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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 202,000 retail customers in an
area of approximately 18,900 square miles in northwestern Wisconsin, to
approximately 9,200 electric retail customers in an area of approximately
300 square miles in the western portion of the Upper Peninsula of Michigan,
and to 10 wholesale customers in the same general area. The Company is
also engaged in the distribution and sale of natural gas in the same
service territory to approximately 71,000 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 1995, the Company derived 83 percent of its total operating
revenues from electric utility operations and 17 percent from gas utility
operations. As of December 31, 1995, the Company had 896 full-time
equivalent employees including 801 full-time employees.
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION
Description of the 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 corpo
ration (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 strategic business
combination involving the Minnesota Company and WEC in a "merger-of-equals"
transaction (the Merger Transaction). The Merger Transaction, which was ap
proved by the respective Boards of Directors and shareholders of the
constituent companies, is expected to close shortly after all of the
conditions to the consummation of the Merger Transaction, including
obtaining applicable regulatory approvals, are met or waived. The goal of
the Minnesota Company and WEC is to receive approvals from all regulatory
authorities by the end of 1996, however, some regulatory authorities have
not established a timetable for their decisions. Therefore, timing of the
receipt of the approvals necessary to complete the Merger Transaction is
not known at this time. See discussion of the regulatory proceedings under
the caption "Utility 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, the holding company of the combined
enterprise will be registered under the Public Utility Holding Company Act
of 1935, as amended. The holding company will be named Primergy Corpo
ration ("Primergy") and will be the parent company of both the Minnesota
Company (which, for regulatory reasons, will reincorporate in Wisconsin)
and of WEC's principal utility subsidiary, Wisconsin Electric Power Company
("WEPCO"), which will be renamed "Wisconsin Energy Company." Wisconsin
Energy Company will include the operations of WEC's other current utility
subsidiary, Wisconsin Natural Gas Company, which was merged into WEPCO
effective Jan. 1, 1996. It is anticipated that, following the Transaction,
except for certain gas distribution properties serving the cities of La
Crosse and Hudson, Wisconsin transferred to the Minnesota Company, the
Company will be merged into Wisconsin Energy Company.
The Merger Agreement 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 (defined below) 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 will 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 des
ignations. Following the merger of the Company into Wisconsin Energy
Company, the Company' 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.
Merger Consummation Conditions
The Transaction is subject to customary closing conditions, including,
without limitation, the receipt of all necessary governmental approvals 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 "Utility 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 WEC and the Minnesota Company 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 it is expected that the Minnesota Company and WEC will make
the following filings as part of the regulatory approval process of the merger:
-Notification under the Hart-Scott-Rodino Antitrust Act of 1976, as
amended, is expected to be filed in the second quarter of 1996 with the
Department of Justice and Federal Trade Commission.
-An Application will be filed for SEC approval of the registration of
Primergy under the Public Utility Holding Company Act of 1935,
as amended, including a decision on possible divestiture of the existing
gas operations and certain non-regulated businesses.
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.
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 Oct. 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 satisfied by 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 contained 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 Agree
ment 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
A preliminary estimate indicates that the Merger Transaction will
result in net savings for the constituent companies of approximately $2.0
billion in costs over 10 years. It is anticipated that the synergies
created by the Merger Transaction 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 rate reduction
of 1.5 percent and a four-year rate freeze in the retail electric
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 will be 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.
The Minnesota Company has proposed a two-year freeze for retail
natural gas rates in its Minnesota jurisdiction. In addition, 38 percent
of the Minnesota Companys net gas savings available in 1997 are forecasted
to be in the purchased cost of gas and would be reflected in customer rates
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 in that time period.
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 Wisconsin Energy Company 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, Wisconsin Energy Company 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 they believe 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 Wisconsin Energy Company be allowed to file with the
PSCW during the rate freeze period for recovery of the costs related to
these events.
Both 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.
REGULATION AND RATES
Utility Industry Restructuring in Wisconsin
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.
To date, after reviewing a set of proposals developed by its working group,
the PSCW has set a target date of 2000 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. The PSCW is also examining
similar issues for the gas industry.
Construction Authorization in Wisconsin
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 from $1,000,000 to $3,000,000. Any projects costing less than
$3,000,000, or 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 Michigan Public Service Commission ("MPSC") regulate the
rates and service of the Company with respect to retail sales within the
State of Wisconsin and the State of Michigan, respectively, 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
91.8 percent of the Company's 1995 revenues from sales were subject to PSCW
jurisdiction. Of the 91.8 percent, 73 percent was generated from electric
retail revenues and the remaining 18.8 percent from retail gas revenues.
The Company's wholesale revenues from sales subject to FERC jurisdiction
were approximately 4.6 percent of the Company's 1995 revenues from sales
with the remaining 3.6 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 dated March 11, 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
certain demand costs for sales and purchased power, which had been excluded
prior to that date.
The Company's retail gas rate schedules include a purchased gas
adjustment clause which provides for inclusion of the current cost of gas
including its transportation. The factors applied under the purchased gas
adjustment clause are adjusted on an ongoing basis to reflect a
reconciliation of gas costs incurred and recovered.
The PSCW scheduled a generic hearing in March 1996 to consider
alternative incentive-based gas cost recovery adjustment mechanisms to
replace the current purchased gas adjustment clause. The incentive-based
mechanism, as proposed by the Company would allow recovery of fluctuations
in gas costs based on an index, such as the spot market price. A PSCW
decision is pending.
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.
Wholesale
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 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 issued a letter requesting the Company to decrease electric rates by
$4.8 million (1.7%). The Company accepted the PSCW proposal in a letter
dated November 2, 1995. On December 21, 1995, the PSCW issued an order
approving a $2.5 million gas rate increase (3.4% on an annual basis). 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. The Company expects its next general rate case filing to be in June
1997, for rates effective in 1998, as required by the PSCW biennial filing
requirements if the Transaction has not been completed prior to that time.
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 $0.2 million relates to the Company) at the time of the
Merger Transaction and four-year rate freeze thereafter, with certain
exceptions. The Company and WEPCO filed full stand alone rate cases on
March 15, 1996, based on a 1997 year. Technical hearings on the stand
alone rate cases are expected in July 1996. Testimony and exhibits
supporting the Merger Transaction and rate plan were filed before the PSCW
on March 18, 1996. The PSCW's decision on the merger approval filing is
expected in the fourth quarter of 1996.
Michigan
There were no changes in the Michigan electric or gas base rates
during 1995.
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's decision
on the Merger Transaction approval filing is expected in the first half of
1996.
Wholesale (FERC)
The Company had 10 wholesale customers at December 31, 1995, with
revenues of approximately $18.0 million. In 1995, the Wisconsin Company
offered its wholesale customers a discount of from three to five percent
from the FERC authorized rate. Seven of the ten municipal customers
elected to either renew or extend their contracts to receive these
discounts. As part of the settlement agreement between the Primergy
partners and the Wisconsin Intervenors, the cities of Medford and Rice Lake
have a 5 year power supply agreement. For the first year the two cities
receive at discounted full requirements service, for the remaining four
years, they receive service at a negotiated, fixed rate. Upon completion
of the term, NSP will have no further obligation to service these two
customers. The other customer did not elect to sign a new contract, but
continues with its existing contract. Due to these changes, 1996 revenues
are estimated to decrease from 1995 revenues by approximately $0.6 million.
