
Total interest charges 17 682 18 925 19 102
Net Income 37 417 38 697 39 217
Retained Earnings, January 1 234 751 221 638 218 833
Dividends paid to parent on common stock (27 997) (25 584) (36 412)
Retained Earnings, December 31 $ 244 171 $ 234 751 $ 221 638
See Notes to Financial Statements.
Statements of Cash Flows Year Ended December 31
(Thousands of dollars) 1997 1996 1995
Cash Flows from Operating Activities:
Net Income $37 417 $38 697 $39 217
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization 38 991 36 665 34 180
Deferred income taxes 4 372 1 736 1 839
Deferred investment tax credits recognized (880) (910) (936)
Allowance for funds used during construction - equity (246) (339) (445)
Insurance receivable 3 091
Cash provided by (used for) changes in certain working capital items (1 491) (2 633) 7 282
Cash used for changes in other assets and liabilities (3 293) (2 691) (1 064)
Net Cash Provided by Operating Activities 74 870 70 525 83 164
Cash Flows from Investing Activities:
Capital expenditures (53 580) (49 403) (51 173)
Increase (decrease) in construction payables 899 (118) (457)
Allowance for funds used during construction - equity 246 339 445
Other (615) (897) (1 606)
Net Cash Used for Investing Activities (53 050) (50 079) (52 791)
Cash Flows from Financing Activities:
Issuances (repayment) of short-term debt due to parent - net 6 000 (11 600) 9 600
Proceeds from issuance of long-term debt 82 691
Redemption of long-term debt, including reacquisition premiums (65 992) (3 375)
Dividends paid to parent (27 997) (25 584) (36 412)
Net Cash Used for Financing Activities (21 997) (20 485) (30 187)
Net Increase (decrease) in cash and cash equivalents (177) (39) 186
Cash and cash equivalents beginning of period 208 247 61
Cash and cash equivalents end of period $ 31 $ 208 $ 247
Cash provided by (used for) changes in certain working capital items:
Accounts receivable-net $ 2 149 $ 2 883 ($ 6 188)
Materials and supplies (3 980) (1 447) 3 442
Accounts payable and accrued liabilities (4 197) 668 1 241
Payables to affiliated companies 137 2 087 4 475
Income and other taxes accrued 134 (4 007) 417
Other 4 266 (2 817) 3 895
Net ($1 491) ($2 633) $ 7 282
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized) $ 16 581 $ 18 556 $ 15 389
Income taxes (net of refunds received) $ 20 673 $ 26 977 $ 17 333
See Notes to Financial Statements.
Balance Sheets December 31
(Thousands of dollars) 1997 1996
Assets
Utility Plant
Electric-including construction work in progress:
1997, $14,904; 1996, $11,948 $ 931 752 $ 894 143
Gas-including construction work in progress:
1997, $1,561; 1996, $1,569 105 362 99 817
Other-including construction work in progress:
1997, $6,769; 1996, $4,835 70 892 67 262
Total 1 108 006 1 061 222
Accumulated provision for depreciation (426 723) (395 619)
Net utility plant 681 283 665 603
Current Assets
Cash 31 208
Accounts receivable 38 758 41 151
Accumulated provision for uncollectible accounts (656) (901)
Unbilled utility revenues 16 376 21 074
Materials and supplies - at average cost
Fuel 12 073 7 780
Other 5 604 5 918
Prepayments and other 12 135 11 703
Total current assets 84 321 86 933
Other Assets
Regulatory assets 35 634 37 102
Other investments 8 166 7 433
Nonutility property - net of accumulated depreciation:
1997, $328; 1996, $327 2 752 2 799
Unamortized debt expense 1 761 1 855
Federal income tax receivable 3 307 3 307
Long-term prepayments and deferred charges 7 411 4 099
Total other assets 59 031 56 595
Total Assets $ 824 635 $ 809 131
Liabilities and Equity
Capitalization
Common stock-authorized 870,000 shares of $100 par value;
issued shares: 1997 and 1996, 862,000 $ 86 200 $ 86 200
Premium on common stock 10 461 10 461
Retained earnings 244 171 234 751
Total common stock equity 340 832 331 412
Long-term debt (net of unamortized discount of $1,825
in 1997 and $1,912 in 1996) 231 775 231 688
Total capitalization 572 607 563 100
Current Liabilities
Notes payable - parent company 45 300 39 300
Accounts payable 13 844 16 493
Payables to affiliated companies (principally parent) 15 682 15 544
Salaries, wages, and vacation pay accrued 6 089 6 417
Taxes accrued 1 775 1 641
Interest accrued 4 187 4 459
Other 4 897 5 558
Total current liabilities 91 774 89 412
Other Liabilities
Accumulated deferred income taxes 105 850 100 898
Accumulated deferred investment tax credits 18 970 20 024
Regulatory liabilities 19 306 19 409
Customer advances 8 192 7 334
Benefit obligations and other 7 936 8 954
Total other liabilities 160 254 156 619
Commitments and Contingent Liabilities (see Note 8)
Total Liabilities and Equity $ 824 635 $ 809 131
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), a wholly-owned subsidiary of Northern States Power Company, a
Minnesota corporation (NSPM), maintains its 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 percent
owned; NSP Lands, Incorporated, 100 percent owned; and Clearwater
Investments, Incorporated, 100 percent owned) at cost plus equity in
earnings since acquisition. The impact of consolidating these subsidiaries
would be immaterial.
