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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1995 Commission file number: 1-3034
NORTHERN STATES POWER COMPANY
(Exact name of Registrant as specified in its charter)
Minnesota 41-0448030
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
414 Nicollet Mall, Minneapolis, Minnesota 55401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 612-330-5500
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of each exchange on which
registered
Common Stock, $2.50 Par Value New York Stock Exchange,
Chicago Stock Exchange and
Pacific Stock Exchange
Cumulative Preferred Stock, $100
Par Value each
Preferred Stock $ 3.60 Cumulative New York Stock Exchange
Preferred Stock $ 4.08 Cumulative New York Stock Exchange
Preferred Stock $ 4.10 Cumulative New York Stock Exchange
Preferred Stock $ 4.11 Cumulative New York Stock Exchange
Preferred Stock $ 4.16 Cumulative New York Stock Exchange
Preferred Stock $ 4.56 Cumulative New York Stock Exchange
Preferred Stock $ 6.80 Cumulative New York Stock Exchange
Preferred Stock $ 7.00 Cumulative New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
_____
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirementes for the past 90 days. Yes X No .
_____ _____
As of March 15, 1996, the aggregate market value of the voting common
stock held by non-affiliates of the Registrant was $3,279,100,656 and there
were 68,490,761 shares of common stock outstanding, $2.50 par value.
Documents Incorporated by Reference
The Registrant's Definitive Proxy Statement for its 1996 meeting of
shareholders to be held on April 24, 1996, is incorporated by reference
into Part III of Form 10-K.
Index
Page No.
PART I
Item 1 - Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION . . . . . . . . . . .1
UTILITY REGULATION AND REVENUES
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5
Revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5
General Rate Filings. . . . . . . . . . . . . . . . . . . . . . . .6
Ratemaking Principles in Minnesota and Wisconsin. . . . . . . . . .6
Fuel and Purchased Gas Adjustment Clauses in Effect . . . . . . . .7
Resource Adjustment Clauses in Effect . . . . . . . . . . . . . . .8
Rate Matters by Jurisdiction. . . . . . . . . . . . . . . . . . . .9
ELECTRIC UTILITY OPERATIONS
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Capability and Demand . . . . . . . . . . . . . . . . . . . . . . 16
Energy Sources. . . . . . . . . . . . . . . . . . . . . . . . . . 18
Fuel Supply and Costs . . . . . . . . . . . . . . . . . . . . . . 19
Nuclear Power Plants - Licensing, Operation and Waste
Disposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Electric Operating Statistics . . . . . . . . . . . . . . . . . . 24
GAS UTILITY OPERATIONS
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Capability and Demand . . . . . . . . . . . . . . . . . . . . . . 26
Gas Supply and Costs. . . . . . . . . . . . . . . . . . . . . . . 26
Viking Gas Transmission Company . . . . . . . . . . . . . . . . . 28
Gas Operating Statistics . . . . . . . . . . . . . . . . . . . . 29
NON-REGULATED SUBSIDIARIES
NRG Energy, Inc. . . . . . . . . . . . . . . . . . . . . . . . . 29
Cenergy, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Eloigne Company . . . . . . . . . . . . . . . . . . . . . . . . . 33
Non-Regulated Business Information. . . . . . . . . . . . . . . . 34
ENVIRONMENTAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . . 35
CAPITAL SPENDING AND FINANCING. . . . . . . . . . . . . . . . . . . . 38
EMPLOYEES AND EMPLOYEE BENEFITS . . . . . . . . . . . . . . . . . . . 39
EXECUTIVE OFFICERS. . . . . . . . . . . . . . . . . . . . . . . . . . 41
Item 2 - Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Item 3 - Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 44
Item 4 - Submission of Matters to a Vote of Security Holders . . . . . . 45
PART II
Item 5 - Market for Registrant's Common Equity and Related
Stockholder Matters. .. . . . . . . . . . . . . . . . . . . . 45
Item 6 - Selected Financial Data . . . . . . . . . . . . . . . . . . . . 46
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . . . . 47
Item 8 - Financial Statements and Supplementary Data . . . . . . . . . . 62
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . . 93
PART III
Item 10 - Directors and Executive Officers of the Registrant . . . . . . 93
Item 11 - Executive Compensation . . . . . . . . . . . . . . . . . . . . 93
Item 12 - Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . . . 93
Item 13 - Certain Relationships and Related Transactions . . . . . . . . 93
PART IV
Item 14 - Exhibits, Financial Statement Schedules, and Reports
on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . 94
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .100
Exhibit (Excerpt)
Unaudited Pro Forma Financial Information. . . . . . . . . . . . . . . .101
PART I
Item 1 - Business
Northern States Power Company (the Company) was
incorporated in 1909 under the laws of Minnesota. Its executive
offices are located at 414 Nicollet Mall, Minneapolis, Minnesota
55401. (Phone 612-330-5500). The Company has two significant
subsidiaries, Northern States Power Company, a Wisconsin
corporation (the Wisconsin Company) and NRG Energy, Inc. (NRG),
a Delaware corporation; and several other subsidiaries,
including Cenergy, Inc. (which changed its name to Cenerprise,
Inc. effective Jan. 1, 1996), a Minnesota corporation, and
Viking Gas Transmission Company, a Delaware corporation
(Viking). (See "Gas Utility Operations - Viking Gas
Transmission Company" and "Non-Regulated Subsidiaries" herein
for further discussion of these subsidiaries.) The Company and
its subsidiaries collectively are referred to herein as NSP.