Electric Transmission Tariffs and Settlement (FERC)
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.
The Company's portion of refunds due were not material at December 31,
1995.
In March 1994, the Minnesota Company and the Company jointly filed a
revised open access transmission tariff with the FERC. On May 25, 1994,
the FERC accepted the filing with the new rates effective November 1, 1994,
subject to refund. The FERC also ruled the tariff would be subject to the
requirement that the Company and the Minnesota Company offer transmission
service using terms and conditions comparable to their own use of the
system. 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. On May 25, 1995, the Administrative Law
Judge (ALJ) issued to the FERC a Certification of Contested Offer of
Settlement. Although there are no genuine issues of material fact and all
parties support certification of the Settlement, the ALJ stated the
Settlement was contested since FERC Staff and Electric Clearinghouse listed
numerous provisions that needed to be modified in response to the issuance
of a proposed rulemaking referred to as the Mega NOPR. (See discussion and
definition of Mega-NOPR below.) The ALJ further stated the Settlement was
not affected by the issuance of the Mega-NOPR, even though the FERC in the
Mega-NOPR stated that any settlement approved prior to the issuance of the
final rule will be made subject to the outcome of the final rule. The FERC
approved the Settlement on February 14, 1996, subject to the outcome of the
final rule. The revenue effect on the Company and the Minnesota Company is
expected to be an increase 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.
Open Access Transmission Proceedings (FERC)
In March 1995, the FERC issued two pronouncements which are expected
to have a major impact on the electric industry: Notice of Proposed
Rulemaking on Open Access Non-Discriminatory Transmission Services and a
Supplemental Notice of Proposed Rulemaking on Stranded Investment (together
called the Mega-NOPR); and a proposal to require Real-Time Information
Networks (RIN).
The stated purpose for the Mega-NOPR is to create a vigorous wholesale
electric market by requiring transmission providers to offer open access to
their transmission systems. FERC seeks to accomplish this by requiring
utilities to unbundle power sales from transmission--but only for new
requirements contracts and new coordination trade contracts. FERC did not
require utilities to divest or separate their generation businesses from
their transmission businesses. FERC also proposes to not disrupt any
existing power or transmission contracts.
The Mega-NOPR would apply to all utilities under FERC's jurisdiction
and would require each utility to file individual tariffs. FERC also seeks
to require non-jurisdictional transmission-owning entities (such as
municipals and cooperatives) to offer open access by including a
reciprocity clause in utilities' individual tariffs, so that those who take
service from a FERC jurisdictional utility must offer the open access. The
rule will be implemented in two stages. In the first stage, generic pro
forma tariffs rates would take effect under financial data filed with FERC
on Form 1. In the second stage, utilities and their customers could file
to modify the tariffs and rates within the limits of non-discriminatory
open access. A Procedural Order which was concurrently issued with the
Mega-NOPR grandfathers the pending joint transmission tariff of the Company
and the Minnesota Company into the second stage.
The rules proposed in the Mega-NOPR would require transmission
providers to offer network, point-to-point and ancillary services.
Ancillary services would include scheduling and dispatching, load
following, imbalance resolution, reactive power support and system
protection.
In the Mega-NOPR, FERC further clarified its guidelines for utilities
to recover stranded investment costs due to facilitation of open access to
a competitive market. FERC stated that it recognized the vital link
between the prior stranded cost proposal issued in 1994 and the open access
initiative. In the Mega-NOPR, FERC has proposed a backstop position,
whereby it will only entertain stranded cost filings when a state
regulatory commission does not have authority under state law to address
stranded costs at the time retail wheeling (which is the transmission to
retail customers of power generated by a third party, in competition with
supplies from the host utility) takes place. The Mega-NOPR also provides
that FERC will entertain utilities' requests for stranded-cost recovery
even after a state has addressed the issue. However, if a state commission
has authority to act, but does not do so, a utility may not seek recovery
from the FERC.
With regard to the RIN proposal, FERC is considering requiring that
each public utility create an electronic bulletin board to ensure that
potential purchasers of transmission services have access to information to
enable them to obtain open access transmission services on a non-
discriminatory basis from the public utility. The proposed RIN would
include a wide range of information such as: availability of transmission
services (including ancillary services); rates; hourly transfer capacities;
hourly amounts scheduled; transmission and unit outages; load flow data;
and transaction specific information on all requests for transmission
service, including requests by transmission owner's wholesale power
marketing department.
In their joint response to the RIN and Mega-NOPR proposals, the
Minnesota Company and the Company filed comments which indicated support
for FERCs open access objective and for FERCs position that it should be
a backstop for the recovery of stranded costs.
Proposed Transaction Approval Proceedings (FERC)
On July 10, 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, a proposed joint
transmission tariff, and an amendment to the Company's Interchange
Agreement with the Minnesota Company. On September 11, 1995, several
parties filed interventions and protests. On October 10, 1995, the
Applicants replied to the petitions for intervention and requests for
hearing. On or about October 25, 1995, intervenors filed responses to the
Applicants reply. On November 9, 1995, the Applicants filed a response to
the intervenors reply comments. Additional intervenor comments were filed
on November 22, 1995.
The issues raised by the intervenors with respect to the merger
application at FERC are primarily related to two areas: the impact on
competition and the nature of the cost savings. The intervenors argue
competition will be adversely affected because NSP and WEPCO will constrain
the transmission system at the interconnections between NSP and a group of
Wisconsin and upper Michigan utilities, allowing NSP and WEPCO to increase
the amount they charge for energy. In response to these intervenor
concerns the Applicants:
have committed to make whatever changes are required in their
transmission tariff by FERC in its Mega-NOPR proceedings to ensure access
is achieved.
have filed to expand the capacity of the interconnections and further
expansion is being pursued.
have committed that if the interface is constrained, any economy
energy sales that NSP and WEPCO make to the Wisconsin and upper Michigan
utilities will be at incremental cost.
will waive their AES (native load) and Mid-Continent Area Power Pool
(MAPP) line loading relief procedures priorities for internal and economy
transactions through the interface.
To the extent that a regional transmission operator has not been
established by the time of the merger, are willing to establish an
unaffiliated entity as an Independent Tariff Administrator that will
schedule transmission use and otherwise ensure that transmission service is
provided on a nondiscriminatory basis. See discussion of the negotiations
to convert MAPP to a Regional Transmission Group at the Electric
Operations - Capability and Demand section herein.
On January 31, 1996, the FERC issued an order which put the merger
approval filing on an accelerated schedule. The FERC set only one issue
hearing. The FERC ordered a hearing regarding the effect of the proposed
merger on bulk power competition. The order requires the initial decision
to be issued by August 30, 1996, and briefs on exception to be filed by
September 30, 1996. In March 1996, the PSCW requested that the FERC
broaden the scope of the merger hearing to evaluate whether the proposed
merger will impair effective state oversight of retail rates. The FERC has
not acted upon the PSCW's request. While the Company expects the FERC's
decision on the merger in the fourth quarter of 1996, the approval process
may extend beyond 1996. The FERC also set for hearing the Transmission
Tariff filing (Docket ER95-1358-000) and the Interchange Agreement filing
(Docket ER95-1357-000).