Related Party Transactions The Company's financial statements
include intracompany transactions and balances related to sales among the
electric and gas utility businesses of the Company as well as intercompany
transactions with NSPM and Viking Gas Transmission Company (a wholly-owned
subsidiary of NSPM), including intercompany profits which are allowed in
utility rates. See Note 6 for further discussion of intercompany
transactions with NSPM.
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.
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 3.61 percent in 1997, 3.57 percent in 1996, and 3.48
percent in 1995.
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 Company used the FERC
calculation for production and transmission property and the PSCW
calculation for other qualified CWIP. The rates used for the FERC
calculation were 5.68 percent in 1997, 5.70 percent in 1996, and 6.20
percent in 1995. The rates used for the PSCW calculation were 10.00
percent in 1997, 10.03 percent in 1996, and 10.13 percent in 1995. 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.
Revenues Revenues are recognized based on products and services
provided to customers each month. Because utility customer meters are read
and billed on a cycle basis, unbilled revenues are estimated and recorded
for services provided from the monthly meter-reading dates to month-end.
Regulatory Deferrals As a regulated utility, the Company accounts
for certain income and expense items under the provisions of Statement of
Financial Accounting Standards (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. Note 7 describes the components of regulatory assets and
liabilities.
Income Taxes Under the liability method used by the Company, income
taxes are deferred for all 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, current income tax expense is provided for the
reversal of some temporary differences previously accounted for by the flow-
through method. Also, regulation has created certain regulatory assets and
liabilities related to income taxes, as summarized in Note 7.
The Company is included in the consolidated Federal income tax return
filed by NSPM 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.
State income tax payments are made directly to the taxing authorities.
Federal income tax payments are made to the Internal Revenue Service by
NSPM and charged back to the Company.
Investment tax credits were deferred and are being 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 leases after the initial
investments have been recovered.
Derivative Financial Instruments As discussed in Note 2, the Company
had entered into an interest rate swap agreement to manage the risk of
holding fixed-rate debt in a declining interest rate environment. The cost
or benefit of swap transactions was recorded as an adjustment to interest
expense each period over the term of the agreement. The agreement expired
March 1, 1998.
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. 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 relate 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
the Company has been designated as one of several potentially responsible
parties, the amount accrued represents the Company's estimated share of the
cost. The Company intends to treat any future costs related to
decommissioning and restoration of its power plants and substation sites,
where operation may extend indefinitely, as a capitalized removal cost of
retirement in utility plant. Depreciation expense levels currently
recovered in rates include a provision for an estimate of removal costs.
Use of Estimates In recording transactions and balances resulting
from business operations, the Company uses estimates based on the best
information available. Estimates are used for such items as plant
depreciable lives, tax provisions, uncollectible accounts, environmental
loss contingencies, unbilled revenues and actuarially determined benefit
costs. As better information becomes available (or actual amounts are
determinable), the recorded estimates are revised. Consequently, operating
results can be affected by revisions to prior accounting estimates.
Reclassifications Certain reclassifications have been made to the
1996 and 1995 financial statements to conform with the 1997 presentation.
These reclassifications had no effect on net income or earnings per share.
