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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, 1996
Commission file number: 10-3140
Northern States Power Company, a Wisconsin corporation,
meets the conditions set forth in general instruction J (1)
(a) and (b) of Form 10-K and is therefore filing this form
with the reduced disclosure format. (In general instruction
J(2))
Northern States Power Company
(Exact name of registrant as specified in its charter)
Wisconsin 39-0508315
(State or other jurisdiction of (I.R.S. employer identification number)
incorporation or organization)
100 North Barstow Street 54703
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (715) 839-2592
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, 1997
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
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION 1
REGULATION AND RATES
Utility Industry Restructuring in Wisconsin
& Michigan 5
Construction Authorization 6
Ratemaking Principles in Wisconsin 6
Fuel and Purchased Gas Adjustment Clauses 7
Rate Matters by Jurisdiction 8
Electric Transmission Tariffs and Settlement (FERC) 9
Minnesota Company Jurisdictions' Proposed Merger
Transaction Proceedings 11
ELECTRIC OPERATIONS
Competition 12
NSP System 13
Capability and Demand 13
Demand Side Management 14
Interchange Agreement 14
Electric Power Pooling Agreements 15
Fuel Supply 15
Electric Operating Statistics 16
GAS OPERATIONS 16
ENVIRONMENTAL MATTERS 18
CONSTRUCTION AND FINANCING 20
EMPLOYEES AND EMPLOYEE BENEFITS 20
Item 2 Properties 21
Item 3 Legal Proceedings 22
Item 4 Submission of Matters to a Vote of Security Holders 22
PART II
Item 5 Market Price of and Dividends on the Registrant's
Common Equity and Related Stockholder Matters 23
Item 6 Selected Financial Data 23
Item 7 Management's Discussion and Analysis 23
Item 8 Financial Statements and Supplementary Data 25
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 41
PART III
Item 10 Directors and Executive Officers of the
Registrant 42
Item 11 Executive Compensation 42
Item 12 Security Ownership of Certain Beneficial
Owners and Management 42
Item 13 Certain Relationships and Related Transactions 42
PART IV
Item 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K 43
SIGNATURES 46
EXHIBITS (EXCERPT)
Statement pursuant to Private Securities Litigation
Reform Act of 1995 47
Unaudited Pro Forma Financial Information 49
PART I
Item 1. Business
Northern States Power Company (the Company), incorporated in
1901 under the laws of Wisconsin as the La Crosse Gas and
Electric Company, is an operating public utility company with
executive offices at 100 North Barstow Street, Eau Claire,
Wisconsin 54703 (Phone: (715) 839-2592). The Company is a wholly-
owned subsidiary of Northern States Power Company, a Minnesota
corporation (the Minnesota Company). The Minnesota Company and
its subsidiaries collectively are referred to herein as NSP.
The Company is engaged in the generation, transmission, and
distribution of electricity to approximately 211,400 retail
customers in an area of approximately 18,900 square miles in
northwestern Wisconsin, to approximately 9,600 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 69,000 customers in
Wisconsin and 4,800 customers in Michigan. In Wisconsin, some of
the larger communities the Company provides natural gas to are
Eau Claire, Chippewa Falls, La Crosse, Hudson, Menomonie and
Ashland. In the Upper Peninsula of Michigan, the largest
community to which the Company provides natural gas is Ironwood.
In 1996, the Company derived 81 percent of its total
operating revenues from electric utility operations and 19
percent from gas utility operations. As of December 31, 1996,
the Company had 861 full-time equivalent employees including 763
full-time employees.
Except for the historical information contained herein, the
matters discussed in this form 10-K, including the statements
regarding the anticipated impact of the proposed merger, 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;
regulatory decisions regarding the proposed combination of NSP
and WEC, 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.
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION
Description of the Merger Transaction
As initially announced in the Company's Current Report on
Form 8-K dated April 28, 1995 and filed on May 8, 1995 (the
Company's 4/28/95 8-K), the Minnesota Company, Wisconsin Energy
Corporation, a Wisconsin corporation (WEC), Northern Power
Wisconsin Corp., a Wisconsin corporation and wholly-owned
subsidiary of the Minnesota Company (New NSP) and WEC Sub Corp.,
a Wisconsin corporation and wholly owned subsidiary of WEC (WEC
Sub), have entered into an Amended and Restated Agreement and
Plan of Merger, dated as of April 28, 1995, as amended and
restated as of July 26, 1995 (the Merger Agreement), which
provides for a business combination of the Minnesota Company and
WEC in a "merger-of-equals" transaction (the Merger Transaction).
On September 13, 1995, the merger plan was approved by more than
95 percent of the respective shareholders of the Minnesota
Company and WEC voting at their respective shareholder meetings.
The agreement to merge is subject to a number of conditions,
including approval by applicable regulatory authorities. NSP
continues to work with WEC to complete the merger. However,
since numerous conditions are beyond its control, NSP cannot
state whether the merger will occur. See discussion of the
regulatory proceedings under the caption "Regulation and Rates -
Rate Matters by Jurisdiction" herein. Additional information
regarding the merger is included in Item 8, Note 11 of the Notes
to Financial Statements and unaudited pro forma financial
statements are included in exhibits listed in Item 14.
In the Merger Transaction, Primergy Corporation (Primergy),
which will be registered under the Public Utility Holding Company
Act of 1935, as amended, will be the parent company of both the
Minnesota Company (which for regulatory reasons, will
reincorporate in Wisconsin) and WEC's current principal utility
subsidiary, Wisconsin Electric Power Company (WEPCO), which will
be renamed "Wisconsin Energy Company." It is anticipated that,
at the time of the Transaction, except for certain gas
distribution properties transferred to the Minnesota Company, the
Company will be merged into Wisconsin Energy Company and the
subsidiaries of the Company will become direct Primergy
subsidiaries.
The Merger Agreement, and the press release issued in
connection therewith, and the related Stock Option Agreements
(defined below) are filed as exhibits to this report and are
incorporated herein by reference. The descriptions of the Merger
Agreement and the Stock Option Agreements set forth herein do not
purport to be complete and are qualified in their entirety by the
provisions of the Merger Agreement and the Stock Option
Agreements, as the case may be, and the other exhibits filed with
this report.
Under the terms of the Merger Agreement, the Minnesota
Company is to be merged with and into New NSP and immediately
thereafter WEC Sub will be merged with and into New NSP, with New
NSP being the surviving corporation. Each outstanding share of
the Minnesota Company's common stock, par value $2.50 per share
(NSP Common Stock), will be canceled and converted into the right
to receive 1.626 shares of common stock, par value $.01 per
share, of Primergy (Primergy Common Stock). The outstanding
shares of WEC common stock, par value $.01 per share (WEC Common
Stock), will remain outstanding, unchanged, as shares of Primergy
Common Stock. Each outstanding share of the Minnesota Company's
cumulative preferred stock, par value $100.00 per share, will be
canceled and converted into the right to receive one share of
cumulative preferred stock, par value $100.00 per share, of New
NSP with identical rights (including dividend rights) and
designations. Following the merger of the Company into Wisconsin
Energy Company, the Company's outstanding first mortgage bonds
will become obligations of Wisconsin Energy Company, but will
continue to be secured under the Company's Supplemental and
Restated Trust Indenture only to the extent of the mortgaged and
pledged property that is acquired by Wisconsin Energy Company,
and will not be secured by any other assets of Wisconsin Energy
Company. WEPCO's outstanding preferred stock will remain
outstanding and be unchanged in the Merger Transaction.
It is anticipated that Primergy will adopt the Minnesota
Company's dividend payment level adjusted for the exchange ratio.
The Minnesota Company currently pays $2.76 per share annually,
and WEC's annual dividend rate is currently $1.52 per share.
Based on the 1.626 stock exchange ratio and the Company's current
dividend rate, the pro forma dividend rate for Primergy Common
Stock would be $1.70 per share as of December 31, 1996. However,
the amount, declaration, and timing of dividends on Primergy
Common Stock will be a business decision to be made by the
Primergy Board of Directors from time to time based upon the
results of operations and financial condition of Primergy and its
subsidiaries and such other business considerations as the
Primergy Board considers relevant in accordance with applicable
laws.
Merger Consummation Conditions
The Merger Transaction is subject to numerous closing
conditions, including, without limitation, the receipt of all
necessary governmental approvals without materially adverse terms
and the making of all necessary governmental filings, including
approvals of state utility regulators in Wisconsin, Minnesota and
certain other states, the approval of the Federal Energy
Regulatory Commission (FERC), the Securities and Exchange
Commission (SEC), the Nuclear Regulatory Commission (NRC), and
the filing of the requisite notification with the Federal Trade
Commission and the Department of Justice under the Hart-Scott-
Rodino Antitrust Improvements Act of 1976, as amended, and the
expiration of the applicable waiting period thereunder. (See
discussion of the utility regulation proceedings under the
caption "Regulation and Rates - Rate Matters by Jurisdiction"
herein.) The Merger Transaction is also subject to receipt of
assurances from the parties' independent accountants that the
Merger Transaction will qualify as a pooling of interests for
accounting purposes under generally accepted accounting
principles. In addition, the consummation of the Merger
Transaction is conditioned upon the approval for listing of such
shares on the New York Stock Exchange.
During 1995, in addition to shareholder and Board of Directors
approval, the Minnesota Company and WEC took the following steps
toward fulfilling the conditions to closing:
- Registration statements filed by the Minnesota Company
and WEC with the SEC with respect to the Primergy Common Stock
to be issued in the Merger Transaction and New NSP Preferred
Stock became effective.
- The Minnesota Company and WEC received a ruling from the
Internal Revenue Service indicating that the proposed
merger transactions would qualify as independent tax-free
reorganizations under applicable tax law.
- The Minnesota Company and WEC filed for regulatory
approval of the Merger Transaction with the FERC and state
commissions. (See "Regulation and Rates - Rate Matters by
Jurisdiction" for further discussion of the status of these
filings.)
- The Minnesota Company filed for NRC approval of the
transfer of nuclear operating licenses from the Minnesota
Company to New NSP.
During 1996 the Minnesota Company and WEC made the following
filings as part of the regulatory approval process of the Merger
Transaction:
- An Application was filed for SEC approval of the
Registration of Primergy under the Public Utility Holding
Company Act of 1935, as amended.
- Notification under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976, was filed with the United States
Department of Justice.
During 1997, the United States Department of Justice served
its second request for information and documents. NSP and WEC
anticipated responding to the second request in March 1997.
As noted above, completion of the merger is subject to
numerous conditions under the Merger Agreement that, unless
waived by the affected party, must be met, including but not
limited to the prior receipt of all necessary regulatory
approvals without the imposition of materially adverse terms; the
accuracy of each party's representations and warranties in the
Merger Agreement at closing, other than representations and
warranties whose inaccuracy does not result in a material adverse
effect on the business, assets, financial condition, results of
operations or prospects of such party and its subsidiaries taken
as a whole; and no such material adverse effect having occurred,
or being reasonably likely to occur, with respect to either
party, at the time of the closing. NSP continues to work with
WEC to complete the merger. However, since numerous conditions
are beyond its control, NSP cannot state whether all necessary
conditions for completion of the merger will occur.
The Merger Agreement
The Merger Agreement contains certain covenants of the
parties pending the consummation of the Merger Transaction.
Generally, the parties must carry on their businesses in the
ordinary course consistent with past practice, may not increase
dividends on common stock beyond specified levels, and may not
issue capital stock beyond certain limits. The Merger Agreement
also contains restrictions on, among other things, charter and
bylaw amendments, capital expenditures, acquisitions,
dispositions, incurrence of indebtedness, certain increases in
employee compensation and benefits, and affiliate transactions.
In accordance with the Merger Agreement, upon the
consummation of the Merger Transaction, James J. Howard,
Chairman, President, and Chief Executive Officer of the Minnesota
Company will initially serve as the Chairman and Chief Executive
Officer of Primergy for a minimum of 16 months after the
effectiveness of the Merger Transaction and will thereafter serve
only as Chairman of the Board of Primergy for a minimum of two
years. Also, Richard A. Abdoo, Chairman, President and Chief
Executive Officer of WEC shall initially hold the positions of
Vice Chairman of the Board, President and Chief Operating Officer
of Primergy and thereafter shall be entitled to hold the
additional position of Chief Executive Officer when Mr. Howard
ceases to be Chief Executive Officer. Mr. Abdoo will assume the
position of Chairman when Mr. Howard ceases to be Chairman.