The Applicants have settled with several intervenors and are
continuing to meet with interested parties in the FERC proceeding, seeking
resolution of the intervenor issues.
ELECTRIC OPERATIONS
Competition
The Company's electric sales are subject to competition in some areas
from municipally owned systems, rural 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 (1935 Act) and the Federal Power Act. Among many other
provisions, the Energy Act is designed to promote competition in the
development of wholesale power generation in the electric utility industry.
It exempts a new class of independent power producers from regulation under
the 1935 Act. The Energy Act also allows the FERC to order wholesale
wheeling by public utilities to provide utility and non-utility
generators access to public utility transmission facilities. The provision
allows the FERC to set prices for wheeling, which will allow utilities to
recover certain costs. The costs would be recovered from the companies
receiving the services, rather than the utilities retail customers. The
market-based power agreement filings with FERC and the Mega-NOPR issued by
FERC (as discussed in "Regulation and Rates", herein) reflect the trend
toward increasing transmission access under the Energy Act. The FERC Mega-
NOPR seeks to standardize the terms, conditions and rate development
approaches to ensure fundamental principles underlie open access tariffs.
The Company shares the FERC view that such tariffs are a necessary step to
support functional unbundling of generation and transmission and the
evolution of a competitive electric power market place. The final rules
FERC will issue as a result of the Mega-NOPR are expected to be aligned
with the pro-forma tariff. The use of pro-forma tariffs in merger filings
enables FERC to separate and exclude open access transmission from other
issues in the Primergy merger docket. This treatment was requested in the
Primergy merger filing that included the pro-forma tariff. The Energy
Act's ultimate impact on the Company cannot be predicted at this time.
Many states are currently considering retail competition. Regulators
in Wisconsin are currently considering what actions they should take
regarding electric industry competition. 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.
Competition should be phased in for retail markets by customer classes,
with all customers having choice of supplier by 2001. The generation
segment of the industry should be deregulated by 2001. Prudent stranded
costs should be recovered prior to the advent of retail wheeling. Finally,
utilities and other competitors should have a level playing field for
issues such as obligation to serve, eminent domain, requirements for demand
side management, funding of social programs, opening of retail markets to
competition and other issues. Also, as an outcome of the responses to the
PSCW, a task force was formed by the PSCW to analyze the industry
restructuring necessary in the state of Wisconsin. In 1995, the PSCW voted
to adopt an electric utility restructuring plan which includes a 32-step
phase-in of retail wheeling by the year 2001. A key component of the plan
is to provide the protections necessary to ensure that consumers are not
harmed in an increasingly competitive environment. One component of the
plan is to have an independent system operator to control transmission
access. The Company believes the transition to a more competitive electric
industry is inevitable and beneficial for all consumers. The Company
supports both regulators goals to facilitate an orderly and efficient
transition to an open, fair and competitive energy market for all customers
and suppliers.
Michigan also has a retail wheeling experiment, limited to its two
largest utilities and customers larger than $50 million, currently
underway. The Company's customers are not included in this experiment
which is currently being challenged in court. A report on further
restructuring has been issued by the Governor of Michigan, known as the
Rothwell Report, and the MPSC is moving forward under guidelines set
forth in this report.
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 NSP System added the Angus Anson 232 MW gas-fired combustion
turbines generation facility, located in Sioux Falls, South Dakota in
September 1994. Also in 1994, the Minnesota Company signed a long-term
power purchase contract with LSP-Cottage Grove for 245 MW of annual
capacity for thirty years scheduled for an in service date of 1997.
The Minnesota Company operates two nuclear generating plants: the
single unit, 539 Mw Monticello Nuclear Generating Plant and the Prairie
Island Nuclear Generating Plant with two units totaling 1,025 Mw. The
Monticello Plant received its 40-year operating license from the NRC on
Sept. 8, 1970, and commenced operation on June 30, 1971. Prairie Island
Units 1 and 2 received their 40-year operating licenses on Aug. 9, 1973,
and Oct. 29, 1974, respectively, and commenced operation on Dec. 16, 1973,
and Dec. 21, 1974, respectively. The ability of these nuclear plants to
continue operating until the end of the license periods is dependent upon
the availability of storage facilities for used nuclear fuel.
The 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. DOE
disposal fees have been ranging from approximately $10 million to $12
million per year, which the Minnesota Company recovers from its customers
in cost-of-energy rate adjustments. In 1985, the Minnesota Company paid
the DOE a one-time fee of $95 million for fuel used prior to April 7, 1983.
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.
In 1979 the Minnesota Company began expanding the used nuclear fuel
storage facilities at its Monticello Plant by replacement of the racks in
the storage pool. Also, in 1987, the Company completed the shipment of
1,058 spent fuel assemblies from the Monticello Plant to a General Electric
storage facility in Morris, Illinois. As a result, the Monticello plant
now has sufficient pool capacity for temporary storage of used fuel to
operate until 2008.
In 1976 the Minnesota Company began expanding the used nuclear fuel
storage facilities at its Prairie Island Plant by replacement of the racks
in the storage pool. Total capacity was increased from 210 fuel assemblies
to 1,386 fuel assemblies. In 1994 the spent nuclear fuel storage
facilities at the Minnesota Company's Prairie Island Plant reached full
capacity. In May 1994 additional on-site dry cask fuel storage facilities
were approved by the Minnesota Legislature which are expected to provide
sufficient temporary storage capacity to operate the Prairie Island plant
until at least 2002.
Capability and Demand
The Company's record peak demand occurred on December 11, 1995, and
was recorded at 1,042 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). Due to MAPP's
penalty for reserve margin shortfalls and to be prepared for weather
uncertainty at the lowest potential cost, the NSP system carried a reserve
margin for 1995 of 20 percent. In March 1996, the members of MAPP approved
the conversion of MAPP into a Regional Transmission Group (RTG). This
conversion plan will now be submitted to FERC for approval before August 1,
1996. By converting MAPP to an RTG, members will have more input into
transmission access within other members territories. This is one of the
proposals in response to intervenor concerns in the FERC regulatory
approval proceeding of the Minnesota Companys 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 80 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 1995.
The Company also has two electric steam generating facilities. One is
the Bay Front Generating Plant which is located in Ashland, Wisconsin. The
plant is fueled primarily by natural gas, coal and wood residue. Recent
modifications to the facility allow for more effective utilization of
additional waste wood fuel supplies and have extended the useful life of
the facility approximately 20 years from their completion in 1992. In 1992
the Company received authorization from the Wisconsin Department of Natural
Resources ("DNR") to burn tire derived fuel on a regular basis.
The Company's second electric steam generating plant is the French
Island plant located in La Crosse, Wisconsin, which has two fluidized bed
boilers modified for the purpose of burning a mixture of waste wood and
RDF. The Bay Front plant in Ashland and the French Island steam plant are
primarily used on an intermediate load basis.
The Company's thermal peaking capability consists of two oil-fired gas
turbine peaking plants and a gas and oil turbine peaking plant. The
Company also has 19 hydro plants that operate as peaking facilities or run-
of-river facilities.