NSP is predominantly an operating public utility
engaged in the generation, transmission and distribution of
electricity throughout an approximately 49,000 square mile
service area and the transportation and distribution of natural
gas in approximately 156 communities within this area. Viking
is a regulated natural gas transmission company that operates a
500-mile interstate natural gas pipeline. NRG manages several
non-regulated energy subsidiaries.
The Company serves customers in Minnesota, North
Dakota and South Dakota. The Wisconsin Company serves customers
in Wisconsin and Michigan. Of the approximately 3 million
people served by the Company and the Wisconsin Company, the
majority are concentrated in the Minneapolis-St. Paul
metropolitan area. In 1995, about 63 percent of NSP's electric
retail revenue was derived from sales in the Minneapolis-St.
Paul metropolitan area and about 55 percent of retail gas
revenue came from sales in the St. Paul metropolitan area. (For
business segment information, see Note 16 of Notes to Financial
Statements under Item 8.)
NSP's utility businesses are currently experiencing
some of the challenges common to regulated electric and gas
utility companies, namely, increasing competition for customers,
increasing pressure to control costs, uncertainties in
regulatory processes and increasing costs of compliance with
environmental laws and regulations. In addition, there are
uncertainties related to permanent disposal of used nuclear
fuel. (See Management's Discussion and Analysis under Item 7,
Notes 14 and 15 of Notes to Financial Statements under Item 8
and "Electric Utility Operations - Capability and Demand and
Nuclear Power Plants - Licensing, Operation and Waste Disposal,"
herein, for further discussion of this matter.)
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION
Description of the Merger Transaction
As initially announced in the Company's Current
Report on Form 8-K dated April 28, 1995 and filed on May 3, 1995
(the Company's 4/28/95 8-K), NSP, Wisconsin Energy Corporation,
a Wisconsin corporation (WEC), Northern Power Wisconsin Corp.,
a Wisconsin corporation and wholly-owned subsidiary of NSP (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 NSP and WEC in a "merger-of-equals" transaction (the
Merger Transaction). The Merger Transaction, which was approved
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 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 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 Revenues - Rate Matters by Jurisdiction"
herein. (See additional discussion of the Merger Transaction
under Item 7, Management's Discussion and Analysis, under Item
8, Note 18 of Notes to Financial Statements and pro forma
financial statements 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 Corporation (Primergy) and will
be the parent company of both NSP (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 Merger Transaction, except for certain gas
distribution properties transferred to the Company, the
Wisconsin Company will be merged into Wisconsin Energy Company.
Incorporated herein as exhibits by reference are the
Merger Agreement, filed as an exhibit to New NSP's registration
statement on Form S-4, and the press release issued in
connection therewith and the related Stock Option Agreements
(defined below) filed as exhibits to the Company's 4/28/95 8-K.
The descriptions of the Merger Agreement and the Stock Option
Agreements set forth herein do not purport to be complete and
are qualified in their entirety by the provisions of the Merger
Agreement and the Stock Option Agreements, as the case may be,
and the other exhibits filed with the Company's 4/28/95 8-K.
Under the terms of the Merger Agreement, the 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
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. As of the date of the Merger Agreement, (April 28, 1995)
the Company had 67.3 million common shares outstanding and WEC
had 109.4 million common shares outstanding. Based on such
capitalization, the Merger Transaction would result in the
common shareholders of the Company receiving 50 percent of the
common stock equity of Primergy and the common shareholders of
WEC owning the other 50 percent of the common stock equity of
Primergy. Each outstanding share of the Company's cumulative
preferred stock, par value $100.00 per share, will be canceled
and converted into the right to receive one share of cumulative
preferred stock, par value $100.00 per share, of New NSP with
identical rights (including dividend rights) and designations.
WEPCO's outstanding preferred stock will remain outstanding and
be unchanged in the Merger Transaction.
It is anticipated that Primergy will adopt the
Company's dividend payment level adjusted for the exchange
ratio. The Company currently pays $2.70 per share annually, and
WEC's annual dividend rate is currently $1.47 per share. Based
on the 1.626 stock exchange ratio and the Company's current
dividend rate, the pro forma dividend rate for Primergy Common
Stock would be $1.66 per share as of Dec. 31, 1995. However, the
amount, declaration, and timing of dividends on Primergy Common
Stock will be a business decision to be made by the Primergy
Board of Directors from time to time based upon the results of
operations and financial condition of Primergy and its
subsidiaries and such other business considerations as the
Primergy Board considers relevant in accordance with applicable
laws.