The Merger Agreement may be terminated under certain
circumstances, including (1) by mutual consent of the parties;
(2) by any party if the Merger Transaction is not consummated by
April 30, 1997 (provided, however, that such termination date
shall be extended to October 31, 1997 if all conditions to
closing the Merger Transaction, other than the receipt of certain
consents and/or statutory approvals by any of the parties, have
been or are capable of being fulfilled at April 30, 1997); (3) by
any party if either the Minnesota Company's or WEC's shareholders
vote against the Merger Transaction or if any state or federal
law or court order prohibits the Merger Transaction; (4) by a non-
breaching party if there exist breaches of any representations or
warranties made in the Merger Agreement as of the date thereof
which breaches, individually or in the aggregate, would result in
a material adverse effect on the breaching party and which is not
cured within 20 days after notice; (5) by a non-breaching party
if there occur breaches of specified covenants or material
breaches of any covenant or agreement which are not cured within
20 days after notice; (6) by either party if the Board of
Directors of the other party shall withdraw or adversely modify
its recommendation of the Merger Transaction or shall approve any
competing transaction; or (7) by either party, under certain
circumstances, as a result of a third-party tender offer or
business combination proposal which such party's board of
directors determines in good faith that their fiduciary duties
require be accepted, after the other party has first been given
an opportunity to make concessions and adjustments in the terms
of the Merger Agreement. In addition, the Merger Agreement
provides for the payment of certain termination fees by one party
to the other in the event of a willful breach or acceptance of a
third-party tender offer or business combination.
Concurrently with the Merger Agreement, the Minnesota
Company and WEC have entered into reciprocal stock option
agreements (the "Stock Option Agreements") each granting the
other an irrevocable option to purchase up to that number of
shares of Common Stock of the other company which equals 19.9
percent of the number of shares of common stock of the other
company outstanding on April 28, 1995 at an exercise price of
$44.075 per share, in the case of Minnesota Company Common Stock,
or $27.675 per share, in the case of WEC Common Stock, under
certain circumstances if the Merger Agreement becomes terminable
by one party as a result of the other party's breach or as a
result of the other party becoming the subject of a third-party
proposal for a business combination. Any party whose option
becomes exercisable (the "Exercising Party") may request the
other party to repurchase from it all or any portion of the
Exercising Party's option at the price specified in the Stock
Option Agreements.
Results of the Merger Transaction
Assuming the merger is completed, a transition to a new
organization would begin. At the time that the Merger Agreement
was signed, anticipated cost savings of the new organization
(compared with the continued independent operation of NSP and
WEC) were estimated to be approximately $2 billion over a 10-year
period, net of transaction costs (about $30 million) and costs to
achieve the merger savings (about $122 million). The actual
realization of these savings will be dependent on numerous
factors.
It is anticipated that the proposed merger will allow the
companies to implement a modest reduction in electric retail
rates as described below followed by a rate freeze for electric
and gas retail customers. This rate plan is currently being
considered by various regulatory agencies.
The Company and WEPCO have proposed an average retail
electric rate reduction of 1.5 percent and a four-year-rate
freeze in the electric retail jurisdiction for customers of
Wisconsin Energy Company. The electric rate reduction of 1.5
percent would be implemented as soon as reasonably possible
following the receipt of the necessary approvals and closing of
the Merger Transaction. This proposed rate reduction is made in
conjunction with the proposal to recover deferred Merger
Transaction costs and costs incurred to achieve merger savings
through amortization over the same period. In addition, the
companies agreed to provide a four-year freeze in wholesale
electric rates effective once the merger is completed.
The Company has proposed a $0.6 million rate decrease and a
four-year freeze for retail natural gas rates in its Wisconsin
jurisdiction. In addition, any net purchased gas cost savings
would be reflected in gas rates for customers in Wisconsin
automatically through the purchased gas adjustment clause
mechanism. The remaining benefits will support the rate freeze,
as well as offset a portion of the rising gas utility costs other
than the purchased cost of gas.
The total savings identified as a result of the Merger
Transaction represent aggressive goals which the Minnesota
Company and WEC intend to achieve, but the rate freeze will
result in some risk to the Minnesota Company's shareholders if
the anticipated cost savings are not realized. There is
uncertainty regarding the timing and levels of the savings and
costs associated with the Merger Transaction. The proposal to
unilaterally reduce rates and institute a rate freeze is designed
to shield customers from these uncertainties. This proposal
permits customers the opportunity to immediately begin realizing
benefits of the Merger Transaction notwithstanding these
uncertainties. Further, the four-year rate freeze permits the
companies a reasonable time period to implement the changes
necessary to achieve the contemplated savings.
The commitment not to increase electric rates does not
prohibit tariff amendments and rate design changes which would
not increase electric net income during the moratorium. Finally,
as part of this proposal, Primergy's operating utility
subsidiaries will work with regulatory commissions to develop a
plan for managing merger benefits for the year 2001 and beyond.
The Company and WEPCO recognize that during the four-year rate
freeze period, it may experience certain significant but
uncontrollable events which necessitate rate changes.
Accordingly, as part of the rate plan proposal, the Company and
WEPCO have identified certain events (large increases in taxes
and government-mandated costs, and extraordinary events) which it
believes should be excepted from the rate freeze. The exceptions
are necessary in order to protect Wisconsin Energy Company from
major cost increases or events which are beyond its control. The
Company and WEPCO propose that for these uncontrollable events it
be allowed to file with the PSCW during the rate freeze period
for recovery of the costs related to these events.
The Company, the Minnesota Company and WEC recognize that
the divestiture of their existing gas operations and certain non-
utility operations is a possibility under the new registered
holding company structure, but have been working with the SEC to
retain such businesses. Based on prior decisions and other
actions by the SEC, the retention of both the gas and non-
regulated businesses seems possible after consummation of the
Merger Transaction. If divestiture is ultimately required, the
SEC has historically allowed companies sufficient time to
accomplish divestitures in a manner that protects shareholder
value.
Also, regulatory authorities may require the use of an
independent transmission system operator (ISO) or divestiture of
certain transmission and/or generation assets. The Company
currently cannot determine if such divestitures would be required
by regulators. In addition, Wisconsin state law limits the total
assets of non-utility affiliates of Primergy, which, depending on
interpretations of the law, may limit growth of nonregulated
operations.
REGULATION AND RATES
Utility Industry Restructuring in Wisconsin & Michigan
Because of the increased focus on competition in the
electric and natural gas utility industries, the Public Service
Commission of Wisconsin (PSCW) is investigating changes in the
structure and regulation of both industries. The Company has
actively participated in these proceedings. In 1994, the PSCW
asked each utility in the state for comments regarding retail
competition. In response to the request, the Company filed the
following recommendations: (1) competition should be phased in
for retail markets by customer classes, with all customers having
choice of supplier by 2001, (2) the generation segment of the
industry should be deregulated by 2001, (3) prudent stranded
costs should be recovered prior to the advent of retail wheeling
and (4) utilities and other competitors should have a level
playing field for issues such as obligation to serve, eminent
domain, requirements for demand side management, funding of
social programs, opening of retail markets to competition and
other issues. Also, as an outcome of the responses to the PSCW,
a task force was formed by the PSCW to analyze the industry
restructuring necessary in the state of Wisconsin. To date,
after reviewing a set of proposals developed by its working
group, the PSCW has set a target date of 2001 for implementing
competition in retail electric markets, established prerequisites
for retail competition and defined a work plan for achieving the
prerequisites. The work plan includes unbundling the components
of the integrated utility, setting service standards and
establishing methods for the continued promotion of energy
conservation and renewable resources.
In February 1996, the PSCW issued its report to the state
legislature on restructuring the electric industry. The report
was the culmination of over a year of work by representatives
from a wide range of interests, including low income advocates,
environmental groups, consumer groups, regulators and the
utilities. The Company played an active role in the efforts.
Key elements of the report include: (1) unbundling the vertically-
integrated utility functions into generation, transmission,
distribution and energy services; (2) improving competition in
electric generation while insuring consumer access to the low
costs associated with existing power plants; (3) preventing the
exercise of market power by large companies; (4) revising
Wisconsin's regulatory processes while protecting the
environment; (5) working to transform the transmission system
into a common carrier; (6) developing distribution and retail
service requirements and (7) developing alternative means for
funding and providing social benefits to customers. The report
included a 32 step plan to achieve these elements with the
ultimate goal of opening the retail market to competition by the
year 2001. The PSCW began implementing the 32 step plan in 1996.
As of the end of the year, parties have filed plans with the PSCW
to unbundle utility functions; completed hearings on revising the
State's Advance Plan and Certificate of Public Convenience and
Necessity processes; developed proposals regarding the funding
and delivery of low income, energy efficiency, renewable resource
and environmental research services; and began work on an initial
distribution and retail service requirements. In addition, the
PSCW issued an order in September that set minimum standards for
creating an ISO that differs from the Company's and WEC's
proposal for an ISO related to the proposed merger to form
Primergy.
In Michigan, the Michigan Public Service Commission (MPSC)
recently released a report setting out their proposal for
instituting retail access. In their report, the MPSC endorsed
two fundamental principles: (1) all customers should be eligible
to participate in the emerging competitive market, and (2) rates
should not be increased for any customers and should be reduced
where possible. The MPSC's plan calls for utilities to open up 2
1/2% of their loads each year beginning in 1997, with full retail
access in effect by the year 2007. Also, the plan calls for
stranded costs to be recovered through the use of rate reduction
bonds; the institution of performance based rates for
transmission and distribution service, the requirement that
originating suppliers in any retail access transaction provide
reciprocal rights to the utility providing the retail direct
access service, distribution utility provision of service to
customers who do not choose to participate or who cannot
participate in the program, and unbundling of rates into separate
functions. Parties were asked to comment by January 21, 1997.
The Company filed comments generally recommending that the MPSC
permit utilities whose operations are primarily in Wisconsin to
follow retail competition approved in Wisconsin with respect to
consumer choice.
During 1995, the PSCW decided that, as competition increases
in natural gas markets, distribution service will need to be
totally separated from unregulated activities. To further that
objective, during 1996, the PSCW adopted standards of conduct to
govern transactions between utilities and their gas marketing
affiliates. They also examined the issue of how to determine
when specific markets are competitive and ready for deregulation.
This is the point at which natural gas utilities will need to
stop offering unregulated services. An order is expected in this
docket this year. In 1997, the PSCW will determine how utility
consumer protection services, such as the winter moratorium and
supplier of last resort, and utility public benefit programs,
such as low income and energy efficiency services, should be
implemented in the future. As part of the gas restructuring
efforts in Michigan, the MPSC issued an order on October 7, 1996,
authorizing Michigan utilities to file customer choice pilot
programs. Under these pilots, customers would be free to choose
their gas supplier. The order did not mandate such pilots, but
left it up to the individual utilities. The Company has no
immediate plans to file for such a pilot.
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
1995, the Wisconsin legislature passed statutory changes raising
the minimum project expenditure requiring a CA generally from
$1,000,000 to $3,000,000. Any transmission projects costing less
than $3,000,000, and less than 10 miles in length, no longer
require PSCW approval.
Before a major electric 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 construction plans are reviewed. In
1995, the Company received approval of its most recent Advance
Plan filing.
Ratemaking Principles in Wisconsin
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 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 92.0 percent of the Company's 1996 revenues from
sales were subject to PSCW jurisdiction. Of the 92.0 percent,
70.8 percent was generated from electric retail revenues and the
remaining 21.2 percent from retail gas revenues. The Company's
wholesale revenues from sales subject to FERC jurisdiction were
approximately 4.5 percent of the Company's 1996 revenues from
sales with the remaining 3.5 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 can deviate from requirements for special
circumstances as noted below.
The PSCW reviews each utility's cash position to determine
if a current return on Construction Work in Progress (CWIP) will
be allowed. The PSCW will allow either a return on CWIP or
capitalization of 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 January 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.
The PSCW conducted a generic hearing in March 1996 under
Docket No. 05-GI-106 to consider alternative incentive-based gas
cost recovery mechanisms to replace the current purchased gas
adjustment clause. In its November 5, 1996 order, the PSCW
issued general guidelines for incentive-based gas cost recovery
mechanisms as well as "modified one-for-one" gas cost recovery
mechanisms. The order required all major gas utilities in
Wisconsin to file a proposal to replace their current purchased
gas adjustment clause, but allowed individual utilities
discretion in choosing which type of gas cost recovery mechanism
to file. The Company plans to file a proposal for a modified one-
for-one gas cost recovery mechanism by July 1, 1997, according to
the schedule established by the PSCW. Under a modified one-for-
one gas cost recovery mechanism (GCRM), the allowable gas
commodity cost recovery would be based on a benchmark index,
which in turn is based on the market price of gas. The allowable
cost recovery of the remaining components of the cost of gas (for
example, interstate pipeline transportation) would be based on
actual costs incurred, as is now the case with the purchased gas
adjustment clause.