2. Long-term Debt
Dec. 31 Dec. 31
1997 1996
Long-term debt includes the following issues:
(Thousands of dollars)
First Mortgage Bonds:
Series due:
Oct. 1, 2003, 5 3/4% $ 40 000 $ 40 000
March 1, 2023, 7 1/4% 110 000 110 000
Dec. 1, 2026, 7 3/8% 65 000 65 000
Total First Mortgage Bonds 215 000 215 000
City of La Crosse Resource Recovery
Revenue Bonds - Series due
Nov. 1, 2021, 6% 18 600 18 600
Total long-term debt $ 233 600 $ 233 600
Except for minor exclusions, all real and personal property is subject
to the lien of the Company's first mortgage bonds. The Supplemental and
Restated Trust Indenture dated March 1, 1991, and effective Oct. 1, 1993
permits an amount of established permanent additions to be deemed
equivalent to the payment of cash necessary to redeem one percent of the
highest principal amount of each series of first mortgage bonds (other than
resource recovery financing) at any time outstanding.
Interest Rate Swap Agreement The Company had entered into an
interest rate swap agreement which expired March 1, 1998 for $20 million of
the 7 1/4 percent series of first mortgage bonds. This agreement
effectively converted the interest rates for $20 million of this debt issue
from fixed to variable based on the six-month London Interbank Offered Rate
(LIBOR) adjusted semi-annually on March 1 and September 1. The net
effective interest rate under the swap agreement was 7.96 percent at Dec.
31, 1997.
Market risks associated with this agreement resulted from short-term
interest rate fluctuations. Credit risk related to non-performance of the
counterparties was not deemed significant, but would have resulted in NSP
terminating the swap transaction and recognizing a gain or loss, depending
on the fair market value of the swap. Such agreements are not reflected on
the Company's balance sheets. The interest rate swap serves 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, 1997, $74,000 would have been payable by the
Company while the present value of the related fixed rate debt issued with
the swaps was $320,000 above carrying value.
Fair Value of Debt The estimated fair value of the Company's long
term debt at December 31, 1997 and 1996 is $234.9 million and $227.7
million, respectively. This fair value 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.
Capital Lease Obligations Amounts due under capital lease
obligations are approximately $441,000, $128,000, $14,000, $0, and $0,
respectively, for the years 1998-2002.
3. Short-Term Borrowings
The Company had bank lines of credit aggregating $1 million at Dec.
31, 1997. 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 1997 and 1996 there were no bank
loans outstanding as the Company obtained short-term borrowings from NSPM
at NSPM's average daily interest rate, including the cost of their
compensating balance requirements.
The PSCW has authorized the Company to make short-term borrowings up
to $80.0 million. At Dec. 31, 1997 and 1996, the Company had $45.3 million
and $39.3 million, respectively, in short-term borrowings from NSPM
outstanding. The weighted average interest rates on all short-term
borrowings as of Dec. 31, 1997 and 1996, were 5.68 percent and 5.62
percent, respectively.
4. Income Tax Expense
The total income tax expense differs from the amount computed by
applying the Federal income tax statutory rate of 35 percent to net income
before income tax expense. The reasons for the difference are as follows:
1997 1996 1995
Tax computed at statutory rate 35.0% 35.0% 35.0%
Increases (decreases) in tax from:
State income taxes, net of Federal income tax benefit 3.7 4.6 5.2
Investment tax credits recognized (1.5) (1.4) (1.4)
Other - net 1.2 0.7 (0.8)
Effective income tax rate 38.4% 38.9% 38.0%
Income tax expense is comprised of the following:
(Thousands of Dollars)
Included in Utility operating expenses:
Current Federal tax expense $ 15 550 $ 18 293 $ 17 772
Current state tax expense 3 671 3 838 4 546
Deferred Federal tax expense 4 688 2 790 2 679
Deferred state tax expense 1 092 677 601
Deferred investment tax credit adjustments (880) (910) (936)
Total 24 121 24 688 24 662
Included in Other income and deductions - net:
Current Federal tax expense 1 942 1 299 691
Current state tax expense (1 345) 326 130
Deferred Federal tax expense (1 408) (1 385) (1 264)
Deferred state tax expense 0 (346) (178)
Total income tax expense $ 23 310 $ 24 582 $ 24 041
The components of the Company's net deferred tax liability at December 31
(including current and noncurrent amounts) were as follows:
(Thousands of dollars) 1997 1996
Deferred tax liabilities:
Differences between book and tax bases of property $ 106 242 $ 103 771
Tax benefit transfer leases 108 1 638
Regulatory assets 12 227 12 690
Other 4 857 3 782
Total deferred tax liabilities 123 434 121 881
Deferred tax assets:
Deferred investment tax credits 7 597 8 014
Regulatory liabilities 7 725 7 729
Deferred compensation, accrued vacation and
other reserves not currently deductible 618 2 310
Other 585 1 260
Total deferred tax assets 16 525 19 313
Net deferred tax liability $ 106 909 $ 102 568
5. Pension Plans and Other Post Retirement Benefits
The Company offers the following benefit plans to its benefit employees, of
whom approximately 52 percent are represented by one local labor union
under a collective-bargaining agreement which expires Dec. 31, 1999.