Merger Consummation Conditions
The Merger Transaction is subject to 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 Revenues - 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 Company and WEC took the following steps
toward fulfilling the conditions to closing:
- Registration statements filed by WEC and the
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.
- NSP 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.
- NSP and WEC filed for regulatory approval of the
Merger Transaction with the FERC and state
commissions. (See "Utility Regulation and
Revenues - Rate Matters by Jurisdiction", herein,
for further discussion of the status of these
filings.)
- The Company filed for the NRC approval of the
transfer of nuclear operating licenses from the
Company to New NSP.
During 1996 NSP and WEC expect to make the following
filings as part of the regulatory approval process for the
Merger Transaction:
- NSP and WEC will file 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.
- 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.
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 or-
dinary course consistent with past practice, may not increase
dividends on common stock beyond specified levels, and may not
issue capital stock beyond certain limits. The Merger Agreement
also contains restrictions on, among other things, charter and
bylaw amendments, capital expenditures, acquisitions,
dispositions, incurrence of indebtedness, certain increases in
employee compensation and benefits, and affiliate transactions.
In accordance with the Merger Agreement, upon the
consummation of the Merger Transaction, James J. Howard,
Chairman, President, and Chief Executive Officer of the Company
will initially serve as the Chairman and Chief Executive Officer
of Primergy for a minimum of 16 months after the effectiveness
of the Merger Transaction and will thereafter serve only as
Chairman of the Board of Primergy for a minimum of two years.
Also, Richard A. Abdoo, Chairman, President and Chief Executive
Officer of WEC shall initially hold the positions of Vice
Chairman of the Board, President and Chief Operating Officer of
Primergy and thereafter shall be entitled to hold the additional
position of Chief Executive Officer when Mr. Howard ceases to be
Chief Executive Officer. Mr. Abdoo will assume the position of
Chairman when Mr. Howard ceases to be Chairman.
The Merger Agreement may be terminated under certain
circumstances, including (1) by mutual consent of the parties;
(2) by any party if the Merger Transaction is not consummated by
April 30, 1997 (provided, however, that such termination date
shall be extended to 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
NSP'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 parties
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
NSP 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 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 and gas
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 has proposed an average retail electric
rate reduction of 1.5 percent and a four-year rate freeze in its
retail jurisdictions. The electric rate reduction of 1.5
percent would be implemented as soon as reasonably possible
following the receipt of the necessary approvals and closing of
the Merger Transaction. This proposed rate reduction is made in
conjunction with the proposal to recover deferred Merger
Transaction costs and costs incurred to achieve merger savings
through amortization over the same period. Customers will also
receive directly the benefit of any fuel savings through the
electric fuel adjustment clause mechanism.
The Company has proposed a two-year freeze for retail
natural gas rates in its Minnesota jurisdiction and a 1.25
percent rate reduction along with a four-year freeze in its
North Dakota jurisdiction. In addition, 38 percent of the
Company's 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 Company and WEC
intend to achieve, but the rate freeze will result in some risk
to the 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 Company's proposal to unilaterally reduce rates and
institute a rate freeze is designed to shield customers from
these uncertainties. This proposal permits customers the
opportunity to immediately begin realizing benefits of the
Merger Transaction notwithstanding these uncertainties.
Further, the four-year rate freeze permits the companies a
reasonable time period to implement the changes necessary to
achieve the contemplated savings.
The commitment not to increase electric rates does not
prohibit tariff amendments and rate design changes which would
not increase electric net income during the moratorium. NSP
also proposes to continue to apply the Conservation Investment
Program Annual Tracker Mechanism to recover conservation program
costs. 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 recognizes that during the four-year
rate freeze period, it may experience certain significant but
uncontrollable events which necessitate rate changes.
Accordingly, as part of the rate plan proposal, the Company has
identified certain events (large increases in taxes and
government-mandated costs, and extraordinary events) which it
believes should be excepted from the rate freeze. The
exceptions are necessary in order to protect the Company from
major cost increases or events which are beyond its control.
The Company proposes that for these uncontrollable events it be
allowed to file with the Commission during the rate freeze
period for recovery of the costs related to these events.
Both NSP 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.
UTILITY REGULATION AND REVENUES
General
Retail sales rates, services and other aspects of the
Company's operations are subject to the jurisdiction of the
Minnesota Public Utilities Commission (MPUC), the North Dakota
Public Service Commission (NDPSC), and the South Dakota Public
Utilities Commission (SDPUC) within their respective states.