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-revenues are refunded and any under-
revenues are collected, including interest. For 1997 the Gas
Cost Recovery Factor is in place, however, due to the pending
merger with WEPCO, the Company has received approval of a waiver
of the Power Supply Cost Recovery Factor. The waiver has been
challenged by the Michigan Attorney General.
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.
Rate Matters by Jurisdiction
Wisconsin
On June 1, 1995, the Company filed an application with the
PSCW requesting no change in the electric utility rates for 1996
and a $2.7 million (3.6%) increase in gas utility rates for 1996.
On October 6, 1995, the PSCW directed the Company to decrease
electric rates by $4.8 million (1.7%). On December 21, 1995, the
PSCW issued an order approving a $2.5 million gas rate increase
(3.4%). An effective date of January 1, 1996, was authorized for
both of these rate changes. In its orders, the PSCW deviated
from its normal biennial rate case filing requirements and
directed the Company to file complete electric and gas rate cases
in early 1996 for the test year beginning January 1, 1997, as
discussed below. This special filing was requested by the PSCW
to facilitate its review of the Company's pending application to
merge with WEPCO.
On March 15, 1996, the Company filed a full rate case for
the 1997 test year on a stand-alone basis as requested by the
PSCW. The Company's filing described revenue deficiencies for
both the electric and gas utilities. However, no rate increases
were requested. Technical hearings for the Company's electric
and gas rate cases were held before the PSCW on July 8, 1996. On
November 26, 1996, the PSCW issued an order approving the
Company's application for no change in rates. However, certain
classes of customers will experience small changes in rates as a
result of rate design revisions requested by the Company. These
changes to electric rates for certain customers classes have an
offsetting effect on overall revenues. There were no significant
changes to gas rates. In its order, the PSCW approved a capital
structure composed of 45% debt and 55% common equity, and granted
an 11.3% return on common equity.
The Company, WEC and WEPCO filed for approval of the
proposed Merger Transaction on August 4, 1995. The merger
application requested deferred accounting treatment and rate
recovery of costs incurred associated with the proposed merger.
Electric and gas rate plans were filed that proposed a 1.5%
reduction in electric rates and a $4.2 million reduction in gas
rates (of which $0.6 million relates to the Company) at the time
of the Merger Transaction and four-year rate freeze thereafter,
with certain exceptions.
On March 18, 1996, the Company and WEC filed testimony and
exhibits supporting the original August 4, 1995, Merger
Transaction filing. On July 24, 1996, the PSCW held a prehearing
conference on the merger proceeding. At the prehearing
conference, the parties agreed upon an extensive issues list and
a schedule for the hearing. At its open meeting on August 8,
1996, the PSCW revised the schedule and set hearings to begin
October 30, 1996. In October 1996, the PSCW staff filed
testimony with the PSCW proposing various conditions, including
potential divestiture of certain transmission, generation and gas
assets and a larger reduction in electric rates than proposed by
the Company and WEC. The staff recommendations differ materially
from the merger terms and conditions included in the application
the Company and WEC originally filed with the PSCW. In January
1997, a Dane County Circuit Court judge ordered the PSCW to delay
its decision on the merger, pending the results of an
investigation regarding alleged prohibited conversations between
one of the PSCW commissioners and WEC officials. The judge
ordered the PSCW to investigate the allegations. At the request
of the PSCW, the matter is under investigation by the District
Attorney's Office to Milwaukee County. The Company cannot
predict when the PSCW will resolve the allegations and proceed
with deliberations concerning the proposed merger. In early
1997, legislation was introduced in the Wisconsin legislature to
revise the statue under which the PSCW review utility mergers.
As introduced, the legislation would apply to the Primergy merger
if it is still pending before the PSCW at the time the
legislation is signed into law. In that event, it is highly
likely that the PSCW would be required to hold additional
hearings on the merger application.
In September 1996, the PSCW issued an order setting minimum
standards for creating an ISO that differ from the Company's and
WEC's ISO proposal. This order was issued as part of a generic
electric utility restructuring process the PSCW started in 1995.
Although the restructuring process is separate from the merger
proceedings, the order is related because the PSCW staff, in its
testimony filed in the merger proceeding, as discussed above,
recommended establishing an ISO that meets the standards of the
PSCW's order as a condition of approving the merger. In
addition, in September 1996, the PSCW submitted its ISO order to
the FERC with a request that FERC require an ISO satisfying the
PSCW minimum standards as a condition of FERC approval of the
NSP/WEC merger application. In October 1996, Company and WEC
filed with the PSCW, as supplemental testimony and exhibits in
the merger proceeding, the same ISO proposal filed with the FERC,
as discussed later.
The Company was originally scheduled to file a general rate
case in June of 1997 for rates effective January 1, 1998 as
required by the PSCW biennial filing schedule. However, because
of the PSCW's decision to deviate from this schedule, it is
unlikely the Company will file a rate case until later in 1997,
if at all. If the PSCW approves the NSP/WEC merger, the Company
anticipates the PSCW will waive the biennial rate case filing
requirement and instead will accept the rate reductions and the
four-year rate freeze as proposed in the companies' merger
application.
Michigan
There were no changes in the Michigan electric or gas base
rates during 1996. The Company does not anticipate the need to
file for a change in Michigan rates in 1997.
The Company and WEPCO filed for MPSC approval of the Merger
Transaction on August 4, 1995. Electric and gas rates were filed
that proposed a rate reduction and a four-year rate freeze. The
MPSC gave its approval for the merger on April 10, 1996.
Wholesale (FERC)
The Company is providing power supply to ten municipal
wholesale customers with 1996 revenues of $17.4 million. This
reduction of $0.5 million from 1995 revenues was the result of
offering discounted rates to customers in exchange for longer
contract terms. In 1996, seven customers received discounts of
three to five percent below the FERC authorized W-1 Wholesale
rate. In that same year, one customer, whose contract term was
completed, renewed its power supply agreement for five years,
including a discount beginning in 1997. Beginning in 1996, two
customers began service under five-year negotiated rate
agreements and at the end of the five year terms, the Company
will have no further obligation to serve these two customers.
All ten municipal wholesale customers have current power supply
agreements ranging from four to ten year terms. Changes in the
wholesale market were anticipated and the Company is providing
discounts and negotiated services to be competitive. Due to
these changes, 1997 revenues are estimated to decrease from 1996
levels by $0.4 million. Two Investor Owned Utilities (IOU)
wholesale customers renewed their agreements in late 1996 for an
additional five years. They will purchase almost all of their
power supply requirements from the Company. A partial
requirements sale is also being made to one additional municipal
customer.
Electric Transmission Tariffs and Settlement (FERC)
NSP has been an industry leader in the area of transmission
open access. In 1990, the Minnesota Company and the Company
jointly filed a transmission services tariff for certain
transmission customers on the NSP System (as defined later). New
rates were effective under the filing, subject to refund, for the
period December 29, 1990, through October 31, 1994. On February
5, 1996, the FERC denied the companies' request for a rehearing
and required the companies to submit a refund compliance filing
in the amount of $1.7 million. A compliance filing was made on
March 29, 1996, and the amount refunded by both companies in 1996
was $1.4 million (the Company's portion was $1.0 million). The
refund had been fully accrued as of December 31, 1995.
In March 1994, the Minnesota Company and the Company jointly
filed a revised open access transmission tariff with the FERC. On
April 11, 1995, an Offer of Settlement (the Settlement) was
entered into by a majority of the parties involved in this
proceeding. The settlement agreement includes a transmission
tariff that complies with the FERC transmission pricing policy
which calls for comparability of service and pricing, network
service, and unbundling of ancillary charges such as scheduling
and load following. The FERC approved the Settlement on February
14, 1996, subject to the outcome of the final rule in the open
access proceedings discussed below. The total revenue effect of
the settlement on both the Company and the Minnesota Company
would produce an increase in revenues of approximately $200,000
per year. The new tariff enables the Company and the Minnesota
Company to comply with transmission pricing provisions of open
access transmission requirements of the Energy Policy Act of
1992. On October 11, 1996, NSP filed the Order No. 888 proforma
tariff using the settlement rates from the approved NSP tariff.
Open Access Transmission Proceedings (FERC)
In April 1996, the FERC issued two final rules, Order Nos.
888 and 889, which may have a significant impact on wholesale
markets. Order No. 888, which was preceded by a Notice of
Proposed Rulemaking referred to as the "Mega-NOPR," concerns
rules on non-discriminatory open access transmission service to
promote wholesale competition. Order No. 888, which was
effective on July 9, 1996, requires utilities and other
transmission users to abide by comparable terms, conditions and
pricing in transmitting power. Order No. 889, which had its
effective date extended to January 3, 1997, requires public
utilities to implement Standards of Conduct and an Open Access
Same Time Information System (OASIS, formerly known as Real-Time
Information Networks). These rules require transmission
personnel to provide the same information about the transmission
system to all transmission customers using the OASIS. A new
proposed rule on Capacity Reservation Open Access Transmission
Tariffs also was issued on April 24, 1996. This proposed rule
requested comments on a new proposed tariff compliance filing and
an information filing that unbundled the transmission component
of the full-requirements municipal wholesale customers' rates.
With regard to the second phase, in December 1996, NSP submitted
its compliance filing which unbundled the transmission component
of its coordination sales agreements. For transactions under
these agreements, these customers became NSP transmission service
customers. In October 1996, the FERC accepted NSP's information
filing. NSP also is in compliance with Order 889. Steps taken
in compliance include the submission of the requisite Standards
of Conduct filing in November 1996 and the training of employees
on these standards in January 1997. NSP continues to be
generally supportive of the FERC's efforts to increase
competition.
The FERC's Order No. 888 required utilities to offer a
transmission tariff that includes network transmission service
(NTS) to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an
instantaneous basis, in a manner similar to NSP's historical
integration of its load and resources. Customers can elect to
participate in the cost-sharing network by requesting NTS service
from NSP. Under NTS, the NSP system and participating customers
share the total annual transmission cost for their combined joint-
use systems, net of related transmission revenues, based upon
each company's share of the total system load. The expected
annual expense increase to the Company, net of cost-sharing
revenues, as a result of offering NTS is estimated to be
approximately $4 million for 1997. In 1996, the Company incurred
approximately $0.5 million of NTS costs.
Proposed Transaction Approval Proceedings (FERC)
In July 1995, the Minnesota Company, the Company and WEC
(the Applicants) filed an application and supporting testimony
with the FERC seeking approval of the Merger Transaction to form
Primergy Corporation. The filing consisted of the merger
application, the proposed joint transmission tariff and an
amendment to the Company's Interchange Agreement with the
Minnesota Company.
The issues raised by intervenors with respect to the merger
application at the FERC are primarily related to two areas: the
impact on competition and the nature of the cost savings. On
January 31, 1996, the FERC issued a ruling which put the merger
approval filing on an accelerated schedule. The FERC set only
one of six merger issues raised by intervenors for hearing,
provided the applicants agreed to a wholesale rate freeze. The
FERC ordered a hearing regarding the effect of the proposed
merger on bulk power competition.
In February 1996, the Applicants agreed to freeze wholesale
rates for four years subsequent to the Merger Transaction.
On May 28, 1996, the Applicants filed additional evidence
with the FERC, providing a detailed analysis of generation
"market power" and more specific information about the
independent system operator (ISO) proposal included in earlier
filings. This additional information was provided to the FERC in
response to concerns raised by intervenors in the merger
proceeding and the FERC staff.
The FERC administrative law judge (ALJ), in the merger
proceeding, issued an initial decision on August 29, 1996,
recommending approval of the merger application, subject to the
Applicants meeting eight conditions. A significant part of the
ALJ's initial decision discusses the design of an ISO. The ALJ's
initial decision specifically rejected the need for divestiture
of any generation or transmission facilities as a requirement for
ensuring open and equal access to the transmission system. In
October 1996, the Applicants filed a Unilateral Offer of
Settlement (UOS) with the FERC. The UOS includes a transmission
system control agreement and articles and bylaws for establishing
an ISO, intended to meet the requirements of the ALJ's decision
and FERC guidelines. In mid-December 1996, the FERC revised and
streamlined its 30-year-old policy for evaluating public utility
mergers, with the changes designed to expedite the processing of
merger applications. The new policy primarily focuses on three
factors in reviewing mergers: the effect on competition, rates,
and state and federal regulation. For pending mergers, the
policy will be applied on a case-by-case basis. The Applicants
believe the proposed merger is consistent with the FERC's revised
merger policy and are hopeful that the FERC will simultaneously
rule on the UOS and the pending merger application in 1997.