Pension 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.
It is the Company's policy to fully fund the actuarially determined
pension costs recognized for ratemaking purposes, subject to the
limitations under applicable employee benefit and tax laws. Plan assets
consist principally of common stock of public companies, corporate bonds
and U.S. government securities. The following table sets forth the funded
status of the pension plan, including amounts allocable to the Company, as
of December 31:
(Thousands of dollars) 1997 1996
Company Company
Total Plan Portion Total Plan Portion
Actuarial present value of benefit obligation:
Vested $ 701 219 $ 91 579 $ 660 920 $ 84 924
Nonvested 165 004 18 260 147 278 16 332
Accumulated benefit obligation $ 866 223 $ 109 839 $ 808 198 $ 101 256
Projected benefit obligation $1 048 251 $ 128 222 $ 993 821 $ 120 886
Plan assets at fair value 1 978 538 234 304 1 634 696 196 089
Plan assets in excess of projected
benefit obligation 930 287 106 082 640 875 75 203
Unrecognized prior service cost 18 663 2 336 19 734 2 469
Unrecognized net actuarial gain (953 825) (102 160) (651 368) (77 174)
Unrecognized net transitional asset (463) (57) (539) (67)
Net pension asset recorded $ (5 338)$ 6 201 $ 8 702 $ 431
Since Jan. 1, 1993, for financial reporting and regulatory purposes, the
Company's pension expense has been determined and recorded under the SFAS
No. 87 - Employers' Accounting for Pensions method. The Company's
accumulated regulatory asset from the use of another method prior to that
date is being amortized over a 15-year period ending in 2007. Net periodic
pension costs for the Company for its share of total plan costs include the
following components:
1997 1996 1995
(Thousands of dollars)
Service cost - benefits earned during the period $ 3 062 $ 3 390 $ 2 844
Interest cost on projected benefit obligation 8 926 8 618 8 662
Actual return on allocated share of plan assets (49 959) (12 353) (10 994)
Net amortization and deferral 32 201 (2 727) (1 567)
Net periodic pension cost determined under SFAS No. 87 (5 770) (3 072) (1 055)
Expenses recognized due to actions of regulators 90 90 90
Net periodic pension cost (credit) recognized for ratemaking $ (5 680) $ (2 982) $ (965)
The weighted average discount rate used in determining the actuarial
present value of the projected obligation was 7 percent at Dec. 31, 1997
and 7.5 percent at Dec. 31, 1996. The rate of increase in future
compensation levels used in determining the actuarial present value of the
projected obligation was five percent in 1997 and 1996. The assumed long-
term rate of return on assets used for cost determinations under SFAS No.
87 was nine percent for 1997, 1996, and 1995. Assumption changes decreased
1997 pension costs by $800,000 and increased 1996 pension costs by
approximately $1.4 million. Assumption changes are expected to decrease
1998 pension credits by approximately $700,000.
Postretirement Health Care The Company participates in NSPM's contributory
health and welfare benefit plan that provides health care and death
benefits to substantially all employees after their retirement. The plan
is intended to provide for sharing the costs of retiree health care between
the Company and retirees. For employees retiring after Jan. 1, 1994, a six-
year cost-sharing strategy was implemented with retirees paying 15 percent
of the total cost of health care in 1994, increasing to a total of 40
percent in 1999. In conjunction with the 1993 adoption of SFAS No. 106 -
Employers' Accounting for Postretirement Benefits Other Than Pensions, the
Company elected to amortize on a straight-line basis over 20 years the
unrecognized accumulated postretirement benefit obligation (APBO) of
approximately $29.5 million for current and future retirees of the Company.
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, 1997 consisted of investments in equity mutual funds
and cash equivalents. The following table sets forth the funded status of
the health care plan, including amounts allocable to the Company, as of
December 31.