The MPUC also possesses regulatory authority over aspects of the
Company's financial activities including security issuances,
property transfers when the asset value is in excess of
$100,000, mergers with other utilities, and transactions between
the regulated Company and affiliates. In addition, the MPUC
reviews and approves the Company's electric resource plans and
gas supply plans for meeting customers' future energy needs.
The Wisconsin Company is subject to regulation of similar scope
by the Public Service Commission of Wisconsin (PSCW) and the
Michigan Public Service Commission (MPSC). In addition, each of
the state commissions certifies the need for new generating
plants and transmission lines of designated capacities to be
located within the respective states before the facilities may
be sited and built.
Wholesale rates for electric energy sold in interstate
commerce, wheeling rates for energy transmission in interstate
commerce, the wholesale gas transportation rates of Viking, and
certain other activities of the Company, the Wisconsin Company
and Viking are subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC). NSP also is subject to the
jurisdiction of other federal, state and local agencies in many
of its activities. (See "Environmental Matters" herein.)
The Minnesota Environmental Quality Board (MEQB) is
empowered to select and designate sites for new power plants
with a capacity of 50 megawatts (Mw) or more, wind energy
conversion plants with a capacity of 5 Mw or more, and routes
for transmission lines with a capacity of 200 kilovolts (Kv) or
more, as well as evaluate such sites and routes for
environmental compatibility. The MEQB may designate sites or
routes from those proposed by power suppliers or those developed
by the MEQB. No such power plant or transmission line may be
constructed in Minnesota except on a site or route designated by
the MEQB.
NSP is unable to predict the impact on its operating
results from the future regulatory activities of any of the
above agencies. To the best of its ability, NSP works to
understand and comply with all rules and regulations issued by
the various agencies.
Revenues
NSP's financial results depend, in part, on its
ability to obtain adequate and timely rate relief from the
various regulatory bodies, its ability to control costs and the
success of its non-regulated activities. NSP's 1995 utility
operating revenues, excluding intersystem non-firm electric
sales to other utilities of $90 million and miscellaneous
revenues of $60 million, were subject to regulatory jurisdiction
as follows:
Percent
Authorized Return on Common of Total
Equity @ Dec. 31, 1995 Revenues
(Electric
Electric Gas & Gas)
Retail:
Minnesota Public Utilities Commission 11.47% 11.47% 74.1%
Public Service Commission of Wisconsin 11.4** 11.4** 14.7
North Dakota Public Service Commission 11.50 14.0 5.1
South Dakota Public Utilities Commission * 3.1
Michigan Public Service Commission 12.25 14.5 0.6
Sales for Resale - Wholesale, Viking Gas
and Interstate Transmission: Federal
Energy Regulatory Commission * * 2.4
Total 100.0%
* Settlement proceeding, based upon revenue levels granted with
no specified return.
** Return authorized for 1996 is 11.3 percent.
General Rate Filings
General rate increases (other than fuel and resource
adjustment rate changes) requested and granted in previous years
from various jurisdictions were as follows (note that 1992,
1993, 1994 and 1995 amounts represent annual increases
(decreases) effective in those years, while 1991 increases
represent annual increases requested in that year even if
effective in a subsequent year):
Annual Increase/(Decrease)
Year Requested Granted
(Millions of dollars)
1991 118.7 68.0
1992 ----- ----
1993 166.6 101.5
1994 (1.0) (1.0)
1995 (0.8) (0.8)
The following table summarizes the status of general
rate increases (decreases) for rates effective in 1995.
Annual Increase/(Decrease)
Requested Granted Status
(Millions of dollars)
Electric
North Dakota-Retail* (0.8) (0.8) Order Issued (May
10, 1995)
Gas 0.0 0.0
Total 1995 Rate
Programs (0.8) (0.8)
* Does not include a refund to residential customers of
approximately $1.5 million for the period Jan. 1, 1994,
through June 1, 1994.
Ratemaking Principles in Minnesota and Wisconsin
Since the MPUC assumed jurisdiction of Minnesota
electric and gas rates in 1975, several significant regulatory
precedents have evolved. The MPUC accepts the use of a forecast
test year that corresponds to the period when rates are put into
effect and allows collection of interim rates subject to refund.
The use of a forecast test year and interim rates minimizes
regulatory lag.
The MPUC must order interim rates within 60 days of
a rate case filing. Minnesota statutes allow interim rates to
be set using (1) updated expense and rate base items similar to
those previously allowed, and (2) a return on equity equal to
that granted in the last MPUC order for the utility. The MPUC
must make a determination on the application within 10 months
after filing. If the final determination does not permit the
full amount of the interim rates, the utility must refund the
excess revenue collected, with interest. To the extent final
rates exceed interim rates, the final rates become effective at
the time of the order and retroactive recovery of the difference
is not permitted. Generally, the Company may not increase its
rates more frequently than every 12 months.