Other Proceedings (FERC)
In September 1996, the Minnesota Company and the Company
filed for FERC approval to "abandon" FERC's jurisdiction over two
liquefied natural gas (LNG) plants they operate near St. Paul,
Minnesota, and Eau Claire, Wisconsin, respectively. FERC
asserted jurisdiction over the plants in the late 1970s, and each
company has provided FERC regulated LNG services from its plant
since that time. Under the filings, FERC would abandon
jurisdiction under Section 7 (c) of the Natural Gas Act, but
would retain limited jurisdiction under Section 18 of Code of
Federal Regulations (CFR) Part 284.224. The "abandonments" are
required to complete the Primergy merger, but would also allow
the Company and the Minnesota Company to modify the LNG plant
facilities or provide new LNG services without prior FERC
approval.
Minnesota Company Jurisdictions' Proposed Merger Transaction
Proceedings
Minnesota Public Utilities Commission (MPUC)
On August 4, 1995, the Minnesota Company filed for MPUC
approval of the Merger Transaction with WEC. The Minnesota
Company proposed a rate plan which would reduce electric rates by
1.5 percent subsequent to the merger and a four-year rate freeze
thereafter, except for certain uncontrollable events. The rate
plan was modified in March 1996 to also provide for a freeze in
gas rates through 1998. The proposed rate plan included a
request for a four-year amortization of the costs associated with
the Merger Transaction.
In June 1996, the MPUC issued an order that established the
procedural framework for the MPUC's considerations of the merger.
Contested case hearings were ordered for the issues of merger-
related savings, electric rate freeze characteristics, the Minnesota
Company's pre-merger revenue requirements, Primergy's ability to control
the transmission interface between the Mid-Continent Area Power Pool
(MAPP) and the Wisconsin and Upper Michigan area, and the impact
of control of this interface on other Minnesota utilities.
Evidentiary hearings were held from November 20 through December
3, 1996. The Minnesota Department of Public Service recommended
a rate reduction of 2.0 percent, compared with the 1.5 percent
reduction the Minnesota Company proposed. In January and
February 1997, administrative law judges issued their findings
and recommendations in the Minnesota merger applications. Among
other items they found: that NSP's projected merger-related cost
savings in general were reasonable; recommended a four-year rate
freeze, with very limited exceptions for rate changes; concluded
that the merger would not provide Primergy with the ability or
incentive to negatively impact competition; and determined the
Minnesota Company's pre-merger electric rates for Minnesota
retail customers may exceed revenue requirements by $3.5 million,
or one-fifth of one-percent. The MPUC will consider the
administrative law judges' recommendations along with other
information when it deliberates and decides the case. On March
5, 1997, the Minnesota Office of the Attorney General, a
participant in the merger cases, filed a brief which expressed
for the first time opposition to the merger. Although NSP had
hoped for approvals from all jurisdictions by the end of 1996, it
now appears that the MPUC could reach decisions within the first
half of 1997. On March 12, 1997, the MPUC issued a notice that
it will consider whether to request additional public hearings as
well as additional written comments. The MPUC stated if
additional hearings or written comments are necessary, final
deliberations in this matter could be scheduled for June or July
1997. On March 20, 1997, the MPUC heard comments from the
parties on the need for additional hearings or other procedures
prior to making a decision on the merger. While NSP believes the
case is ready for decision now, the MPUC is considering what
further procedures, if any, it will require. If no further
procedures are undertaken, a decision in the second quarter is
expected.
In July 1996, the MPUC, on a motion from a Commissioner,
voted to request an investigation into allegations of improper
communications between two Commissioners and a Minnesota Company
lobbyist. The MPUC in September 1996 determined in an order that
no improper contact had taken place. Upon reconsideration of the
matter in December 1996, the MPUC reversed itself and found the
communications were improper. However, in January 1997, prior to
issuing an order on its December decision, the MPUC reconsidered
and nullified its December decision. No final order has been
issued.
The need for general rate filings in 1997 depend upon the
outcome of the merger case.
North Dakota Public Service Commission (NDPSC)
On August 4, 1995, the Minnesota Company filed for NDPSC
approval of the Merger Transactions with WEC. The Minnesota
Company proposed a rate plan which would reduce electric rates by
1.5 percent on January 1, 1997, or after the close of the Merger
Transaction, and implement a four-year rate freeze thereafter,
with certain exceptions. A 1.25 percent rate reduction and a
four-year rate freeze in gas rates was also proposed. Public
hearings on the Merger Transaction were held in Minot, Grand
Forks and Fargo, North Dakota, in November and December 1995. A
technical hearing was held in March 1996. The NDPSC voted
unanimously to approve the Merger on June 26, 1996, basically on
the terms proposed by NSP.
South Dakota Public Utilities Commission (SDPUC)
In 1995, the SDPUC determined that it did not have
jurisdiction to approve or deny the Merger Transaction with WEC.
On September 30, 1996, the Minnesota Company filed a 1.5% or $1.2
million electric rate reduction to be effective upon closing of
the Merger Transaction. After the merger-related reduction,
South Dakota rates would then be frozen through 2000.
ELECTRIC OPERATIONS
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, the President signed into law the Energy
Policy Act of 1992 (Energy Act). The Energy Act amends the
Public Utility Holding Company Act of 1935 (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 promote the
continued trend of increased competition in the electric energy
markets. NSP plans to continue its efforts 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
requests for the use of its transmission facilities as power
marketers continue to enter the electric industry. In 1996, the
Company filed 58 transmission service agreements for FERC
approval.
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 "Rates and
Regulation," 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 Company's electric production and transmission systems
are interconnected with the production and transmission system of
the Minnesota Company. The combined electric production and
transmission systems of the Company and the Minnesota Company are
hereinafter called the "NSP System."
The facilities of the NSP System include coal and nuclear
generating plants, hydro, gas fired combustion turbines, waste
wood, and waste wood/refuse derived fuel (RDF) generating plants,
an interconnection with 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.
The Minnesota Company operates two nuclear generating
plants: the single unit, 539 Megawatts (MW) Monticello Nuclear
Generating Plant and the Prairie Island Nuclear Generating Plant
with two units totaling 1,025 MW. The Monticello Plant received
its 40-year operating license from the NRC on September 8, 1970,
and commenced operation on June 30, 1971. Prairie Island Units 1
and 2 received their 40-year operating licenses on August 9,
1973, and October 29, 1974, respectively, and commenced operation
on December 16, 1973, and December 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 pool capacity for temporary storage of used fuel
to operate until 2008. 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 2003.
The Minnesota Company 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 2010. Consequently, the Minnesota
Company 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 13, 1995,
and was recorded at 1,075 MW. The peak demand for 1996 occurred
on August 6 with 1,034 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 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). In March 1996, the members of MAPP
approved the conversion of MAPP into a Regional Transmission
Group (RTG). On September 12, 1996, the conversion plan, the
"Restated Mid-Continent Area Power Pool Agreement, January 12,
1996", was approved by the FERC, in Docket No. ER96-1447, and
became effective November 1, 1996. By converting MAPP to an RTG,
members will have more input into transmission access within
other member's territories. This is one of the proposals in
response to intervenor concerns in the FERC regulatory approval
proceeding of the Minnesota Company's proposed merger with WEC.
(See "Regulation and Rates")
The Company primarily relies on the Minnesota Company,
through the Interchange Agreement (see Electric Operations -
Interchange Agreement), for base load generation. Approximately
77 percent of the total kilowatt hour requirements of the Company
were provided by the Minnesota Company generating facilities or
purchases made by the Minnesota Company for system uses in the
year 1996.
The Company also has two electric steam generating
facilities. One is the Bay Front Generating Plant which is
located in Ashland, Wisconsin. The plant is fueled primarily by
natural gas, coal and wood residue. Recent modifications to the
facility allow for more effective utilization of additional waste
wood fuel supplies and have extended the useful life of the
facility approximately 20 years from their completion in 1992.
In 1992 the Company received authorization from the Wisconsin
Department of Natural Resources (WDNR) to burn tire derived fuel
at the Ashland plant on a regular basis.
The Company's second electric steam generating plant is the
French Island plant located in La Crosse, Wisconsin, which has
two fluidized bed boilers modified for the purpose of burning a
mixture of waste wood and RDF. The Bay Front plant in Ashland
and the French Island steam plant are primarily used on an
intermediate load basis.
The Company's thermal peaking capability consists of two oil-
fired gas turbine peaking plants and a gas and oil turbine
peaking plant. The Company also has 19 hydro plants that operate
as peaking facilities or run-of-river facilities.
Demand Side Management
The Company continues to implement various Demand Side
Management (DSM) programs designed to improve load factor and
reduce the Company's power production cost and system peak
demands, thus reducing or delaying the need for additional
investment in new generation and transmission facilities. The
Company currently offers a broad range of DSM programs to all
customer sectors, including information programs, rebate and
financing programs, and rate incentive programs. In management's
opinion, these programs respond to customer needs and focus on
increasing value of service that, over the long term, will reduce
the company's capital requirements and help its customer base
become more stable, energy efficient and competitive.
During 1996, the Company's programs accomplished
approximately 20.5 MW of system peak demand reduction in the
commercial, industrial and agricultural customer sectors and over
2.5 MW in the residential sector. These impacts were obtained
through appliance, lighting, motor, and cooling efficiency and
process improvements, peak curtailable and time-of-use rate
applications and direct load control of water heaters and air
conditioners.
Since 1986, the Company's DSM programs have achieved 196 MW
of summer peak demand reduction, which is equivalent to almost
19% of the Company's 1996 summer peak demand. The Company is
working towards a cumulative goal of 200 MW of peak demand
reduction by the end of 1997. The Company continues to focus on
improving the cost-effectiveness of its DSM programs through
market research studies and program evaluations.
Since January 1, 1996, the Company has been allowed to
expense rather than defer and amortize DSM program expenditures.
Expenditures incurred prior to 1996 continue to be amortized.
Interchange Agreement
The electric production and transmission costs of the NSP
System are shared by the Company and the Minnesota Company. The
cost-sharing arrangement between the companies is the Agreement
to Coordinate Planning and Operation and Interchange Power and
Energy between the Company and the Minnesota Company (Interchange
Agreement). It is a FERC regulated agreement and has been
accepted by the PSCW and the MPSC for determination of costs
recoverable in rates by the Company for charges from the
Minnesota Company in rate cases.
Historically the Company's share of the NSP System annual
production and transmission costs has been in the 14 to 17
percent range. Revenues received from billings to the Minnesota
Company for its share of the Company's production and
transmission costs are recorded as electric operating revenues on
the Company's income statement. The portions of the Minnesota
Company's production and transmission costs that were charged to
the Company were recorded as purchased and interchange power
expenses and other operation expenses, respectively, on the
Company's income statement. (See Note 6 to Financial
Statements).
Under the Interchange Agreement, the Company could be
charged a portion of the cost of an assessment made against the
Minnesota Company pursuant to the Price-Anderson liability
provisions of the Atomic Energy Act of 1954. (See Note 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, pursuant to the RTG agreement discussed previously.
The NSP System is one of 53 members, 27 associate members and 6
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 an RTG, as discussed
previously, was approved by the FERC September 12, 1996 and has been
in effect since November 1, 1996.
Fuel Supply
In 1996 the Company shared in the fuel supply costs incurred
by the Minnesota Company in accordance with the Interchange
Agreement. Coal and nuclear fuel will continue to dominate the
NSP System fuel requirements for the generation of electricity.
It is expected that approximately 97 percent of the NSP System
annual fuel requirements on a Btu basis will be provided by these
two sources and that 3 percent of the NSP System's annual fuel
requirements for generation will be provided by other fuels
(including natural gas, oil, refuse derived fuel, waste
materials, renewable sources, and wood) over the next several
years. The actual fuel mix for 1996, and the estimated fuel mix
for 1997 and 1998, are as follows:
Fuel Use on Btu Basis
(Est.) (Est.)
1996 1997 1998
Coal 59.7% 60.3% 59.3%
Nuclear 37.2% 36.5% 37.5%
Other 3.1% 3.2% 3.2%
Electric Operating Statistics
The follow table summarizes the revenues, sales and customers from the
Company's electric business, excluding sales to the Minnesota Company and
miscellaneous revenues:
Operating Statistics
1996 1995 1994 1993 1992
Electric Revenue (thousands)
Residential
With space
heating $ 22 876 $ 24 825 $ 23 916 $ 24 086 $ 22 521
Without space
heating 95 681 96 248 92 033 90 632 85 889
Small commercial and
industrial 54 500 54 826 53 842 52 214 50 234
Large commercial and
industrial* 110 318 110 270 107 462 101 609 95 336
Streetlighting and
other 4 371 4 320 4 335 4 262 4 206
Total retail 287 746 290 489 281 588 272 803 258 186
Sales for resale 17 391 17 902 17 414 16 009 14 755
Total $305 137 $308 391 $299 002 $288 812 $272 941
Sales (millions of kilowatt-hours)
Residential
With space heating 348 372 358 362 346
Without space
heating 1 358 1 346 1 284 1 265 1 229
Small commercial and
industrial 896 882 863 834 814
Large commercial and
industrial* 2 466 2 403 2 306 2 169 2 098
Streetlighting and
other 43 42 43 42 43
Total retail 5 111 5 045 4 854 4 672 4 530
Sales for resale 458 456 438 417 394
Total 5 569 5 501 5 292 5 089 4 924
Customer accounts (Dec. 31)
Residential
With space heating 29 133 28 783 28 391 27 958 27 518
Without space
heating 154 200 152 368 150 082 148 108 146 704
Small commercial and
industrial 28 541 28 066 27 481 26 928 26 671
Large commercial and
industrial* 1 412 1 322 1 234 1 171 1 142
Streetlighting and
other 1 003 1 000 989 989 1 007
Total retail 214 289 211 539 208 177 205 154 203 042
Sales for resale 10 10 10 10 10
Total 214 299 211 549 208 187 205 164 203 052
*Includes customers with annual electric demand of 100 kilowatts or
more.