Demand Side Management
The Company continues to implement various Demand Side Management
(DSM) programs designed to improve load factor and reduce the Company's
power production cost and system peak demands, thus reducing or delaying
the need for additional investment in new generation and transmission
facilities. The Company currently offers a broad range of DSM programs to
all customer sectors, including information programs, rebate and financing
programs, and rate incentive programs. In management's opinion, these
programs need to respond to customer needs and focus on increasing value of
service so that, over the long term, the programs help its customer base
become more stable, energy efficient and competitive.
During 1995, the Company's programs reduced system peak demand by
approximately 20 Megawatts (MW) in the commercial, industrial and
agricultural customer sectors and over 3.9 MW in the residential sector.
These reductions were achieved 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 173 MW of summer
peak demand reduction, which is equivalent to 16% of its 1995 summer peak
demand. A cumulative goal of 200 MW of peak demand reduction by 1997 has
been established. The Company continues to focus on improving the cost-
effectiveness of its DSM programs through market research studies and
program evaluations.
The PSCW has approved changes to the Companys deferral and
amortization practices for Wisconsin DSM program expenditures effective
January 1, 1996. These changes allow the Company to currently expense
rather than defer and amortize certain program expenditures beginning in
1996. Expenditures incurred prior to 1996 will 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 Northern States
Power Company (Minnesota) and Northern States Power Company (Wisconsin)
("Interchange Agreement"). It is a FERC regulated agreement and has been
accepted by the PSCW and the MPSC for determination of costs recoverable in
rates by the Company for charges from the Minnesota Company in rate cases.
Historically the Company's share of the NSP System annual production
and transmission costs has been in the 14 to 17 percent range. Revenues
received from billings to the Minnesota Company for its share of the
Company's production and transmission costs are recorded as electric
operating revenues on the Company's income statement. The portions of the
Minnesota Company's production and transmission costs that were charged to
the Company were recorded as purchased and interchange power expenses and
other operation expenses, respectively, on the Company's income statement.
(See Note 6 to Financial Statements).
Under the Interchange Agreement, the Company could be charged a
portion of the cost of an assessment made against the Minnesota Company
pursuant to the Price-Anderson liability provisions of the Atomic Energy
Act of 1954. (See Note 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 an
agreement dated March 31, 1972, with amendments filed in 1994. The NSP
System is one of 58 members in MAPP consisting of 8 investor-owned
systems, eight generation and transmission cooperatives, three public power
districts, eight municipal systems and the DOE's Western Area Power
Administration, and 30 Associate Participants. The MAPP agreement provides
for the members to coordinate the installation and operation of generating
plants and transmission line facilities. The terms and conditions of the
MAPP agreement and transactions between MAPP members are subject to the
jurisdiction of the FERC. The 1972 MAPP agreement, as amended, was
accepted for filing with the FERC on December 15, 1994.
Fuel Supply
In 1995 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, and wood) over the
next several years. The actual fuel mix for 1995, and the estimated fuel
mix for 1996 and 1997, are as follows:
Fuel Use on Btu Basis
(Est.) (Est.)
1995 1996 1997
Coal 57.9 59.9 59.7
Nuclear 39.0 36.8 36.6
Other * 3.1 3.3 3.7
* Includes oil, gas, refuse derived fuel and wood
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
Electric Revenue (thousands)
Residential 1995 1994 1993 1992 1991
With space heating $ 24 825 $ 23 916 $ 24 086 $ 22 521 $ 23 357
Without space heating 96 248 92 033 90 632 85 889 87 036
Small comm'l and indust'l 54 826 53 842 52 214 50 234 50 391
Large comm'l and indust'l* 110 270 107 462 101 609 95 336 90 748
Street lighting and other 4 320 4 335 4 262 4 206 4 141
Total retail 290 489 281 588 272 803 258 186 255 673
Sales for resale 17 902 17 414 16 009 14 755 21 579
Total $308 391 $299 002 $288 812 $272 941 $277 252
Sales (millions of kilowatt-hours)
Residential
With space heating 372 358 362 346 369
Without space heating 1 346 1 284 1 265 1 229 1 289
Small comm'l and indust'l 882 863 834 814 846
Large comm'l and indust'l* 2 403 2 306 2 169 2 098 2 056
Street lighting and other 42 43 42 43 45
Total retail 5 045 4 854 4 672 4 530 4 605
Sales for resale 456 438 417 394 571
Total 5 501 5 292 5 089 4 924 5 176
Customer accounts (Dec. 31)
Residential
With space heating 28 521 28 024 27 600 27 266 26 923
Without space heating 150 799 148 852 147 000 145 533 144 197
Small comm'l and indust'l 27 706 27 175 26 800 26 418 25 988
Large comm'l and indust'l* 1 276 1 182 1 200 1 109 1 073
Streetlighting and other 998 989 900 1 000 993
Total retail 209 300 206 222 203 500 201 326 199 174
Sales for resale 10 10 10 10 16
Total 209 310 206 232 203 510 201 336 199 190
*Includes customers with annual electric demand of 100 kilowatts or more.
GAS OPERATIONS
During 1995, 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 Companys 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 Companys 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 primary gas transportation provider, NNG, is in the
process of determining the final amount of transition costs to be passed on
to all customers as a result of Order 636 restructuring. NNG's
restructuring provided for the assignment of a significant portion of NNG's
gas supply and upstream contract obligations. The solution was beneficial
because NNGs customers contracted directly for obligations, rather than
paying to buy out those obligations and then contracting with the same gas
suppliers and pipelines to replace the merchant function. NNGs total
transition costs recoverable for the remaining unassigned agreements is
limited to $78 million. In addition, NNG may seek transition cost recovery
for certain other costs, subject to prudency review. NNGs total Order 636
transition costs, to be passed to all of its customers, are estimated to be
approximately $100 million. NNG will recover the prudent transition costs
by amortizing the amount over a period of several years, and including the
amortized costs as a component of its transportation charges. The Company
and the Minnesota Company estimate that they will be responsible for less
than $11 million of NNG's transition costs, spread over a period of
approximately five years, which began November 1, 1993. To date, the
Company's regulatory commissions have approved recovery of restructuring
charges in retail gas rates. The Company has no Order 636 transition cost
responsibilities to its other pipelines.
The Companys ability to operate in a competitive gas market was
expanded through the Minnesota Companys acquisitions of Viking in June
1993 and the assets of a gas marketing business, in October 1993. Viking
allows NSP continued access to competitive interstate natural gas
transportation. The gas marketing business assets are owned by
Cenerprise, Inc. (Cenerprise), a Minnesota Company subsidiary. Cenerprise
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 is continuing its pursuit of growth and profitability
through expansion of its distribution system and services both inside and
outside of its existing service territories. In 1995 the Company extended
service to the Township of Pleasant Valley in Eau Claire County, the
Townships of Tainter and Cedar Falls in Dunn County, and the Town of
Washburn in Bayfield County.
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: energy
management services, sales of unused system supply if profitable, and
brokerage of gas not purchased or required for system needs. These non-
traditional marketing opportunities are a result of deregulation in the
natural gas industry. Traditional regulated services would not have
allowed a mark-up on gas costs. The pilot project, with its sharing of
benefits between customers and shareholders, will, by order of the PSCW, be
discontinued at the end of 1996. Prior to that time, the Company will
determine whether to continue these activities as fully regulated or shift
them to fully unregulated.