Minnesota law allows Construction Work in Progress
(CWIP) in a utility's rate base instead of recording Allowance
for Funds Used During Construction (AFC) in revenue requirements
for rate proceedings. The MPUC has exercised this option to a
limited extent so that cash earnings are allowed on small and
short-term projects that do not qualify for AFC. (For the
Company's policy regarding the recording of AFC, see Note 1 of
Notes to Financial Statements under Item 8.)
The PSCW has a biennial filing requirement for
processing rate cases and monitoring utilities' rates. By June
1 of each odd-numbered year, the Wisconsin Company must submit
filings for calendar test years beginning the following January
1. The filing procedure and subsequent review generally allow
the PSCW sufficient time to issue an order effective with the
start of the test year.
The PSCW reviews each utility's cash position to
determine if a current return on CWIP will be allowed. The PSCW
will allow either a return on CWIP or capitalization of AFC at
the adjusted overall cost of capital. The Wisconsin 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 in Effect
The Company's retail electric rate schedules, and
most of the Wisconsin Company's wholesale rate schedules,
provide for adjustments to billings and revenues for changes in
the cost of fuel and purchased energy. Although the lag in
implementing the billing adjustment is approximately 60 days, an
estimate of the adjustment is recorded in unbilled revenue in
the month costs are incurred. The Company's wholesale electric
sales customers remaining with NSP do not have a fuel clause
provision in their contracts. In lieu of fuel clause recovery,
the contracts instead provide a fixed rate with an escalation
factor. The Wisconsin Company calculates the wholesale electric
fuel adjustment factor for the current month based on estimated
fuel costs for that month. The estimated fuel cost is adjusted
to actual the following month.
In September 1995, the MPUC approved a variance of
Minnesota fuel adjustment clause rules to specifically allow for
the inclusion of total wind purchase power costs and biomass
related energy costs in the fuel adjustment clause. The Company
must request approval for renewal of this variance annually.
The Company is obligated by legislative mandate to purchase 425
Mw of wind generated energy and 125 Mw of farm-grown closed-loop
bio-mass generated energy by 2002.
The Wisconsin Company's automatic retail electric
fuel adjustment clause for Wisconsin customers was eliminated
effective in 1986. The clause was replaced by a limited-issue
filing procedure. Under the procedure, the Wisconsin Company
may elect to file or be required to file for a change in rates
(limited to the fuel issue) following an annual deviation in
fuel costs of 2 percent or more. The adjustment approved is
calculated on an annual basis, but applied prospectively.
Effective Jan. 1, 1996, the fuel costs that are monitored
include certain fuel costs including demand costs for sales and
purchased power, which had been excluded prior to that date.
Gas rate schedules for the Company and the Wisconsin
Company include a purchased gas adjustment (PGA) clause that
provides for rate adjustments for changes in the current unit
cost of purchased gas compared to the last costs included in
rates.
By September 1 of each year, the Company is required
by Minnesota statute to submit to the MPUC an annual report of
the Purchased Gas Adjustments (PGA) for each customer class by
month for the previous year commencing July 1 and ending June
30. The report verifies whether the utility is calculating the
adjustments properly and implementing them in a timely manner.
In addition, the MPUC review includes an analysis of procurement
policies, cost-minimizing efforts, rule variances in effect or
requested, retail transportation gas volumes, independent
auditors' reports, and the impact of market forces on gas costs
for the coming year. The MPUC has the authority to disallow
certain costs if it deems the utility was not prudent in its gas
procurement activities. The MPUC allowed full recovery of gas
costs in response to the June 30, 1994, filing. The MPUC's
determination regarding the filing for the year ended June 30,
1995, is pending.
In August 1995, the MPUC initiated an investigation
- -- an industry-wide proceeding which will be open to
participation from any interested party -- to examine whether
the PGA mechanism is still appropriate for gas utilities based
on the recent changes in the competitive environment in the gas
utility industry and the authorization of performance-based gas
purchasing regulation. The MPUC requested comments on the
continued need for the PGA mechanism. The Company has filed
comments supporting the continued use of the PGA, but urging the
use of performance-based PGA mechanisms. An MPUC decision on
the matter is pending.
The PSCW scheduled a generic hearing in March 1996
to consider an incentive-based gas cost recovery adjustment
clause to replace the current purchased gas cost recovery
adjustment clause. The incentive-based mechanism would allow
recovery of fluctuations in gas costs based on an index, such as
the spot market price. The new method would allow the Wisconsin
Company to absorb the additional charge or benefit related to
any difference between actual gas costs incurred and the index
used for recovery. A PSCW decision is pending.
The Wisconsin Company's gas and retail electric rate
schedules for Michigan customers include Gas Cost Recovery
Factors and Power Supply Cost Recovery Factors, which are based
on 12 month projections. After each 12 month period, a
reconciliation is submitted whereby over-collections are
refunded and any under-collections are collected from the
customers.