GAS OPERATIONS
During 1996, 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's Order 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 (NNG),
Great Lakes Transmission Limited Partnership, Northern Border
Pipeline Company, Viking Gas Transmission Company (Viking),
another subsidiary of the Minnesota Company, and TransCanada
Pipeline, LTD.
The Company's ability to operate in a competitive gas market
was expanded through the Minnesota Company's acquisitions of
Viking in June 1993 and the formation of an energy services
business, Cenerprise, Inc. (Cenerprise), in October 1993.
Viking allows NSP continued access to competitive interstate
natural gas transportation. Cenerprise, a Minnesota Company
subsidiary, 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.
The Company has been providing limited non-traditional
services under a pilot project approved by the PSCW which allows
the Company to take advantage of its unique position in the
United States and Canadian supply markets. Examples of non-
traditional activities may include sales of unused system supply
if profitable and brokerage of gas not purchased or required for
system needs. These non-traditional marketing opportunities are
a result of deregulation in the natural gas industry.
Traditional regulated services would not have allowed a mark-up
on gas costs. The pilot project, with its sharing of benefits
between customers and shareholders, was, by order of the PSCW,
discontinued at the end of 1996. In 1997, the Company will
continue these activities with 100% of the revenues credited back
to customers.
In January 1997, the PSCW adopted "Standards of Conduct" for
retail natural gas utilities (LDCs) serving Wisconsin consumers.
The standards would apply to the Company's existing gas
operations, and the retail gas operations of New NSP and
Wisconsin Energy Company after the proposed Merger Transaction.
The standards are similar to, but much more extensive than, the
standards of conduct FERC has imposed on Viking under Order 497
and on NSP's wholesale electric transmission functions under
Order 889. The PSCW standards require separation of the LCD
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. PSCW approval is pending.
Gas Operating Statistics
The follow table summarizes the revenues, sales and
customers from the Company's gas business, excluding sales to the
Minnesota Company and miscellaneous revenues (including purchased
gas adjustments):
1996 1995 1994 1993 1992
Revenues (thousands)
Residential
With space heating $40 635 $36 695 $33 726 $32 029 $27 592
Without space
heating 747 556 571 535 480
Small com.w/o space
heating 1 893 929 869 824 697
Small com.with space
heating 22 412 19 263 17 691 17 049 14 990
Small industrial firm 2 309 6 428 6 545 5 961 3 942
Total firm 67 996 63 871 59 402 56 398 47 701
Interruptible 20 419 16 569 15 299 15 156 13 015
Total $88 415 $80 440 $74 701 $71 554 $60 716
Sales (thousands of mcf)
Residential
With space heating 6 355 5 801 5 243 5 221 4 756
Without space heating 102 72 73 72 66
Small com.w/o space
heating 481 180 168 162 145
Small com.with space
heating 4 167 3 785 3 424 3 403 3 142
Small industrial firm 1 774 2 162 2 126 1 932 1 128
Total firm 12 879 12 000 11 034 10 790 9 237
Interruptible 7 135 6 951 6 032 6 153 5 650
Total 20 014 18 951 17 066 16 943 14 887
Customer Accounts (Dec. 31)
Residential
With space heating 63 112 60 420 57 263 54 535 51 583
Without space
heating 2 756 2 756 2 931 2 995 3 106
Small com.w/o space
heating 686 573 563 537 539
Small com.with space
heating 7 665 7 385 7 052 6 707 6 462
Small industrial firm 6 119 116 116 110
Total firm 74 225 71 253 67 925 64 890 61 800
Interruptible 300 300 281 265 265
Total 74 525 71 553 68 206 65 155 62 065
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 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). The
Company has procedures in place to comply with these regulations.
Both the Company and the Minnesota Company have received
requests for information concerning groundwater contamination at
a landfill site in Hudson, Wisconsin. While neither the Company
nor the Minnesota Company has been named potentially responsible
parties (PRPs), both companies voluntarily joined a group of
other parties to address the contamination at this site. A
preliminary estimate of total remediation costs at the site is
approximately $6.5 million. The Company's and the Minnesota
Company's share of this cost is currently estimated to be 0.6%.
The Company's share alone is not expected to exceed $5,000.
In addition, the administrator of a group of PRPs has
notified the Company that it might be responsible for cleanup of
a solid and hazardous waste landfill sites in Eau Claire and
Amery, Wisconsin. The Company contends that it did not
contribute waste consistent with the contaminants of concern in
the subject landfills. 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.
On March 2, 1995, the WDNR notified the Company that it is a
PRP at a creosote/coal tar contamination site in Ashland,
Wisconsin adjacent to Lake Superior. At this time, the WDNR has
determined that the Company is the only PRP at this site. 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 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 December 31, 1996, 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 1996 were $525,000. The PSCW authorized recovery of
$353,000 over a two year period beginning in 1997, which
represents recovery of actual expenditures through 1995. Based
on this PSCW decision to allow recovery of remediation costs incurred,
the Company has recorded a regulatory asset for the estimated accrued
and actual incurred expenditures related to the Ashland site. 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.
On February 12, 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 has worked with the WDNR throughout 1996
to establish mutually agreed-upon CO emission limits for the Bay
Front facility. No fines or other enforcement mechanism have
occurred nor are they expected.
On March 11, 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 #1, resulted in the WDNR clearing the
NOV on Unit #1 on September 25, 1996. On October 9, 1996, the
Company received a letter from the WDNR reiterating the
outstanding NOV on Unit #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. The Company is currently
investigating this matter to determine the cause of these
unexpected events. At this time, the Company is unable to
predict whether any fines will be imposed by the WDNR against the
Company or what further corrective action may be required. The
Company does not believe any fines, if levied, or corrective
action, if required, will have a material adverse effect on the
Company's financial condition or results of operation.
In late December 1996, the Company completed installation of
continuous emission monitors for carbon monoxide at the French
Island Generating facility in La Crosse, Wisconsin. 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.
CONSTRUCTION AND FINANCING
During the five years ended December 31, 1996, the Company
had gross additions to utility plant in service of approximately
$262.6 million. Included in the Company's gross additions is
$26.6 million for electric production facilities, $150.2 million
for other electric properties, $39.4 million for gas utility
properties, and $46.4 million for other utility properties.
Retirements during the same period were approximately $39.9
million. Based on studies made by the Company, the weighted
average age of depreciable property was 13.8 years at December
31, 1996.
Expenditures for the Company's construction programs for the
five-year period 1997-2001, are estimated to be as follows:
Year Estimated Construction Expenditures
1997 $ 58 million
1998 68 million
1999 77 million
2000 75 million
2001 81 million
TOTAL $359 million
The 1997 construction expenditures are estimated to include
approximately $41.9 million for electric facilities, $4.5 million
for gas facilities and $11.3 million for general plant and
equipment. It is presently estimated that approximately 73% of
the 1997-2001 construction expenditures will be provided by
internally generated funds, with the remainder from short-term
and long-term debt financing. At December 31, 1996, the
Company's short-term borrowings payable to the Minnesota Company
were $39.3 million. The PSCW has authorized up to $80 million of
these short-term borrowings. The Company currently projects the
need for $50 million of long-term debt in 1999 to finance the
estimated construction expenditures for the 1997-2001
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.
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1996, the total number of full- and part-time
employees of the Company was approximately 902. About 393
employees of the Company are represented by one local IBEW labor
union, under a three year collective bargaining agreement which
expired December 31, 1996, but was extended to April 30, 1997.
Management and union representatives have reached a tentative
agreement on the terms of a new collective bargaining agreement,
subject to approval by the union membership. NSP is not able to
predict the outcome at this time.
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% 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
1996, based on matching up to $900 per year for each
nonbargaining employee and up to $600 per year for each
bargaining employee.
Wage increases: Under a market-based pay structure
implemented for nonbargaining employees in 1994, the Company uses
salary surveys that indicate how local and regional companies pay
their employees for comparable positions. In January 1996,
nonbargaining employees received an average wage scale increase
of 3.5%, while bargaining employees received a 4.0% base wage
increase. In January 1997, non bargaining employees received an
average wage scale increase of 4.0%. Wage increases for
bargaining employees in 1997 will be determined by the new
collective bargaining agreement which is not yet final, as
discussed previously.
Item 2. Properties
Electric Utility
The Company's major electric generating facilities consist
of the following:
Projected
Year 1997-8 Winter
Station and Units Fuel Installed Capability (MW)
Combustion Turbine:
Flambeau Station Gas/Oil 1969 17
(1 unit)
Park Falls, WI
Wheaton Oil 1973 443
(6 units)
Eau Claire, WI
French Island Oil 1974 192
(2 units)
La Crosse, WI
Steam:
Bay Front Coal/Wood/ 1945-1960 75
(3 units) Gas
Ashland, WI
French Island Wood/RDF 1940-1948 29
(2 units)
La Crosse, WI
Hydro Plants:
(19 plants) Various dates 249
TOTAL 1 005
At December 31, 1996, the Company owned approximately 2,392
pole miles of overhead electric transmission lines, 8,338 pole
miles of overhead electric distribution lines, 38 conduit miles
and 1,052 direct buried cable miles of underground electric
lines. Virtually all of the land and personal property owned by
the Company is subject to the lien of their first mortgage bond
indentures pursuant to which the Company has issued first
mortgage bonds.
Gas Utility
The gas properties of the Company include approximately
1,538 miles of natural gas distribution mains. The Company owns
two liquefied natural gas facilities with a combined storage
capacity of the equivalent of 400,000 Mcf to supplement the
available pipeline supply of natural gas during periods of peak
demands. The two liquefied natural gas facilities are located in
Eau Claire and La Crosse, Wisconsin. The La Crosse LNG facility
is currently nonoperational. In January of 1993, the Company
installed temporary propane air facilities with a capacity of
144,000 gallons to further supplement its gas supply in the La
Crosse, Wisconsin area during peak periods. This propane air
facility was not operational for the 1995-96 winter, but was used
in the 1996-97 winter heating season.
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.
On June 20, 1994, the Minnesota Company along with other
major utilities filed a lawsuit against the DOE in an attempt to
clarify the DOE's obligation to dispose of spent nuclear fuel
beginning not later than January 31, 1998. The suit was filed in
the U.S. Court of Appeals, Washington, D.C. The primary purpose
of the lawsuit was to insure that the Minnesota Company and its
customers receive timely storage and disposal of spent nuclear
fuel in accordance with the terms of the Minnesota Company's
contract with the DOE. On July 23, 1996, the U.S. Court of
Appeals for the District of Columbia Circuit, affirmed the
federal government's obligation. The court unanimously ruled
that the Nuclear Waste Policy Act creates an unconditional
obligation for the DOE to begin acceptance of spent nuclear fuel
by January 31, 1998. The DOE did not seek U.S. Supreme Court
review. On January 31, 1997, the Minnesota Company, along with
30 other electric utilities and 45 state agencies, filed another
lawsuit against the DOE requesting authority to withhold payments
to the DOE for the permanent disposal program.
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 J (1) (a) and (b) of Form 10-K for wholly owned
subsidiaries (reduced disclosure format).
Item 7. Management Discussion and Analysis of Financial Condition
and Results of Operations
Management's Discussion and Analysis of Financial
Condition and Results of Operations is omitted per conditions as
set forth in general instructions J (1) (a) and (b) of Form 10-K
for wholly owned subsidiaries. It is replaced with management's
narrative analysis of the results of operations set forth in
general instructions J (2) (a) of Form 10-K for wholly owned
subsidiaries (reduced disclosure format). This analysis will
primarily compare its revenue and expense items for the year
ended December 31, 1996 with the year ended December 31, 1995.
The Company's net income for year ended December 31, 1996
was $38.7 million, down from the $39.2 million earned in
the same period of 1995. The 1996 operating income increased by
$0.4 million from the 1995 level.