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):
Revenues (thousands)
Residential 1995 1994 1993 1992 1991
With space heating $36 695 $33 726 $32 029 $27 592 $24 411
Without space heating 556 571 535 480 532
Small com.w/o space heating 929 869 824 697 682
Small com.with space heating 19 263 17 691 17 049 14 990 13 728
Small industrial firm 6 428 6 545 5 961 3 942 2 953
Total firm 63 871 59 402 56 398 47 701 42 306
Interruptible 16 569 15 299 15 156 13 015 12 869
Total $80 440 $74 701 $71 554 $60 716 $55 175
Sales (thousands of mcf)
Residential
With space heating 5 801 5 243 5 221 4 756 4 598
Without space heating 72 73 72 66 82
Small com.w/o space heating 180 168 162 145 150
Small com.with space heating 3 785 3 424 3 403 3 142 3 056
Small industrial firm 2 162 2 126 1 932 1 128 838
Total firm 12 000 11 034 10 790 9 237 8 724
Interruptible 6 951 6 032 6 153 5 650 5 685
Total 18 951 17 066 16 943 14 887 14 409
Customer Accounts
Residential
With space heating 58 549 55 663 52 700 49 413 46 060
Without space heating 2 778 2 946 3 000 3 089 3 253
Small com.w/o space heating 560 551 500 529 526
Small com.with space heating 7 205 6 846 6 600 6 269 5 960
Small industrial firm 116 116 100 110 113
Total firm 69 208 66 122 62 900 59 410 55 912
Interruptible 292 272 300 259 253
Total 69 500 66 394 63 200 59 669 56 165
ENVIRONMENTAL MATTERS
The Wisconsin Department of Natural Resources (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 affected 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 to the
air. Occasional, infrequent exceedances of DNR air emission opacity
limitations occurred in 1995 at the Company's Bay Front facility. These
are being resolved through operating changes. No agency enforcement action
has resulted.
Regulatory approval is required for the construction of generating
plants and major transmission lines. Also, additional regulations have
been instituted governing the use, transport, disposal and inspection of
hazardous material and electrical equipment containing polychlorinated
biphenyls. The Company has procedures in place to comply with these
regulations.
The 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.
Both the Company and the Minnesota Company have received notices for
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 (PRP's), both
companies voluntarily joined a group of other parties to address the
contamination at this site. A preliminary estimate of total remediation
costs at the site is approximately $6 million. The Company's and the
Minnesota Company's share of this cost is currently estimated to be
approximately 1%. The Company's share alone is estimated to be $20,000.
In addition, the administrator of a group of PRP's has notified the
Company that it might be responsible for cleanup of a solid and hazardous
waste landfill site in Eau Claire, Wisconsin. The Company contends that it
did not dispose of hazardous wastes in the subject landfill during the time
period in question. Because neither the amount of cleanup costs nor the
final method of their allocation among all designated PRP's has been
determined, it is not feasible to predict the outcome of the matter at this
time or any potential future impact on the Companys 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.
On February 19, 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 a number of remediation options which 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 ongoing limited groundwater treatment, would cost
approximately $6.0 million. Currently, the WDNR is conducting an
investigation in Chequamegon Bay adjacent to Kreher Park to determine the
extent of contamination in the bay. The WDNR has informed the Company that
it will not choose or proceed with any remediation options on any portion
of the Ashland site until the completion of the Chequamegon Bay
investigation in the second half of 1996. Until more information is known
concerning the extent of remediation required by the WDNR, the remediation
method selected and 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 the expected timing of any payments
related to the Ashland site is not determinable. At December 31, 1995, the
Company had recorded an estimated liability of $900,000 for future
remediation costs at this site and had incurred approximately $400,000 in
actual expenditures.
On March 11, 1996, the Company received a Notice of Violation from the
WDNR stating that emissions from the Company's French Island facility had
exceeded allowable levels for dioxin. The WDNR has requested a written
response from the Company no later than April 15, 1996, setting forth the
Companys plans for bringing the emissions levels back into compliance.
The Company is currently investigating this matter to determine the cause
of this unexpected event. 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
operations.
In late December 1994, the Company completed installation of a control
center monitoring system at the Bay Front generating plant in Ashland,
Wisconsin. The continuous emissions system which will monitor emissions
from the four generating units, was mandated by the Clean Air Act and has
been in service since January 1, 1995.
CONSTRUCTION AND FINANCING
During the five years ended December 31, 1995, the Company had gross
additions to utility plant in service of approximately $250.9 million.
Included in the Company's gross additions is $29.8 million for electric
production facilities, $149.9 million for other electric properties, $38.4
million for gas utility properties, and $32.8 million for other utility
properties. Retirements during the same period were approximately $39.2
million. Based on studies made by the Company, the weighted average age of
depreciable property was 12.9 years at December 31, 1995.
Expenditures for the Company's construction programs for the five-year
period 1996-2000, are estimated to be as follows:
Year Estimated Construction Expenditures
1996 $ 54 million
1997 60 million
1998 68 million
1999 64 million
2000 57 million
TOTAL $303 million
The 1996 construction expenditures are estimated to include
approximately $37.6 million for electric facilities, $5.0 million for gas
facilities and $11.2 million for general plant and equipment. It is
presently estimated that approximately 88% of the 1996-2000 construction
expenditures will be provided by internally generated funds, with the
remainder from short-term and long-term debt financing. In addition to
construction financing needs, long-term debt is expected to be issued to
refinance the Companys 9-1/8% first mortgage bonds, which are callable
beginning April 1, 1996. At December 31, 1995, the Company's short-term
borrowings payable to the Minnesota Company were $50.9 million. These
short-term borrowings have been authorized up to $55.0 million by the PSCW.
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 1995, the total number of full- and part-time employees of
the Company was approximately 896. About 410 employees of the Company are
represented by one local IBEW labor union, under a three year collective
bargaining agreement expiring December 31, 1996.
Recent changes to the Company's employee and retiree benefits, which
support a broad NSP goal of providing market-based benefits, include:
Active nonbargaining medical premium increases: A cost sharing
strategy for medical benefits for nonbargaining employees was implemented
in 1994. The strategy consisted of adjusting the employee contribution
portion of total medical costs to 10% in 1994 and 20% in 1995 and 1996.
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. In 1994, the Company began matching
employees' pre-tax 401(k) contributions. Such matching contributions were
$0.5 million in 1995, based on matching up to $700 per year for each
nonbargaining employee and up to $500 per year for each bargaining
employee. In 1994, matching contributions were $0.3 million. In 1996,
NSP's annual match will increase to $900 for nonbargaining employees.
Under the terms of the bargaining agreement implemented in 1994, NSP's
annual match for each bargaining employee will increase to $600 in 1996.
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 1995, nonbargaining employees received an
average wage scale increase of 3.5%, while bargaining employees received a
2% base wage increase and a 1.5% lump sum payment. In January 1996,
nonbargaining employees received an average wage scale increase of 3.5%,
while bargaining employees received a 4% base wage increase.