(Thousands of dollars) 1997 1996
Company Company
Total Plan Portion Total Plan Portion
APBO:
Retirees $149 081 $ 23 637 $144 180 $ 22 166
Fully eligible plan participants 21 245 3 236 23 438 3 447
Other active plan participants 108 904 13 189 101 065 12 065
Total APBO 279 230 40 062 268 683 37 678
Plan Assets at Fair Value 19 784 10 553 15 514 8 285
APBO in excess of plan assets 259 446 29 509 253 169 29 393
Unrecognized net actuarial loss (14 408) (3 071) (12 467) (2 057)
Unrecognized transition obligation (161 700) (22 112) (172 480) (23 586)
Postretirement benefit liability recorded $ 83 338 $ 4 326 $ 68 222 $ 3 750
The assumed health care cost trend rates used in measuring the APBO at
Dec. 31, 1997 and 1996, respectively, were 9.2 and 9.8 percent for those
under age 65 and 6.8 and 7.1 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 Dec. 31, 1997, by
approximately 14.5 percent and service and interest cost components of the
net periodic postretirement cost by approximately 15.4 percent. The
assumed discount rate used in determining the APBO was 7 percent for Dec.
31, 1997 and 7.5 percent for Dec. 31, 1996, compounded annually. The
assumed long-term rate of return on assets used for cost determinations
under SFAS No. 106 was eight percent for 1997, 1996, and 1995. Assumption
changes had an immaterial effect on results of operations.
The Company's share of net annual periodic postretirement benefit
costs under the plan consists of the following components (thousands of
dollars):
1997 1996 1995
Service cost-benefits earned during the year $ 644 $ 804 $ 686
Interest cost (on service cost and APBO) 2 694 2 700 2 761
Amortization of transition obligation 1 474 1 474 1 474
Actual return on Company's share of plan assets (874) (632) (301)
Net amortization and deferral 211 221
Net periodic postretirement health care costs $4 149 $4 567 $4 620
The Company's regulators have allowed full recovery of increased
benefit costs under SFAS No. 106, effective in 1993. External funding is
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 jurisdictions in
1993.
401(k) The Company participates in NSPM's contributory, defined
contribution Retirement Savings Plan (the Plan), which complies with
section 401(k) of the Internal Revenue code and covers substantially all
Company employees. Employer matching contributions under this Plan began
in 1994, and are required to match a specified amount of employee
contributions. The Company's matching contribution to the Plan was $0.5
million in 1997, 1996 and 1995.
6. Parent Company and Intercompany Agreements
The Company is wholly-owned by NSPM. The electric production and
transmission costs of the NSP system are shared by the Company and NSPM. A
FERC approved agreement (Interchange Agreement) between the Company and
NSPM 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
1997 1996 1995
(Thousands of dollars)
Operating revenues:
Electric $ 71 262 $ 69 337 $ 70 251
Gas $45 $39 $43
Operating expenses:
Purchased and interchange power $179 708 $173 492 $173 743
Gas purchased for resale $231 $216 $205
Other operation $11 972 $13 685 $13 791
7. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized
regulatory assets and liabilities shown on the Balance Sheet at December
31:
(Thousands of dollars) Amortization Period 1997 1996
AFC recorded in plant on a net-of-tax basis Plant Lives* $ 9 768 $ 9 928
Losses on reacquired debt Term of Related Debt 12 533 13 341
Conservation and energy management programs Up to 8 years* 8 842 10 604
Environmental costs As allowed in rates 1 913 1 405
Unrecovered purchased gas costs 1 year 0 722
Pensions and other Mainly 10 years 2 578 1 102
Total Regulatory Assets $ 35 634 $ 37 102
Excess deferred income taxes collected from
customers $ 3 898 $ 3 420
Investment tax credit deferrals 12 694 13 412
Other 2 714 2 577
Total Regulatory Liabilities $ 19 306 $ 19 409
* Earns a return on investment in the ratemaking process.
8. Commitments and Contingent Liabilities
Commitments The Company presently estimates capital expenditures
will be $68 million in 1998 and $385 million for 1998-2002.
Rentals under operating leases were approximately $1,080,000,
$1,704,000, and $1,644,000 for 1997, 1996, and 1995, respectively. Future
commitments under these leases generally decline from current levels.