Viking is a transportation-only interstate pipeline
and provides no sales services. As a result, Viking terminated
its PGA clause effective Nov. 1, 1993. Natural gas fuel for
compressor station operations is provided in-kind by
transportation service customers.
Resource Adjustment Clauses in Effect
In October 1994, the Company filed with the MPUC a
petition for a miscellaneous rate change approving the
implementation of an annual recovery mechanism for deferred
electric conservation and energy management program
expenditures. On Feb. 23, 1995, the MPUC voted to approve
recovery of $41 million under a new electric rate adjustment
clause for the period May 1995 through June 1996. Thereafter,
the Company would be required to request a new cost recovery
level annually. This decision allows for accelerated recovery
of conservation and energy management program expenditures which
is desirable because it lessens the risk for future stranded
costs resulting from electric industry restructuring. Beginning
in May 1995, a 2.45 percent surcharge to customer's bills
appeared as a line item entitled "resource adjustment." A
similar rate adjustment clause was approved for an annual
recovery rate of $3.7 million in deferred and current gas
conservation and energy management program expenditures
beginning with November 1995 billings. In January 1996, a
number of changes to the Company's regulatory deferral and
amortization practices for Minnesota electric conservation
program expenditures were approved. These changes allow the
Company to expense rather than amortize new conservation
expenditures beginning in 1996 and to increase its recovery of
electric margins lost due to conservation activity. In
addition, the Company received approval for 1996 and 1997
conservation expenditures at levels lower than 1995. On April
1, 1996, the Company expects to file for annual changes to the
Minnesota electric conservation rate adjustment clause,
incorporating the changes in January 1996, with an effective
period of July 1, 1996, through June 30, 1997. These
conservation cost recovery changes are intended to avoid a
significant delay between the time when costs are incurred and
their recovery in rates.
Rate Matters by Jurisdiction
Minnesota Public Utilities Commission (MPUC)
In 1991, the Minnesota legislature passed a law
which granted the MPUC discretionary authority to approve a rate
adjustment clause for changes in certain costs (including
property taxes, fees and permits) incurred by Minnesota public
utilities. In addition, the MPUC may approve a utility's use of
the rate adjustment clause for billing customers if certain
conservation expenditure levels are met. During 1995, the
Company filed with the MPUC a request to make use of the rate
adjustment clause to recover increased property tax costs from
its retail gas customers in Minnesota. The MPUC denied the
Company's request. No additional request to make use of the
rate adjustment clause for the Company's electric or gas
customers is currently pending with the MPUC.
In October 1994, as part of a response to 1994
Minnesota legislation related to fuel storage at the Prairie
Island nuclear plant, the Company filed a miscellaneous rate
change proposal with the MPUC which reflects a 50 percent
discount on the first 300 kilowatt hours (Kwh) consumed each
month by qualified low-income residential customers. In
December 1994 the MPUC approved the Company filing. As a
result, the Low Income Discount Rate became effective beginning
with the October 1994 billing month for qualifying customers,
with rate adjustments designed to recover from other customers
the costs of the discount becoming effective Jan. 4, 1995. The
ruling also eliminated the Conservation Rate Break and
restructured the rates between customer classes, but did not
significantly change overall revenue levels.
Approximately 35,000 of the Company's customers
received assistance totaling more than $5 million from federally
funded Low Income Household Energy Assistance Programs (LIHEAP)
operated by the state of Minnesota in 1995. Other states served
by NSP have similar programs. The federal LIHEAP program is
currently facing significant opposition in securing funding to
continue operations. Qualification for the Company's Low Income
Discount Rate is based on eligibility for LIHEAP. The state of
Minnesota would continue to certify eligibility even if LIHEAP
is not funded. Management believes reductions in federal
funding for LIHEAP exceeding 30 percent may result in an
increase in the Company's uncollectible accounts for customers
who cannot obtain other sources of assistance.
Gas utilities in Minnesota are also required to file
for a change in gas supply contract levels to meet peak demand,
to redistribute demand costs among classes, or exchange one form
of demand for another. The Company filed in October 1995 to
increase its demand entitlements due to projected increases in
firm customer count, to increase the Minnesota jurisdictional
allocation of total demand entitlements, effective Nov. 1, 1995,
and to recover the demand entitlement costs associated with the
increase in transportation and storage levels in its monthly
PGA's. The MPUC approved this filing on March 7, 1996.
In April 1995, the MPUC opened up the rulemaking
process to amend, repeal, or replace existing rules governing
customer service standards for gas and electric utilities. The
MPUC solicited comments from interested parties in June 1995.
The MPUC formed an advisory task force in August 1995
representing interests from electric and gas utilities, low and
fixed income consumer advocate groups, other state of Minnesota
agencies and other various rate payer classes. Certain parties
are proposing changes to the MPUC customer service rules that
have the potential to increase the Company's costs associated
with managing and collecting customer accounts. Examples of
proposed changes are provisions to require NSP to have a signed
contract for service, restrict collection of past-due bills to
only the party(s) named on the bill, and to prohibit the Company
from collecting a deposit for utility service from a low-income
customer. The ultimate outcome of the rulemaking process is
unknown at this time.