Item 2. Properties
Electric Utility
The Company's major electric generating facilities consist of the
following:
Projected
Year 1996-7 Winter
Station and Units Fuel Installed Capability (MW)
Combustion Turbine:
Flambeau Station Gas/Oil 1969 17
(1 unit)
Park Falls, WI
Wheaton Oil 1973 440
(6 units
Eau Claire, WI
French Island Oil 1974 192
(2 units)
La Crosse, WI
Steam:
Bay Front Coal/Wood/ 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 248
TOTAL 1 001
At December 31, 1995, the Company owned approximately 2,392 pole miles
of overhead electric transmission lines, 8,044 pole miles of overhead
electric distribution lines, 37 conduit miles and 1,011 direct buried cable
miles of underground electric lines. Virtually all of the land and
personal property owned by the Company is subject to the lien of their
first mortgage bond indentures pursuant to which the Company has issued
first mortgage bonds.
Gas Utility
The gas properties of the Company include approximately 1,438 miles of
natural gas distribution mains. The Company owns two liquefied natural gas
facilities with a combined storage capacity of the equivalent of 400,000
Mcf to supplement the available pipeline supply of natural gas during
periods of peak demands. The two liquified natural gas facilities are
located in Eau Claire and La Crosse, Wisconsin. In January of 1993, the
Company installed temporary propane air facilities with a capacity of
144,000 gallons to further supplement its gas supply in the La Crosse,
Wisconsin area during peak periods. This propane air facility was not
operational for the 1995-96 winter but may be considered for use 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.
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
Omitted per conditions set forth in general instruction J (1) and (a)
and (b) of Form 10-K for wholly-owned subsidiaries (reduced disclosure
format).
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, 1995 with the year ended December 31, 1994.
The Company's net income for year ended December 31, 1995 was $39.2
million, up from the $38.5 million earned in the same period of 1994. The
1995 operating income increased by $1.3 million from the 1994 level.
Electric Sales and Revenues
Electric revenues for 1995 increased $5.9 million, a 1.6 percent
increase from 1994. Revenues from retail sales, which accounted for 76.3
percent of the electric revenues in 1995, increased $8.9 million or 3.2
percent. Reflected in this revenue increase is an estimated $5.1 million
due to more favorable weather conditions. Residential sales in 1995 were
4.6 percent higher than 1994, including weather impacts. Included in the
1995 retail increase is $2.8 million related to the Company's large
commercial and industrial customers, some of which expanded their
operations, increasing energy needs.
The Company's wholesale customers accounted for 5.8 percent of the
total electric revenues. Wholesale revenues increased $0.5 million or 2.8
percent in 1995, with sales increasing 4.2 percent.
Another major component (approximately 15.3 percent) of electric
revenues is charges billed to the Minnesota Company through the Interchange
Agreement (see Part I, Item 1; Business-Electric Operations). Interchange
Agreement billings charged to the Minnesota Company decreased $3.3 million
mainly as a result of less fuel being burned in Wisconsin for system
requirements.
Other electric revenues decreased $0.2 million in 1995.
Gas Sales and Revenues
Gas revenues in 1995 increased by $1.3 million or 1.8 percent as
compared with 1994. This is the impact of increased revenues due to a 8.8
percent increase in firm sales due to customer and usage growth, and
increased revenues of $0.5 million due to more moderate winter weather in
1994. Offsetting these firm sales increases were the impact of lower
purchased gas costs being reflected in customer rates.
Operating Expenses and Other Factors
Fuel for Electric Generation, which represents the Company's portion
of the NSP System's fuel generation and Purchased and Interchange Power
together decreased $1.1 million or 0.6 percent in 1995 from 1994. Although
system output increased to meet higher sales demand, decreases in the cost
per unit of energy more than offset the costs of higher sales.
Gas Purchased for Resale decreased $1.1 million or 2.1 percent. Of
the $1.1 million deviation, approximately $0.3 million is due to the lower
cost per unit of purchased gas, $0.7 million is due to lower transportation
charges, with the remaining $0.1 million due to decreases in miscellaneous
purchased gas costs.
Other operation costs increased $2.3 million due to increases in steam
and distribution operating expenses and in transmission costs charged from
the Minnesota Company for the Companys share of NSP system costs.
Maintenance expense for 1995 was $1.6 million lower than 1994 levels.
Of this decrease, $1.3 million related to lower maintenance costs for the
Companys hydro plants.
Administrative and general costs decreased $1.2 million due to a
decrease in labor costs.
Conservation costs increased $0.5 million from 1995 as compared to
1994 primarily due to increases in the amortization levels for demand side
management program costs previously capitalized.
Depreciation and Amortization increased $2.3 million in 1995 primarily
due to higher levels of depreciable plant, particularly shorter-lived
computer equipment.
Property and General Taxes increased $0.4 million primarily due to
higher gross receipts tax as a result of 1995 revenues increasing over 1994
revenues.
Income taxes increased $5.5 million in 1995 over the 1994 level.
Approximately $2.8 million of the increase is due to adjustments made in
the third quarter of 1994 decreasing current tax expense. These
adjustments resulted from the updating of the status of the estimated
income tax payments expected to be incurred as a result of unaudited tax
years. The remaining $2.7 million increase is primarily attributable to
the increase in pretax book income. See Note 4 to the Financial Statements
for a detailed reconciliation of effective tax rates and statutory rates.
Allowances for Funds Used During Construction (AFC) decreased $0.2
million in 1995 from 1994 due to lower levels of qualifying construction
and lower AFC rates associated with increased use of low-cost short-term
borrowings.
Other income and deductions increased $1.1 million in 1995 from 1994.
This increase was mainly due to increases in subsidiary company earnings,
including affordable housing and real estate businesses.
Other interest and amortization expense increased $1.5 million in 1995
from 1994. An increase in interest to associated companies accounted for
$1.1 million of the increase. Of this increase, $1.1 million resulted from
increases in both the interest rate and the level of short-term borrowings
from the Minnesota Company in 1995. The remaining $0.4 million increase in
other interest expense is due to the write-off of previously deferred
interest on 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 sheet 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, 1995, and the results of its
operations and its cash flows for the year in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Companys management; our responsibility is to
express an opinion on these financial statements based on our audit. We
conducted our audit 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 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 audit provides a reasonable
basis for the opinion expressed above. The financial statements of the
Company for the years ended December 31, 1994 and 1993 were audited by
other independent accountants whose report dated January 27, 1995 expressed
an unqualified opinion on those statements.
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
February 5, 1996, except as to the Environmental Contingencies
section of Note 8, which is as of February 19, 1996
Item 8 Financial Statements and Supplementary Data
INDEPENDENT AUDITORS' REPORT
Northern States Power Company (Wisconsin):
We have audited the accompanying balance sheet of Northern States Power
Company (Wisconsin) (the Company) and its subsidiaries as of December 31,
1994 and the related statements of income and retained earnings and of cash
flows for each of the two years in the period ended December 31, 1994.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on the financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of the Company at December 31, 1994 and
the results of their operations and their cash flows for each of the two
years in the period ended December 31, 1994, in conformity with generally
accepted accounting principles.