Electric Sales and Revenues
Electric revenues in total decreased $4.0 million in 1996.
Sales to unaffiliated customers decreased $3.1 million or 1.0
percent in 1996 as compared to 1995 primarily due to price
decreases net of higher sales levels. Customer and sales growth,
partially offset by less favorable weather in 1996, produced an
electric sales increase of 1.2 percent. These sales increases
were more than offset by decreased revenues from a 1.7 percent
electric rate reduction effective January 1, 1996 as discussed in
the Rate Matters by Jurisdiction section.
The remaining $0.9 million reduction in electric revenues
relates to lower Interchange Agreement billings to the Minnesota
Company as discussed in Note 6 to the Financial Statements.
Gas Sales and Revenues
Gas revenues in 1996 increased $10.7 million or 13.7 percent
as compared with 1995. Gas sales increased 5.6 percent in 1996
from 1995 due to favorable winter weather and sales growth. As
discussed in the Rate Matters by Jurisdiction section, a 3.4
percent gas rate increase effective January 1, 1996 also
contributed to the increased revenues. Gas revenues also
increased due to higher costs per unit of gas purchased, 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 $0.2 million or 0.1 percent in 1996
from 1995. Compared to 1995, the Company's total sales
requirements increased 1.1 percent in 1996. The effects of higher
sales requirements were partially offset by lower average
production costs per unit charged from the Minnesota Company.
Gas Purchased for Resale increased $6.0 million or 11.4
percent in 1996. Of the increase, approximately $2.8 million
relates to additional gas purchases to support increased gas
sales, and approximately $3.2 million relates to a higher cost
per unit of purchased gas.
Other operation, maintenance, and administrative and general
expenses together decreased $4.2 million or 4.6 percent in 1996
as compared to 1995 primarily due to reduced employee benefit
expenses as discussed in Note 5 to the Financial Statements,
lower employee levels, and reduced maintenance on overhead lines.
Conservation costs in 1996 increased $1.4 million as
compared to 1995 due to certain demand side management costs
which were capitalized in previous years.
Depreciation and Amortization increased $2.6 million in 1996
due to increases in the Company's plant in service.
Property and General Taxes increased $0.2 million in 1996
from 1995 primarily due to increases in property tax rates.
Income tax expense was approximately the same for both
years, reflecting comparable pretax operating income.
Allowance for Funds Used During Construction (AFC) decreased
in total by $0.2 million in 1996 from 1995 due to varying levels
of construction work in progress and lower AFC rates associated
with increased use of lower-cost, short-term borrowings to fund
construction.
Other income and deductions decreased $1.0 million in 1996
from 1995 primarily due to lower subsidiary company earnings.
Other interest and amortization (before AFC) expense
decreased $0.3 million in 1996 from 1995. An increase in
interest paid to the Minnesota Company for short-term borrowings
was offset by reduced interest on long-term debt and a 1995
charge for interest on prior year income tax assessments.
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
December 31, 1996 and 1995, and the results of its operations and
its cash flows for the years then ended 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. The financial statements of the Company
for the year ended December 31, 1994 were audited by other
independent accountants whose report dated January 27, 1995
expressed an unqualified opinion on those statements.
/s/
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
February 3, 1997
INDEPENDENT AUDITORS' REPORT
Northern States Power Company (Wisconsin):
We have audited the accompanying statements of income and
retained earnings and of cash flows of Northern States Power
Company (Wisconsin) and its subsidiaries (the Companies) for the
year ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility
is to express an opinion on the financial statements based on our
audit.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audit provides a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the results of operations and cash flows of
the Companies for the year ended December 31, 1994, in conformity
with generally accepted accounting principles.
/s/
Deloitte and Touche LLP
Minneapolis, Minnesota
January 27, 1995
Statements of Income and Retained Earnings
Year Ended December 31
(Thousands of dollars) 1996 1995 1994
Operating Revenues
Electric $ 377 073 $ 381 040 $ 375 105
Gas 88 756 78 058 76 715
Total 465 829 459 098 451 820
Operating Expenses
Purchased and interchange power 173 492 173 743 174 144
Fuel for electric generation 5 165 4 703 5 414
Gas purchased for resale 58 347 52 356 53 484
Other operation 46 920 46 534 44 260
Maintenance 19 617 20 780 22 385
Administrative and general 21 814 25 264 26 487
Conservation and demand side
management 9 117 7 674 7 211
Depreciation and amortization 35 731 33 097 30 774
Property and general taxes 14 332 14 109 13 710
Income taxes 24 688 24 662 19 077
Total operating expenses 409 223 402 922 396 946
Operating Income 56 606 56 176 54 874
Other Income and Deductions
Allowance for funds used during
construction-equity 339 445 671
Other income and deductions-net 677 1 698 574
Total Other Income 1 016 2 143 1 245
Income Before Interest Charges 57 622 58 319 56 119
Interest Charges
Interest on long-term debt 15 918 16 038 15 995
Other interest and amortization 3 406 3 548 2 060
Allowance for funds used during
construction-debt (399) (484) (481)
Total interest charges 18 925 19 102 17 574
Net Income 38 697 39 217 38 545
Retained Earnings, January 1 221 638 218 833 205 114
Dividends paid to parent on common
stock (25 584) (36 412) (24 826)
Retained Earnings, December 31 $ 234 751 $ 221 638 $ 218 833
See Notes to Financial Statements.
Statements of Cash Flows
Year Ended December 31
(Thousands of dollars) 1996 1995 1994
Cash Flows from Operating Activities:
Net Income $38 697 $39 217 $38 545
Adjustments to reconcile net income
to cash from operating activities:
Depreciation and amortization 36 665 34 180 32 382
Deferred income taxes 1 736 1 839 7 614
Deferred investment tax credits
recognized (910) (936) (943)
Allowance for funds used during
construction - equity (339) (445) (671)
Insurance receivable 3 091 (3 091)
Cash provided by (used for) changes
in certain working capital items (2 633) 7 282 (9 568)
Cash used for changes
in other assets and
liabilities (2 691) (1 064) (6 076)
Net Cash Provided by Operating
Activities 70 525 83 164 58 192
Cash Flows from Investing Activities:
Capital expenditures (49 403) (51 173) (52 639)
Increase (decrease) in construction
payables (118) (457) (633)
Allowance for funds used during
construction - equity 339 445 671
Other (897) (1 606) 2 037
Net Cash Used for Investing Activities (50 079) (52 791) (50 564)
Cash Flows from Financing Activities:
Issuances (repayment) of short-term
debt due to parent - net (11 600) 9 600 17 800
Proceeds from issuance of
long-term debt 82 691
Redemption of long-term debt,
including reacquisition premiums (65 992) (3 375) (990)
Dividends paid to parent (25 584) (36 412) (24 826)
Net Cash Used for Financing
Activities (20 485) (30 187) (8 016)
Net Increase (decrease) in cash and
cash equivalents (39) 186 (388)
Cash and cash equivalents beginning
of period 247 61 449
Cash and cash equivalents end
of period $ 208 $ 247 $ 61
Cash provided by (used for) changes
in certain working capital items:
Accounts receivable-net $2 883 ($6 188) $ 770
Materials and supplies (1 447) 3 442 (4 708)
Accounts payable and accrued
liabilities 668 1 241 332
Payables to affiliated companies 2 087 4 475 (2 655)
Income and other taxes accrued (4 007) 417 (4 174)
Other (2 817) 3 895 867
Net ($2 633) $7 282 ($9 568)
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount
capitalized) $ 18 556 $ 15 389 $ 15 870
Income taxes (net of refunds
received) $ 26 977 $ 17 333 $ 18 773
See Notes to Financial Statements.
Balance Sheets
December 31
(Thousands of dollars) 1996 1995
Assets
Utility Plant
Electric-including construction
work in progress:
1996, $11,948; 1995, $12,640 $ 894 143 $ 864 514
Gas 99 817 94 425
Other 67 262 63 758
Total 1 061 222 1 022 697
Accumulated provision for depreciation (395 619) (370 634)
Net utility plant 665 603 652 063
Other Property and Investments
Non-utility property - at cost 3 126 3 123
Accumulated provision for depreciation (327) (334)
Other investments 7 433 6 429
Total other property and investments 10 232 9 218
Current Assets
Cash 208 247
Accounts receivable 41 151 43 988
Accumulated provision for uncollectible
accounts (901) (854)
Materials and supplies - at average cost
Fuel 7 780 6 689
Other 5 918 5 561
Unbilled utility revenues 21 074 18 665
Prepayments and other 11 703 11 295
Total current assets 86 933 85 591
Other Assets
Regulatory assets 37 102 34 704
Unamortized debt expense 1 855 2 780
Federal Income tax receivable 3 307 3 307
Other 4 099 3 235
Total other assets 46 363 44 026
Total Assets $ 809 131 $ 790 898
See Notes to Financial Statements.
December 31,
(Thousands of dollars) 1996 1995
Liabilities and Equity
Capitalization
Common stock-authorized 870,000
shares of $100 par value; issued
shares: 1996 and 1995, 862,000 $ 86 200 $ 86 200
Premium on common stock 10 461 10 461
Retained earnings 234 751 221 638
Total common stock equity 331 412 318 299
Long-term debt (net of unamortized
discount of $1,912 in 1996) 231 688 213 235
Total capitalization 563 100 531 534
Current Liabilities
Notes payable - parent company 39 300 50 900
Accounts payable 16 493 14 884
Payables to affiliated companies
(principally parent) 15 544 13 457
Salaries, wages, and vacation pay accrued 6 417 6 343
Taxes accrued 1 641 5 648
Interest accrued 4 459 5 300
Current deferred income taxes 1 670 1 963
Capital lease obligations and other 3 888 4 177
Total current liabilities 89 412 102 672
Other Liabilities
Accumulated deferred income taxes 100 898 100 227
Accumulated deferred investment tax credits 20 024 21 205
Regulatory liabilities 19 409 18 020
Customer advances 7 334 6 458
Benefit obligations and other 8 954 10 782
Total other liabilities 156 619 156 692
Commitments and Contingent Liabilities (see Note 8)
Total Liabilities and Equity $ 809 131 $ 790 898
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 (the Minnesota
Company), maintains the accounting records in accordance with
either the uniform system of accounts prescribed by the Federal
Energy Regulatory Commission (FERC) or those prescribed by the
Public Service Commission of Wisconsin (PSCW) and the Michigan
Public Service Commission (MPSC), which systems are the same in
all material respects.
Investment in Subsidiaries - The Company carries its
investment in its subsidiaries (Chippewa and Flambeau Improvement
Company, 75.86% owned; NSP Lands, Incorporated, 100% owned; and
Clearwater Investments, Incorporated, 100% owned) at cost plus
equity in earnings since acquisition. The impact of
consolidation of these subsidiaries is considered immaterial.
Related Party Transactions - The Company's financial
statements include intercompany transactions and balances related
to sales among the electric and gas utility businesses of the
Company, the Minnesota Company and Viking Gas Transmission
Company (a wholly-owned subsidiary of the Minnesota Company),
including intercompany profits which are allowed in utility
rates. See Note 6 for further discussion of intercompany
transactions with the Minnesota Company.
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 3.57
percent in 1996, 3.48 percent in 1995, and 3.45 percent in 1994.
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
5.70 percent in 1996, 6.20 percent in 1995, and 7.55 percent in
1994. The rates used for the PSCW calculation were 10.03 percent
in 1996, 10.13 percent in 1995, and 10.13 percent in 1994. 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 the Minnesota Company and files separate
state returns for Wisconsin and Michigan. The Company records
current and deferred income taxes at the statutory rates as if it
filed a separate return for Federal income tax purposes. State
income tax payments are made directly to the taxing authorities.
Federal income tax payments are made to the Internal Revenue
Service by the Minnesota Company 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 has 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 is recorded as an adjustment to interest expense
each period over the term of the agreement.
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 (based on historical experience).
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. Recent changes in interest rates have
resulted in changes to actuarial assumptions used in the benefit
cost calculations for postretirement benefits, as discussed in
Note 5.
Reclassifications - Certain reclassifications have been made
to the 1995 and 1994 financial statements to conform with the
1996 presentation. These reclassifications had no effect on net
income or earnings per share.