Purchased Gas Contracts The Company has contracts providing for the
purchase and delivery of a significant portion of its current natural gas
requirements. These contracts, which expire in various years between 1999
and 2011, require minimum contractual purchases and deliveries of natural
gas. In total, the Company is committed to the minimum purchase of
approximately $119 million of natural gas and related transportation, or to
make payments in lieu thereof, under these contracts. In addition, the
Company is required to pay additional amounts depending on actual
quantities shipped under these agreements. As a result of FERC Order No.
636, the Company has been very active in developing a mix of gas supply,
transportation and storage contracts designed to meet its needs for retail
gas sales. The contracts are with several suppliers and for various
periods of time. Because the Company has other sources of natural gas
available and suppliers are expected to continue to provide reliable
natural gas supplies, risk of loss from non-performance under these
contracts is not considered significant. In addition, the Company's risk
of loss (in the form of increased costs) from market price changes in
natural gas is mitigated through the cost-of-gas adjustment provision of
the ratemaking process, which provides for recovery of prudently incurred
natural gas costs.
Nuclear Contingencies Although the Company does not own a nuclear
facility, any assessment made against NSPM and under the Price-Anderson
liability provisions of the Atomic Energy Act of 1954, would be a cost
included under the Interchange Agreement (see Note 6) 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. NSPM has secured insurance of $200 million to satisfy such
claims. The remaining $8.7 billion of exposure is funded by the Secondary
Financial Protection Program, available from assessments by the federal
government in case of a nuclear accident. NSPM is subject to an assessment
of $79 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.
Environmental Contingencies The Company potentially may be involved
in the cleanup and remediation at four sites. Three sites are solid and
hazardous waste landfill sites in Eau Claire, Rice Lake and Amery, Wis.
The Company contends that it did not contribute significant amounts of
waste to these landfills. Based on this minimal contribution, the Company
does not expect that significant liability will occur. However, because
neither the amount of cleanup costs nor the final method of their
allocation among all designated PRPs has been determined, it is not
feasible to predict the outcome of these matters at this time. The fourth
site, in Ashland, Wis., contains creosote and coal tar contamination.
In 1997, the WDNR notified the Company that it is one of three
Responsible Parties for creosote and coal tar contamination at the Ashland
site. The Ashland site has three distinct portions--the Company portion,
the Kreher Park portion and the Chequamegon Bay (of Lake Superior) portion.
The Company portion of the site, formerly a coal gas plant site, is Company
property. The Kreher Park portion is adjacent to the Company site and is
not owned by the Company. The Chequamegon Bay portion is adjacent to the
Kreher Park portion and is not owned by the Company. The Company is
discussing its potential involvement in the Kreher Park and Chequamegon Bay
portions with the WDNR and the City of Ashland. In February 1996, the
Company received from the WDNR's consultant a draft report of the results
of a remediation action options feasibility study for the Kreher Park
portion of the Ashland site. The draft report contains several remediation
options that were scored by the consultant across a variety of parameters.
Two options scored the most technologically and economically feasible, and
one of those is the lowest-cost option for remediation at the Kreher Park
portion of the site. The draft report estimates that this option, which
would involve capping the property and some limited groundwater treatment,
would cost approximately $6 million. In 1996, the WDNR completed a
sediment contamination investigation of the impacted area of the
Chequamegon Bay portion of the site to determine the extent and nature of
the contamination. Contamination of the near shore area has been confirmed
by the study. WDNR's consultant is preparing a remedial option study for
the entire Ashland site, which includes the Company's portion and the two
adjacent portions. Until this study is completed and more information is
known concerning the extent of the final remediation required by the WDNR,
the remediation method selected, the related costs, the various parties
involved and the extent of the Company's responsibility, if any, for
sharing the costs, the ultimate cost to the Company and timing of any
payments related to the Ashland site are not determinable, but may be
significant. As of Dec. 31, 1997, the Company had recorded an estimated
liability of $880,000 for future remediation costs for the Company owned
portion of the site. Actual costs incurred through 1997 were $646,000.
The PSCW authorized recovery of the amount paid through 1995, $353,000,
over a two year period beginning in 1997. Based on the PSCW decision to
allow recovery of remediation costs incurred, the Company recorded a
regulatory asset of $1,526,000 (of which $176,500 has been amortized to
expense as of Dec. 31, 1997).
Legal Claims In the normal course of business, the Company is a party
to routine claims and litigation arising from prior and current operations.
The Company is actively defending these matters and has recorded an
estimate of the probable cost of settlement or other disposition.