On Aug. 4, 1995 the Company filed for MPUC approval
of the Merger Transaction with WEC. The Company proposed a rate
plan which would reduce electric rates by 1.5 percent starting
Jan. 1, 1997, or after receipt of all regulatory approvals and
a four-year rate freeze thereafter, except for certain
uncontrollable events. The rate plan was modified in March 1996
to also provide for a two-year freeze in gas rates. The
proposed rate plan also included a request for deferred
accounting and rate recovery of the costs associated with the
Merger Transaction. Initial comments from the Department of
Public Service, which recommended that the MPUC approve the
Merger Transaction, and other interested parties were filed on
Jan. 16, 1996. The Company's reply comments were filed on March
1, 1996. The MPUC's decision on the Merger Transaction approval
filing is expected in the third or fourth quarter of 1996.
No general rate filings are anticipated in Minnesota in 1996.
North Dakota Public Service Commission (NDPSC)
In August 1994, the Company applied to the NDPSC for
an annualized electric rate reduction of $3.6 million to reflect
a correction in cost allocations to the North Dakota
jurisdiction. In November 1994, the NDPSC approved the
Company's request to make refunds to customers, effectively
implementing the reduction as of June 1, 1994. These refunds
were accrued in 1994 and paid in February 1995. In May 1995,
the NDPSC approved a refund to residential customers of
approximately $1.5 million for the period Jan. 1, 1994 through
June 1, 1994 to reflect corrections to cost allocations for that
period. This refund was accrued in 1994 and paid in June 1995.
Also,the NDPSC approved an annualized rate reduction of $750,000
for North Dakota commercial and industrial electric customers,
which was effective prospectively from June 1, 1995.
On Aug. 4, 1995, the Company filed for NDPSC
approval of the Merger Transaction with WEC. The Company
proposed a rate plan which would reduce electric rates by 1.5
percent on Jan. 1, 1997, or after the close of the Merger
Transaction, and implement a four-year rate freeze thereafter,
with certain exceptions. A 1.25 percent rate reduction and a
four-year rate freeze in gas rates was also proposed. Public
hearings on the Merger Transaction were held in Minot, Grand
Forks and Fargo, North Dakota in November and December 1995. A
technical hearing was held in March 1996. The NDPSC's decision
is expected on the Merger Transaction approval filing later in
1996.
At a hearing in December 1995, the NDPSC approved
the phase-out of the use of deferred accounting for conservation
program costs. Effective retroactively to Jan. 1, 1995, the
Company will expense conservation program costs related to North
Dakota operations in the year the costs are incurred. This
change increased expenses by $1.7 million in 1995 and is
expected to increase 1996 expenses by a similar amount. Costs
incurred prior to 1995 will continue to be amortized in
jurisdictional expenses.
On Jan. 17, 1996, the Company filed a plan with the
NDPSC for a $485,000 annual reduction in base gas rates in North
Dakota. This plan responds to a NDPSC staff audit of gas
earnings for this jurisdiction for the years 1991 to 1995. The
Company also proposed to adjust its base cost of gas to more
current levels and make modifications to its PGA and annual gas
cost true-up mechanism. The changes are proposed to be
effective prospective from the date of the NDPSC order approving
the plan. NDPSC action is pending. This reduction would be in
addition to the merger-related gas rate reductions.
No other general rate filings are anticipated in
North Dakota in 1996.
South Dakota Public Utilities Commission (SDPUC)
There were no general rate filings in South Dakota
in 1995. On Sept. 8, 1995, the SDPUC determined that it did not
have jurisdiction to approve or deny the Merger Transaction with
WEC. However, a rate filing to reflect merger savings in
electric rates is expected on or around the time of the
consummation of the Merger Transaction. No other general rate
filings are anticipated in South Dakota in 1996.
Public Service Commission of Wisconsin (PSCW)
On June 1, 1995, the Wisconsin Company filed with
the PSCW for a $2.7 million increase, or 3.6 percent, in natural
gas rates and no change in electric rates to be effective Jan.
1, 1996. On Oct. 6, 1995, the PSCW ordered a $4.8 million
decrease, or approximately 1.7 percent on an annual basis, in
the Wisconsin Company's retail electric rates. The new rates
took effect Jan. 1, 1996. On Dec. 21, 1995, the PSCW ordered a
$2.5 million increase, or approximately 3.4 percent on an annual
basis, in the Wisconsin Company's retail gas rates and a return
on common equity of 11.3 percent to be effective Jan. 1, 1996.