2. Long-term Debt
Dec. 31 Dec. 31
1996 1995
(Thousands of dollars)
Long-term debt includes the following issues:
First Mortgage Bonds (less reacquired
bonds of $3,365 at December 31, 1995):
Series due:
Oct. 1, 2003, 5 3/4% $ 40 000 $ 40 000
Apr. 1, 2021, 9 1/8% 44 635
Mar. 1, 2023, 7 1/4% 110 000 110 000
Dec. 1, 2026, 7 3/8% 65 000
Total First Mortgage Bonds 215 000 194 635
City of La Crosse Resource
Recovery Revenue Bonds -
Series due Nov. 1, 2011, 7 3/4% 18 600
Series due Nov. 1, 2021, 6 % 18 600
Total long-term debt $ 233 600 $ 213 235
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 October 1, 1993 permits an amount of
established permanent additions to be deemed equivalent to the
payment of cash necessary to redeem 1% of the highest principal
amount of each series of first mortgage bonds (other than
pollution control financing) at any time outstanding.
Interest Rate Swap Agreement - The Company has entered into
an interest rate swap agreement extending through March 1, 1998
for $20 million of the 7-1/4% series first mortgage bonds. This
agreement effectively converts the interest costs for $20 million
of this debt issue from fixed to variable rates based on six-
month London Interbank Offered Rates (LIBOR) with the rates
changing semi-annually, March 1 and September 1. The net
effective interest rate under the Swap agreement was 7.89% at
December 31, 1996.
Market risks associated with this agreement result from
short-term interest rate fluctuations. Credit risk related to
non-performance of the counterparties is not deemed significant,
but would result in NSP terminating the swap transaction and
recognizing a gain or loss, depending on the fair market value of
the swap. 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, 1996, $212,000 would have been payable by
the Company while the present value of the related fixed rate
debt issued with the swaps was $618,000 below carrying value.
Fair Value of Debt - The estimated fair value of the
Company's long term debt at December 31, 1996 and 1995 is $227.7
million and $230.6 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 $752,000, $441,000, $128,000,
$14,000, and $0, respectively, for the years 1997-2001.
3. Short-Term Borrowings
The Company had bank lines of credit aggregating $1,000,000
at December 31, 1996. 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 1996 and 1995 there were no bank loans outstanding
as the Company obtained short-term borrowings from the Minnesota
Company at the Minnesota Company's average daily interest rate,
including the cost of their compensating balance requirements.
The PSCW has authorized the Company's short-term commercial
paper borrowings up to $80.0 million. At December 31, 1996 and
1995, the Company had $39.3 million and $50.9 million,
respectively, in short-term commercial paper borrowings
outstanding. The weighted average interest rates on all short-
term borrowings as of December 31, 1996 and 1995, were 5.59
percent and 6.2 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%
to net income before income tax expense. The reasons for the
difference are as follows:
1996 1995 1994
(Thousands of dollars)
Tax computed at statutory rate $ 22 148 $ 22 140 $ 20 074
Increases (decreases) in tax from:
State income taxes, net of Federal
income tax benefit 2 921 3 314 2 393
Investment tax credits
recognized (910) (936) (943)
Adjustment to taxes accrued in
prior years 682 90 (2 430)
Other - net (259) (567) (283)
Total income tax expense $ 24 582 $ 24 041 $ 18 811
Effective income tax rate 38.9% 38.0% 32.8%
Income tax expense is comprised
of the following:
Included in Utility operating expenses:
Current Federal tax expense $ 18 293 $ 17 772 $ 8 075
Current state tax expense 3 838 4 546 2 810
Deferred Federal tax expense 2 790 2 679 7 967
Deferred state tax expense 677 601 1 168
Deferred investment tax credit
adjustments (910) (936) (943)
Total 24 688 24 662 19 077
Included in income deductions:
Current Federal tax expense 1 299 691 1 039
Current state tax expense 326 130 216
Deferred Federal tax expense (1 385) (1 264) (1 008)
Deferred state tax expense (346) (178) (513)
Total income tax expense $ 24 582 $ 24 041 $ 18 811
The components of the Company's net deferred tax liability at
Dec. 31 (including current and noncurrent amounts) were as
follows:
(Thousands of dollars) 1996 1995
Deferred tax liabilities:
Differences between book and tax bases
of property $ 103 771 $ 106 390
Tax benefit transfer leases 1 638 3 369
Regulatory assets 12 690 12 498
Other 3 782 4 337
Total deferred tax liabilities 121 881 126 594
Deferred tax assets:
Deferred investment tax credits 8 014 8 507
Regulatory liabilities 7 729 11 063
Deferred compensation, accrued
vacation and other reserves
not currently deductible 2 310 4 040
Other 1 260 794
Total deferred tax assets 19 313 24 404
Net deferred tax liability $ 102 568 $ 102 190
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 expired December 31, 1996, but was
extended to April 30, 1997. Management and union representatives
have reached a tentative agreement on the terms of a new
collective-bargaining agreement, subject to approval by the union
membership. The Company is not able to predict the outcome at
this time.
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:
1996 1995
Company Company
(Thousands of dollars) Total Plan Portion Total Plan Portion
Actuarial present value of
benefit obligation:
Vested $ 660 920 $ 84 924 $ 686 403 $ 87 877
Nonvested 147 278 16 332 155 177 17 901
Accumulated benefit obligation $ 808 198 $ 101 256 $ 841 580 $ 105 778
Projected benefit obligation $ 993 821 $ 120 886 $ 1 039 981 $ 127 287
Plan assets at fair value 1 634 696 196 089 1 456 530 145 963
Plan assets in excess of
projected benefit obligation 640 875 75 203 416 549 18 676
Unrecognized prior service cost 19 734 2 469 20 805 2 602
Unrecognized net gain (651 368) (77 174) (452 699) (23 842)
Unrecognized net transitional
asset (539) (67) (615) (77)
Net pension asset (liability)
recorded $ 8 702 $ 431 $ (15 960)$ (2 641)
Effective January 1, 1993, for financial reporting and regulatory
purposes, the Company's pension expense is 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:
1996 1995 1994
(Thousands of dollars)
Service cost - benefits earned
during the period $ 3 390 $ 2 844 $ 3 114
Interest cost on projected benefit
obligation 8 618 8 662 8 087
Actual return on allocated
share of plan assets (12 353) (10 994) (1 702)
Net amortization and deferral (2 727) (1 567) (10 130)
Net periodic pension cost determined
under SFAS No. 87 (3 072) (1 055) (631)
Expenses recognized due to actions
of regulators 90 90 90
Net periodic pension cost (credit)
recognized for ratemaking $ (2 982) $ (965) $ (541)
The weighted average discount rate used in determining the
actuarial present value of the projected obligation was 7.5% in
1996 and 7% in 1995. The rate of increase in future compensation
levels used in determining the actuarial present value of the
projected obligation was 5% in 1996 and 1995. The assumed long-
term rate of return on assets used for cost determinations under
SFAS No. 87 was 9% in 1996 and 1995, and 8% in 1994. Assumption
changes increased 1996 pension costs by approximately $1.4
million and decreased 1995 pension costs by approximately $2.5
million. Assumption changes are expected to decrease 1997
pension costs by approximately $0.8 million.
Postretirement Health Care - The Company participates in the
Minnesota Company'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 January 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, 1996, 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.
1996 1995
Company Company
(Thousands of dollars) Total Plan Portion Total Plan Portion
APBO:
Retirees $144 180 $ 22 166 $ 145,763 $ 22 709
Fully eligible plan
participants 23 438 3 447 24 406 3 235
Other active plan
participants 101 065 12 065 116 810 14 872
Total APBO 268 683 37 678 286 979 40 816
Plan Assets at Fair Value 15 514 8 285 11 583 5 608
APBO in excess of plan assets 253 169 29 393 275 396 35 208
Unrecognized net actuarial
gain (loss) (12 467) (2 057) (40 411) (7 925)
Unrecognized transition
obligation (172 480) (23 586) (183 260) (25 060)
Postretirement benefit liablity
recorded $ 68 222 $ 3 750 $ 51 725 $ 2 223
The assumed health care cost trend rate used in measuring
the APBO at December 31, 1996 and 1995, respectively, were 9.8
and 10.4 percent for those under age 65 and 7.1 and 7.3 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 1 percent increase in the assumed health care cost
trend rate for each year would increase the APBO as of December
31, 1996, by approximately 14 percent and service and interest
cost components of the net periodic postretirement cost by
approximately 17 percent. The assumed discount rate used in
determining the APBO was 7.5 percent for December 31, 1996 and 7
percent for December 31, 1995, compounded annually. The assumed
long-term rate of return on assets used for cost determinations
under SFAS No. 106 was 8 percent for 1996, 1995, and 1994.
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):
1996 1995 1994
Service cost-benefits earned during
the year $ 804 $ 686 $ 644
Interest cost (on service cost
and APBO) 2 700 2 761 2 251
Amortization of transition
obligation 1 474 1 474 1 474
Return on assets and other (632) (301) (182)
Net amortization and deferral 221
Net periodic postretirement
health care costs $ 4 567 $ 4 620 $ 4 187
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 the Minnesota Company'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 both 1996 and 1995 and $0.3 million in 1994.
6. Parent Company and Intercompany Agreements
The Company is wholly-owned by the Minnesota Company. The
electric production and transmission costs of the NSP system are
shared by the Company and the Minnesota Company. A FERC approved
agreement (Interchange Agreement) between the Company and the
Minnesota Company provides for the sharing of all costs of
electric generation and transmission facilities of the NSP
System, including capital costs. Billings under the Interchange
Agreement and an intercompany gas agreement which are included in
the statement of income are as follows:
Year Ended December 31
1996 1995 1994
(Thousands of dollars)
Operating revenues:
Electric $69 337 $70 251 $73 503
Gas $39 $43 $50
Operating expenses:
Purchased and interchange power $173 492 $173 743 $174 144
Gas purchased for resale $216 $205 $227
Other operation $13 685 $13 791 $12 824
7. Regulatory Assets and Liabilities
The following summarizes the individual components of
unamortized regulatory assets and liabilities shown on the
Balance Sheet at Dec. 31:
(Thousands of dollars) Amortization Period 1996 1995
AFC recorded in plant on
a net-of-tax basis Plant Lives* $ 9 928 $ 9 918
Losses on reacquired debt Term of New Debt 13 341 9 749
Conservation and energy
management programs Up to 9 years* 10 604 12 347
Environmental costs To be determined 1 405 1 284
Unrecovered purchased gas costs 1 year 722
Pensions and other Mainly 11 years 1 102 1 406
Total Regulatory Assets $ 37 102 $ 34 704
Excess deferred income taxes
collected from customers $ 3 420 $ 1 449
Investment tax credit deferrals 13 412 14 237
Fuel refunds and other 2 577 2 334
Total Regulatory Liabilities $ 19 409 $ 18 020
* Earns a return on investment in the ratemaking process.
8. Commitments and Contingent Liabilities
Commitments - The Company presently estimates capital
expenditures will be $58 million in 1997 and $359 million for
1997-2001.
Rentals under operating leases were approximately
$1,704,000, $1,644,000, and $1,792,000 for 1996, 1995, and 1994,
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 1997 and 2011, require minimum
contractual purchases and deliveries of fuel. In total, the
Company is committed to the minimum purchase of approximately
$156 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 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 fuel available
and suppliers are expected to continue to provide reliable fuel
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 fuel is mitigated through the cost-of-energy
adjustment provision of the ratemaking process, which provides
for recovery of nearly all fuel costs.
Nuclear Contingencies - Although the Company does not own a
nuclear facility, any assessment made against the Minnesota
Company and under the Price-Anderson liability provisions of the
Atomic Energy Act of 1954, would be a cost included under the
Interchange Agreement (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. The Minnesota Company has secured
insurance of $200 million to satisfy such claims. The remaining
$8.7 billion of exposure is funded by the Secondary Financial
Protection Program, available from assessments by the federal
government in case of a nuclear accident. The Minnesota Company
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. Two sites
are solid and hazardous waste landfill sites in Eau Claire and
Amery, Wisconsin. The Company contends that it did not
contribute waste consistent with the contaminants of concern in
these landfills. 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 third site is a landfill in
Hudson, Wisconsin. Payment amounts for the cleanup of this site
will be decided in early 1997 and are not expected to exceed
$5,000. The fourth site, in Ashland, Wisconsin, contains
creosote/coal tar contamination.
In 1995, the Wisconsin Department of Natural Resources
(WDNR) notified the Company that it is a potentially responsible
party (PRP) at the Ashland site. At this time, the WDNR has determined
that the Company is the only PRP at this 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 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 is not determinable. As
of December 31, 1996, 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
1996 were $525,000. The PSCW authorized recovery of $353,000
over a two year period beginning in 1997, which represents
recovery of actual expenditures through 1995. Based on this PSCW
decision to allow recovery of remediation costs incurred, the Company
has recorded a regulatory asset for the estimated accrued and actual
incurred expenditures related to the Ashland site. 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.