Deloitte and Touche LLP
Minneapolis, Minnesota
January 27, 1995
Item 8 Financial Statements and Supplementary Data
Statements of Income and Retained Earnings Year Ended December 31
(Thousands of dollars) 1995 1994
1993
Operating Revenues
Electric $ 380 724 $ 374 777 $ 362 473
Gas 78 058 76 715 72 760
Total 458 782 451 492 435 233
Operating Expenses
Purchased and interchange power 173 743 174 144 162 510
Fuel for electric generation 4 703 5 414 3 185
Gas purchased for resale 52 356 53 484 51 501
Other operation 46 534 44 260 43 351
Maintenance 20 780 22 385 21 703
Administrative and general 25 264 26 487 26 842
Conservation and demand side management 7 674 7 211 6 556
Depreciation and amortization 33 059 30 736 28 585
Property and general taxes 14 109 13 710 13 091
Income taxes 24 662 19 077 23 103
Total operating expenses 402 884 396 908 380 427
Operating Income 55 898 54 584 54 806
Other Income and Deductions
Allowance for funds used
during construction-equity 445 671 694
Other income and deductions-net 1 976 864 844
Total Other Income 2 421 1 535 1 538
Income Before Interest Charges 58 319 56 119 56 344
Interest Charges
Interest on long-term debt 16 038 15 995 16 343
Other interest and amortization 3 548 2 060 2 406
Allowance for funds used
during construction-debt (484) (481) (411)
Total interest charges 19 102 17 574 18 338
Net Income 39 217 38 545 38 006
Retained Earnings, January 1 218 833 205 114 192 816
Dividends paid on common stock (36 412) (24 826) (25 708)
Retained Earnings, December 31 $ 221 638 $ 218 833 $ 205 114
See Notes to Financial Statements.
Item 8 Financial Statements and Supplementary Data
Statements of Cash Flows Year Ended December 31
(Thousands of dollars) 1995 1994 1993
Cash Flows from Operating Activities:
Net Income $39 217 $38 545 $38 006
Adjustments to reconcile net
income to cash from operating activities:
Depreciation and amortization 34 180 32 382 33 580
Deferred income taxes 1 839 7 614 7 161
Deferred investment tax credits recognized (936) (943) (948)
AFC-equity (445) (671) (694)
Insurance receivable 3 091 (3 091) 0
Other (1 064) (6 076) 67
Cash provided by (used for) changes in
certain working capital items 7 282 (9 568) 299
Net Cash Provided by Operating Activities 83 164 58 192 77 471
Cash Flows from Financing Activities:
Proceeds from issuance of long-term debt 0 0 146 587
Proceeds from issuance of notes
payable-parent company 9 600 17 800 0
Repayment of notes payable-parent company 0 0 (800)
Repayment of long-term debt
(including reacquisition premium) (3 375) (990) (136 090)
Dividends paid to parent (36 412) (24 826) (25 708)
Net Cash Used for Financing Activities (30 187) (8 016) (16 011)
Cash Flows from Investing Activities:
Construction expenditures capitalized (51 173) (52 639) (59 954)
Decrease in construction payables (457) (633) (2 143)
AFC-equity 445 671 694
Other (1 606) 2 037 (489)
Net Cash Used for Investing Activities (52 791) (50 564) (61 892)
Net Increase/(Decrease) in Cash 186 (388) (432)
Cash at Beginning of Period 61 449 881
Cash at End of Period $ 247 $ 61 $ 449
Cash (used for) provided by changes in certain working capital items:
Accounts receivable-net $(6 188) $ 770 $(1 597)
Materials and supplies 3 442 (4 708) (453)
Accounts payable and accrued liabilities 1 241 332 7 633
Payables to affiliated companies 4 475 (2 655) 127
Income and other taxes accrued 417 (4 174) (2 762)
Other 3 895 867 (2 649)
Net $ 7 282 $ (9 568) $ 299
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized) $ 15 389 $ 15 870 $ 17 440
Income taxes (net of refunds received) $ 17 333 $ 18 773 $ 18 825
See Notes to Financial Statements.
Item 8 Financial Statements and Supplementary Data
Balance Sheets December 31
(Thousands of dollars) 1995
1994
Assets
Utility Plant
Electric-including construction work in progress:
1995, $12,640; 1994, $14,599 $ 864 514 $ 836 665
Gas 94 425 88 350
Other 63 758 54 675
Total 1 022 697 979 690
Accumulated provision for depreciation (370 634) (344 675)
Net utility plant 652 063 635 015
Other Property and Investments
Nonutility property - at cost 3 123 3 082
Accumulated provision for depreciation (334) (365)
Other investments - at cost
which approximates market 6 429 3 974
Total other property and investments 9 218 6 691
Current Assets
Cash 247 61
Accounts receivable 43 988 37 484
Accumulated provision for
uncollectible accounts (854) (538)
Materials and supplies - at average cost
Fuel 6 689 9 804
Other 5 561 5 889
Unbilled utility revenues 18 665 16 409
Prepayments and other 11 295 11 030
Deferred tax asset 0 1 415
Total current assets 85 591 81 554
Other Assets
Unamortized debt expense 2 780 2 928
Regulatory assets 34 704 32 783
Federal Income tax receivable 3 307 3 307
Insurance receivable 0 3 091
Other 3 235 2 931
Total deferred debits 44 026 45 040
Total $ 790 898 $ 768 300
See Notes to Financial Statements.
Item 8 Financial Statements and Supplementary Data
December 31
(Thousands of dollars) 1995 1994
Liabilities and Equity
Capitalization
Common stock-authorized 870,000
shares of $100 par value;
issued shares: 1995 and 1994, 862,000 $ 86 200 $ 86 200
Premium on common stock 10 461 10 461
Retained earnings 221 638 218 833
Total common equity 318 299 315 494
Long-term debt 213 235 213 700
Total capitalization 531 534 529 194
Current Liabilities
Notes payable - parent company 50 900 41 300
Long-term debt due within one year 0 2 910
Accounts payable 14 884 14 415
Payables to affiliated companies
(principally parent) 13 457 8 982
Salaries, wages, and vacation pay accrued 6 343 6 028
Federal income taxes accrued 4 111 0
Other taxes accrued 1 537 936
Interest accrued 5 300 5 485
Deferred tax liability 1 963 0
Capital lease obligations and other 3 767 1 463
Total current liabilities 102 262 81 519
Deferred Credits
Accumulated deferred income taxes 100 227 99 748
Accumulated deferred investment tax credits 21 205 22 332
Regulatory liabilities 18 430 17 961
Customer advances 6 458 5 543
Benefit obligations and other 10 782 12 003
Total deferred credits 157 102 157 587
Commitments and Contingent Liabilities
Total $ 790 898 $ 768 300
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 to the
Company's financial position.
Related Party Transactions All significant intercompany transactions
and balances have been eliminated in consolidation except for intercompany
and intersegment profits for sales among the electric and gas utility
businesses of the Company, the Minnesota Company and Viking Gas
Transmission Company (a wholly-owned subsidiary of the Minnesota Company),
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 3.48 percent in 1995, 3.45 percent in 1994, and 3.40
percent in 1993.