9. Segment Information
Year Ended December 31
1997 1996 1995
(Thousands of dollars)
Operating income before income taxes:
Electric $ 68 536 $ 69 730 $ 72 595
Gas 9 185 11 564 8 243
Total operating income before income taxes $ 77 721 $ 81 294 $ 80 838
Depreciation and amortization:
Electric $ 32 510 $ 30 857 $ 28 752
Gas 5 305 4 874 4 345
Total depreciation and amortization $ 37 815 $ 35 731 $ 33 097
Construction expenditures:
Electric $ 46 744 $ 42 519 $ 42 843
Gas 6 836 6 884 8 330
Total construction expenditures $ 53 580 $ 49 403 $ 51 173
Identifiable assets:
Electric utility $674 939 $661 585 $654 130
Gas utility 91 609 91 557 86 021
Total identifiable assets 766 548 753 142 740 151
Other corporate assets 58 087 55 989 50 747
Total assets $824 635 $809 131 $790 898
10. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended
Mar. 31, June 30, Sept. 30, Dec. 31,
1997 1997 1997 1997
(Thousands of dollars)
Operating revenues $138 249 $103 796 $104 341 $126 263
Operating income $ 17 259 $ 9 353 $ 11 225 $ 15 763
Net income $ 12 608 $ 4 645 $ 8 242 $ 11 922
Quarter Ended
Mar. 31, June 30, Sept. 30, Dec. 31,
1996 1996 1996 1996
(Thousands of dollars)
Operating revenues $138 730 $101 678 $100 366 $125 055
Operating income $ 17 341 $ 9 902 $ 11 379 $ 17 984
Net income $ 12 919 $ 5 432 $ 6 799 $ 13 547
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
During 1997 there were no disagreements with the Company's independent
certified public accountants on accounting procedures or accounting and
financial disclosures.
PART III
Part III of Form 10-K has been omitted from this report in accordance with
conditions set forth in general instructions I (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
PART IV
Item 14 - Exhibits, Financial Statement Schedules
and Reports on Form 8-K
(a) 1. Financial Statements Page
Included in Part II of this report:
Report of Independent Accountants for the years ended
Dec. 31, 1997 and 1996. 20
Statements of Income and Retained Earnings for
the three years ended Dec. 31, 1997. 21
Statements of Cash Flows for the three
years ended Dec. 31, 1997. 22
Balance Sheets, Dec. 31, 1997 and 1996 23
Notes to Financial Statements. 25
2. Financial Statement Schedules
Schedules 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 Dec. 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 Aug. 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
Company to Firstar Trust Company (formerly 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 Aug. 1, 1964.
(Filed as Exhibit 4.20 to Registration Statement 2-23726)
4.05* Copy of Supplemental Trust Indenture, dated Dec. 1, 1969.
(Filed as Exhibit 2.03E to Registration Statement 2-36693)
4.06* Copy of Supplemental Trust Indenture, dated Sept. 1, 1973.
(Filed as Exhibit 2.03F to Registration Statement 2-49757)
4.07* Copy of Supplemental Trust Indenture, dated Feb. 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 Oct. 1, 1993.
(Filed as Exhibit 4.01 to Form 8-K Report dated September 21,
1993)
4.15* Copy of Supplemental Trust Indenture, dated Dec. 1, 1996.
(Filed as Exhibit 4.01 to Form 8-K Report dated Dec. 12, 1996)
10.01* Copy of Interchange Agreement dated Sept. 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)
27.01 Financial Data Schedule
99.01 Statement pursuant to Private Securities Litigation
Reform Act of 1995.
(b) Reports on Form 8-K - The following report on Form 8-K was filed
either during the three months ended December 31, 1997, or between Dec. 31,
1997 and the date of this report.
None
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
March 25, 1998 /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/ /s/
John A. Noer H. Lyman Bretting
President and Chief Executive Director
(Principal Executive Officer)
/s/ /s/
Roger D. Sandeen P. M. Gelatt
Controller Director
(Principal Accounting Officer)
/s/ /s/
Neal A. Siikarla Ray A. Larson, Jr.
Treasurer Director
(Principal Financial Officer)
/s/
Larry G. Schnack
Director
/s/
Loren L. Taylor
Director
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
DT 27.01 Financial Data Schedule
DT 99.01 Statement pursuant to Private Securites
Litigation Reform Act of 1995.
DT = Filed electronically with this direct transmission.