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
1996 1995 1994
(Thousands of dollars)
Operating income before income taxes:
Electric $ 69 730 $ 72 595 $ 67 453
Gas 11 564 8 243 6 498
Total operating income before
income taxes $ 81 294 $ 80 838 $ 73 951
Depreciation and amortization:
Electric $ 30 857 $ 28 752 $ 26 874
Gas 4 874 4 345 3 900
Total depreciation and
amortization $ 35 731 $ 33 097 $ 30 774
Construction expenditures:
Electric $ 42 519 $ 42 843 $ 42 756
Gas 6 884 8 330 9 883
Total construction expenditures $ 49 403 $ 51 173 $ 52 639
Identifiable assets:
Electric utility $661 585 $654 130 $634 848
Gas utility 91 557 86 021 81 244
Total identifiable assets 753 142 740 151 716 092
Other corporate assets 55 989 50 747 52 208
Total assets $809 131 $790 898 $768 300
10. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended
Mar. 31, Jun. 30, Sep. 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
Quarter Ended
Mar. 31, Jun. 30, Sep. 30, Dec. 31,
1995 1995 1995 1995
(Thousands of dollars)
Operating revenues $ 127 994 $ 102 323 $ 105 083 $ 123 698
Operating income $ 19 649 $ 9 307 $ 10 075 $ 17 145
Net income $ 15 160 $ 4 261 $ 6 047 $ 13 749
11. Merger Agreement with Wisconsin Energy Corporation
As previously reported in the Company's Current Report on
Form 8-K, dated May 8, 1995, and Quarterly Reports on Form 10-Q,
the Minnesota Company and Wisconsin Energy Corporation (WEC) have
entered into an Agreement and Plan of Merger (Merger Agreement),
which provides for a strategic business combination involving the
Minnesota Company and WEC in a "merger-of-equals" transaction
(the Transaction).
Primergy Corporation (Primergy), which will be registered
under the Public Utility Holding Company Act of 1935, as amended,
will be the parent company of both the Minnesota Company (which,
for regulatory reasons, will reincorporate in Wisconsin) and
WEC's current principal utility subsidiary, Wisconsin Electric
Power Company, which will be renamed "Wisconsin Energy Company."
It is anticipated that, following the Transaction, except for
certain gas distribution properties transferred to the Minnesota
Company, the Company will be merged into Wisconsin Energy Company
and that some or all of the Company's subsidiaries will be
divested to Primergy or another of its subsidiaries.
As noted above, pursuant to the Transaction, NSP will
reincorporate in Wisconsin. This reincorporation will be
accomplished by the merger of the Minnesota Company into a new
company, Northern Power Wisconsin Corporation (New NSP), with New
NSP being the surviving corporation and succeeding to the
business of the Minnesota Company as an operating public utility.
Following such merger, a new WEC subsidiary, WEC Sub Corporation
(WEC Sub), will be merged with and into New NSP, with New NSP
being the surviving corporation and becoming a subsidiary of
Primergy. Both New NSP and WEC Sub were created to effect the
Transaction and will not have any significant operations, assets
or liabilities prior to such mergers. After the Transaction is
completed, the Company will be dissolved and no common stock will
be outstanding. Current bondholders of the Company will become
investors in Wisconsin Energy Company.
PRO FORMA FINANCIAL INFORMATION (UNAUDITED)
Exhibits 99.03 and 99.04 include unaudited pro forma
financial information which reflects the adjustment of the
historical consolidated balance sheets and statements of income
of NSP, the Company and WEC to give effect to the Transaction to
form Primergy and a new subsidiary structure. The unaudited pro
forma balance sheet information gives effect to the Transaction
as if it had occurred on December 31, 1996. The unaudited pro
forma income statements give effect to the Transaction as if it
had occurred on January 1, 1994. This pro forma information was
prepared from the historical consolidated financial statements of
NSP, the Company and WEC on the basis of accounting for the
Transaction as a pooling of interests and should be read in
conjunction with such historical consolidated financial
statements and related notes thereto of the Minnesota Company,
the Company and WEC. The pro forma information is not
necessarily indicative of the financial position or operating
results that would have occurred had the Transaction been
consummated on the dates for which the Transaction is being given
effect, nor is it necessarily indicative of future operating
results or financial position of Primergy or Wisconsin Energy
Company.
The Primergy pro forma financial information in Exhibit
99.03 reflects the combination of the historical financial
statements of NSP and WEC after giving effect to the Transaction
to form Primergy. The Wisconsin Energy Company pro forma
financial information in Exhibit 99.04 reflects the adjustment of
the historical financial statements of the Company to give effect
to the Transaction, including the merger of the Company into
Wisconsin Energy Company and the transfer of ownership of all of
the other current Company subsidiaries to Primergy or another of
its subsidiaries. The transfer of certain Company gas
distribution properties to New NSP, which is anticipated as part
of the merger, has also been reflected in the pro forma amounts
in Exhibit 99.04.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
During 1996 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 J
(1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners
and Management
Item 13. Certain Relationships and Related Transactions
PART IV
Item 14. Exhibits, Financial Statement Schedules Page
and Reports on Form 8-K
(a) 1. Financial Statements
Included in Part II of this report:
Report of Independent Accountants for
the years ended December 31, 1996 and 1995. 25
Independent Auditors' Report for the
year ended December 31, 1994. 26
Statements of Income and Retained
Earnings for the three years ended
December 31, 1996. 27
Statements of Cash Flows for the three
years ended December 31, 1996. 28
Balance Sheets, December 31, 1996 and 1995. 29
Notes to Financial Statements. 31
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
2.01* Amended and Restated Agreement and Plan of
Merger, dated as of April 28, 1995, as amended and
restated as of July 26,1995, by and among
Northern States Power Company, Wisconsin Energy
Corporation, Northern Power Wisconsin Corp. and WEC
Sub. Corp. (Exhibit (2)-1 to Northern Power
Wisconsin Corporation's Registration
Statement on Form S-4 filed on August 7, 1995,
File No. 33-61619-01).
2.02* WEC Stock Option Agreement, dated as of April
28, 1995, by and among Northern States Power
Company and Wisconsin Energy Corporation (Exhibit (2)-
2 to Form 8-K dated April 28, 1995, File No. 1-
3034).
2.03* NSP Stock Option Agreement, dated as of April
28, 1995, by and among Wisconsin Energy
Corporation and Northern States Power Company
(Exhibit (2)-3 to Form 8-K dated April 28, 1995,
File No. 1-3034).
3.01* Restated Articles of Incorporation as of
December 23, 1987.
(Filed as Exhibit 30.01 to Form 10-K Report 10-
3140 for the year 1987)
3.02* Copy of the By-Laws of the Company as amended
August 19, 1992.
(Filed as Exhibit 3.02 to Form 10-K Report
10-3140 for the year 1992)
4.01* Copy of Trust Indenture, dated April 1, 1947,
From the Company to First Wisconsin Trust Company.
(Filed as Exhibit 7.01 to Registration Statement
2-6982)
4.02* Copy of Supplemental Trust Indenture, dated
March 1, 1949.
(Filed as Exhibit 7.02 to Registration Statement 2-7825)
4.03* Copy of Supplemental Trust Indenture, dated
June 1, 1957.
(Filed as Exhibit 2.13 to Registration
Statement 2-13463)
4.04* Copy of Supplemental Trust Indenture, dated
August 1, 1964.
(Filed as Exhibit 4.20 to Registration Statement
2-23726)
4.05* Copy of Supplemental Trust Indenture, dated
December 1, 1969.
(Filed as Exhibit 2.03E to Registration
Statement 2-36693)
4.06* Copy of Supplemental Trust Indenture, dated
September 1, 1973.
(Filed as Exhibit 2.01F to Registration
Statement 2-48805)
4.07* Copy of Supplemental Trust Indenture, dated
February 1, 1982.
(Filed as Exhibit 4.01G to Registration
Statement 2-76146)
4.08* Copy of Supplemental Trust Indenture, dated
March 1, 1982.
(Filed as Exhibit 4.08 to form 10-K Report
10-3140 for the year 1982)
4.09* Copy of Supplemental Trust Indenture, dated
June 1, 1986.
(Filed as Exhibit 4.09 to Form 10-K Report 10-3140
for the year 1986)
4.10* Copy of Supplemental Trust Indenture, dated
March 1, 1988.
(Filed as Exhibit 4.10 to Form 10-K Report 10-3140
for the year 1988)
4.11* Copy of Supplemental and Restated Trust Indenture,
dated March 1, 1991.
(Filed as Exhibit 4.01K to Registration Statement
33-39831)
4.12* Copy of Supplemental Trust Indenture, dated
April 1, 1991.
(Filed as Exhibit 4.01 to Form 10-Q Report 10-3140
for the quarter ended March 31, 1991)
4.13* Copy of Supplemental Trust Indenture, dated
March 1, 1993.
(Filed as Exhibit to Form 8-K Report dated March
3, 1993)
4.14* Copy of Supplemental Trust Indenture, dated
October 1, 1993.
(Filed as Exhibit 4.01 to Form 8-K Report dated
September 21, 1993)
4.15* Copy of Supplemental Trust Indenture, dated
December 1, 1996.
(Filed as Exhibit 4.01 to Form 8-K Report
dated December 12, 1996)
10.01* Copy of Interchange Agreement dated September
17, 1984, and Settlement Agreement dated May 31, 1985,
between the Company, the Minnesota Company and LSDP.
(Filed as Exhibit 10.10 to Form 10-K Report 10-3140
for the year 1985)
27.01 Financial Data Schedule
99.01 Statement pursuant to Private Securities
Litigation Reform Act of 1995.
99.02* Press Release, dated May 1, 1995, of NSP
(Exhibit (99)-01 to Form 8-K dated April 28,
1995, File No. 1-3034).
99.03 Unaudited Pro Forma Combined Condensed
Balance Sheets for the year ended December 31,
1996 and unaudited Pro Forma Combined Condensed
Statements of Income for the years ended December
31, 1994, 1995 and 1996 for Primergy Corporation.
99.04 Unaudited Pro Forma Combined Condensed Balance Sheets
for the year ended December 31, 1996 and unaudited
Pro Forma Combined Condensed Statements of Income
for the years ended December 31, 1994, 1995 and 1996
for Wisconsin Energy Company.
99.05* Audited Financial Statements of Wisconsin Energy
Corporation. (Item 8 of Wisconsin Energy Corporation's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1996, File No. 1-9057).
99.06* Audited Financial Statements of Northern States
Power Company. (Item 8 of Northern States
Power Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1996, File No.
1-3034).
99.07* Audited Financial Statements of Wisconsin
Electric Power Company. (Item 8 of Wisconsin
Electric Power Company's Annual Report on
Form 10-K for the fiscal year ended December 31,
1996, File No. 1-1245).
(b) Reports on Form 8-K - The following report on Form 8-K was
filed either during the three months ended December 31, 1996,
or between December 31, 1996 and the date of this report.
December 12, 1996 (Filed December 16, 1996) - Items 5 and 7.
Other Events and Financial Statements and Exhibits.
Disclosure of the Company entering into an Underwriting
Agreement and filed with the Securities and Exchange commission
a prospectus supplement and final prospectus relating to
$65,000,000 in aggregate principal amount of the Company's First
Mortgage Bonds, Series due December 1, 2026.
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this annual report to be signed on its behalf by the undersigned,
thereunto authorized.
NORTHERN STATES POWER COMPANY
/s/
John A. Noer
President and Chief Executive
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report signed below by the following persons on
behalf of the registrant and in the capacities and on the date
indicated.
/s/
John A. Noer
(Principal Executive Officer)
/s/ /s/
M. N. Gregerson H. Lyman Bretting
Vice President-Customer Services Director
/s/ /s/
A. G. Schuster P. M. Gelatt
Vice President Director
Power Delivery and Generation
/s/ /s/
Patrick D. Watkins Wayne E. Harrison
Vice President-Corporate Services Director
/s/ /s/
John P. Moore, Jr. Loren L. Taylor
General Counsel and Secretary Director
/s/ /s/
Roger D. Sandeen Ray A. Larson, Jr.
Controller Director
(Principal Accounting Officer)
/s/ /s/
Neal A. Siikarla Larry G. Schnack
Treasurer Director
(Principal Financial Officer)
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
DT 27.01 Financial Data Schedule
DT 99.01 Statement pursuant to Private Securities
Litigation Reform Act of 1995.
DT 99.03 Unaudited Pro Forma Combined Condensed
Balance Sheets for Primergy Corporate at
Dec. 31, 1996 and Unaudited Pro Forma
Combined Condensed Statements of Income
for the three years ended Dec. 31, 1996.
DT 99.04 Unaudited Pro Forma Condensed Balance Sheet
for Wisconsin Energy Company at Dec. 31,
1996 and Unaudited Pro Forma Condensed
Statements of Income for the three years
ended Dec. 31, 1996.