Allowance for Funds Used during Construction (AFC) AFC, a non-cash
item, is computed by applying a composite pretax rate, representing the
cost of capital used to fund utility construction, to qualified
Construction Work in Progress (CWIP). The rates used for the FERC
calculation were 6.20 percent in 1995, 7.55 percent in 1994, and 7.93
percent in 1993. The rates used for the PSCW calculation were 10.13
percent in 1995, 10.13 percent in 1994, and 10.84 percent in 1993. 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 Customers' meters are read and bills rendered on a cycle
basis. The Company accrues the amount of estimated unbilled revenues for
services provided from the monthly meter reading date to month-end. The
current asset, unbilled utility revenues, is adjusted monthly, with a
corresponding adjustment to revenues, to reflect estimated changes in
unbilled revenues.
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 The Company records income taxes in accordance with SFAS
No. 109 - Accounting For Income Taxes. SFAS No. 109 requires the use of
the liability method whereby income taxes are deferred for temporary
differences between pretax financial and taxable income, and between the
book and tax bases of assets and liabilities. Deferred taxes are recorded
using the tax rates scheduled by tax law to be in effect when the temporary
differences reverse. Due to the effects of regulation, 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 backed to the Company.
Investment tax credits are deferred and amortized over the estimated
lives of the related property.
Purchased Tax Benefits The Company purchased tax-benefit transfer
leases under the Safe Harbor Lease provisions of the Economic Recovery Tax
Act of 1981. For both financial reporting and regulatory purposes, the
Company is amortizing the difference between the cost of the purchased tax
benefits and the amounts to be realized through reduced current income tax
liabilities over the remaining terms of the lease after the initial
investments have been recovered.
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 are 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. When a single estimate of the
liability cannot be determined, the low end of the estimated range is
recorded. Costs are charged to expense (or deferred as a regulatory asset
based on expected recovery from customers in future rates) if they relate
to the remediation of conditions caused by past operations or if they are
not expected to mitigate or prevent contamination from future operations.
Where environmental expenditures 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 Notes 5 and 8.
Reclassifications Certain reclassifications have been made to the 1994
and 1993 financial statements to conform with the 1995 presentation. These
reclassifications had no effect on net income or earnings per share.
2. Long-term Debt
December 31
1995 1994
(Thousands of dollars)
Long-term debt includes the following issues:
First Mortgage Bonds - less reacquired bonds of $3,365 and $490 at
December 31, 1995 and 1994, respectively:
Series due:
Apr. 1, 2021, 9-1/8% $ 44 635 $ 48 010
Mar. 1, 2023, 7 1/4% 110 000 110 000
Oct. 1, 2003, 5 3/4% 40 000 40 000
Total 194 635 198 010
Less April 1, 2021, 9 1/8% bonds
redeemed in February 1995
(classified as current at
December 31, 1994) 0 2 910
________ ________
Net long-term portion of First Mortgage Bonds 194 635 195 100
City of LaCrosse Resource Recovery Revenue
Bonds - Series due Nov. 1, 2011, 7 3/4% 18 600 18 600
Total long-term debt $213 235 $213 700
Except for minor exclusions, all real and personal property is subject
to the lien of the Companys 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 $20.0
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 8.03% at
December 31, 1995.
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 Companys balance sheets. The interest rate swaps serve to hedge the
interest rate risk associated with fixed rate debt in a declining interest
rate environment. This hedge is produced by the tendency for changes in
the fair market value of the swap to be offset by changes in the present
value of the liability attributable to the fixed rate debt issued in
conjunction with the interest rate swap. If the interest rate swap had
been terminated at Dec. 31, 1995, $1.8 million would have been payable by
the Company while the present value of the fixed rate debt issued with the
swaps was $3.1 million below par value.
Fair Value of Debt The estimated fair value of the Companys long
term debt (including debt due within one year classified as current) at
December 31, 1995 and 1994 is $230.6 million and $196.2 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 in the next five years are approximately $1,061,000, $753,000,
$442,000, $129,000, and $15,000, respectively, for the years 1996-2000.
3. Short-Term Borrowings
The Company had bank lines of credit aggregating $1,000,000 at December
31, 1995. 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 1995 and 1994 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 $55.0 million. At December 31, 1995 and 1994, the Company
had $50.9 million and $41.3 million, respectively, in short-term commercial
paper borrowings outstanding. The weighted average interest rates on all
short-term borrowings as of December 31, 1995, and December 31, 1994, were
6.2 percent and 5.0 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:
1995 1994 1993
(Thousands of dollars)
Tax computed at statutory rate $ 22 140 $ 20 074 $ 21 387
Increases (decreases) in tax from:
State income taxes,
net of Federal income tax benefit 3 314 2 393 3 165
Investment tax credits recognized (936) (943) (948)
Adjustment to taxes accrued in prior years 90 (2 430) 0
Other - net (567) (283) (506)
Total income tax expense $ 24 041 $ 18 811 $ 23 098
Effective income tax rate 38.0% 32.8% 37.8%
Income tax expense is comprised of the following:
Included in income taxes:
Current Federal tax expense $ 17 772 $ 8 075 $ 12 919
Current state tax expense 4 546 2 810 3 180
Deferred Federal tax expense 2 680 7 967 6 173
Deferred state tax expense 601 1 168 1 778
Deferred inv. tax credit adjustments (936) (943) (948)
Total 24 663 19 077 23 103
Included in income deductions:
Current Federal tax expense 691 1 039 875
Current state tax expense 129 216 (90)
Deferred Federal tax expense (1 264) (1 008) (790)
Deferred state tax expense (178) (513) 0
Total income tax expense $ 24 041 $ 18 811 $ 23 098
The components of the Company's net deferred tax liability at Dec. 31
(including current and noncurrent amounts) were as follows:
(Thousands of dollars) 1995 1994
Deferred tax liabilities:
Differences between book and tax bases of
property $ 106 390 $ 98 526
Tax benefit transfer leases 3 369 4 950
Regulatory assets 12 498 11 626
Other 4 336 3 332
Total deferred tax liabilities 126 593 118 434
Deferred tax assets:
Deferred investment tax credits 8 507 8 955
Regulatory liabilities 11 063 7 409
Deferred compensation, accrued vacation and
other reserves not currently deductible 4 040 3 155
Other 794 582
Total deferred tax assets 24 404 20 101
Net deferred tax liability $ 102 189 $ 98 333
5. Pension Plans and Other Post Retirement Benefits
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.
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:
1995 1994 1993
(Thousands of dollars)
Service cost - benefits earned
during the period $ 2 844 $ 3 114 $ 2 845
Interest cost on projected benefit obligation 8 662 8 087 9 024
Actual return on allocated share
of plan assets (10 994) (1 702) (18 724)
Net amortization and deferral (1 567) (10 130) 8 091
Net periodic pension cost
determined under SFAS No. 87 (1 055) (631) 1 236
Expenses recognized due to actions
of regulators 90 90 90
Net periodic pension (benefit)
cost recognized for ratemaking $ (965) $ (541) $ 1,326
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 funded status of the pension plan,
including amounts allocable to the Company, as of December 31 is as
follows:
1995 1994
Company Company
Total Plan Portion Total Plan Portion
Actuarial present value
of benefit obligation:
Vested $686 403 $ 87 877 $571 254 $ 74 387
Nonvested 155 177 17 901 120 420 14 538