The Wisconsin Company and WEC filed for approval of
the Merger Transaction on Aug. 4, 1995. WEC requested deferred
accounting treatment and rate recovery of costs associated with
the proposed merger. Rate plans were filed that proposed a 1.5
percent annual retail electric rate reduction and a $4.2 million
annual reduction in gas rates (of which $.2 million relates to
the Wisconsin Company) at the time of the merger and four-year
rate freezes thereafter with certain exceptions. On March 15,
1996, the Wisconsin Company filed full stand-alone rate cases
for a 1997 test year on an unmerged basis. This special filing
was requested by the PSCW to set a baseline cost for evaluating
savings associated with the Merger Transaction. The Wisconsin
Company filing described revenue deficiencies for both electric
and gas utilities, however no rate increases were requested.
The Wisconsin Company intends to attempt to manage its cost
levels to avoid such rate increases. On March 18, 1996, the
Wisconsin Company filed testimony and exhibits supporting the
original Aug. 4, 1995 Merger Transaction filing. Technical
hearings on the merger are expected in July 1996. The PSCW's
decision on the merger approval filing is expected in the fourth
quarter of 1996.
The Wisconsin Company is scheduled to file a general
rate case in June 1997, for rates effective in 1998, as required
by the PSCW biennial filing requirement.
Michigan Public Service Commission (MPSC)
The Wisconsin Company and WEC filed for MPSC
approval of the Merger Transaction on Aug. 4, 1995. Electric
and gas rate plans were filed that proposed a rate reduction and
a four-year rate freeze. The MPSC's decision on the Merger
Transaction is expected in the first half of 1996.
Electric Transmission Tariffs and Settlement (FERC)
In 1990, NSP filed a transmission services tariff
for certain transmission customers. New rates were effective
under the filing, subject to refund, for the period Dec. 29,
1990, through Oct. 31, 1994. NSP has recorded an estimated
liability at Dec. 31, 1995, for potential transmission rate
refunds under this tariff based on the FERC order dated Sept.
21, 1993. On Feb. 5, 1996, the FERC denied NSP's request for
rehearing and required NSP to submit a refund compliance filing
in the amount of $1.7 million. This refund amount is
approximately the same as estimated liabilities recorded.
In March 1994, NSP filed a revised open access
transmission tariff with the FERC. On May 25, 1994, the FERC
accepted the filing, with the new rates effective Nov. 1, 1994,
subject to refund. The FERC also ruled the tariff would be
subject to the requirement that NSP offer transmission service
using terms and conditions comparable to its 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 Order of Settlement. Although there
are no genuine issues of material fact and all parties support
certification of the Settlement, the ALJ stated the Settlement
is contested since FERC Staff and Electric Clearinghouse list
numerous provisions that need to be modified in response to the
issuance of proposed rulemaking referred to as the Mega NOPR.
(See discussion and definition of Mega-NOPR below.) The ALJ
further stated the Settlement is 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 Feb. 14, 1996, subject to the outcome
of the final rule, in 1996. The revenue effect on the Company
is an increase of approximately $200,000 per year. The new
tariff allows NSP 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 a 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.
The FERC is proposing to require utilities to unbundle power
sales from transmission. This "unbundling service" requirement
would apply only to new requirements contracts and new
coordination trade contracts. The FERC did not require
utilities to divest or separate their generation businesses from
their transmission businesses. The FERC also proposes to not
disrupt any existing power or transmission contracts.
The Mega-NOPR would apply to all utilities under the
FERC's jurisdiction and would require each utility to file
individual tariffs. The FERC also seeks to require non-
jurisdictional transmission providing entities (such as
municipals and cooperatives) to offer open access by including
a reciprocity clause in their 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 the 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 NSP's
transmission tariff into the second stage.
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, the FERC further clarified its
guidelines for utilities to recover stranded investment costs
due to facilitation of open access to a competitive market. The
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, the 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 the FERC will entertain utilities' requests for
stranded-cost recovery even after a state has addressed the
case. 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 its response to the RIN and Mega NOPR proposals,
NSP filed comments which indicated support for FERC's open
access objective and for FERC's position that it should be a
backstop for the recovery of stranded costs. NSP also asserted
that its open access transmission tariffs filed in 1994 comply
with the spirit of the Mega-NOPR.
Proposed Merger Approval Proceedings (FERC)
On July 10, 1995, the Company and WEC filed an
application and supporting testimony with the FERC seeking
approval of the Merger Transaction to form Primergy Corporation.
The filing consisted of the merger application, the proposed
joint transmission tariff, and an amendment to the Company's
Interchange Agreement with the Wisconsin Company. On Sept. 11,
1995, several parties, who had previously filed for intervenor
status in the FERC Merger Transaction approval application
filing, filed interventions and protests. On Oct. 10, 1995, the
Company and WEC replied to petitions for intervention and
requests for hearings. On or about Oct. 25, 1995, intervenors
filed responses to the Company and WEC's reply. On Nov. 9,
1995, the Company and WEC filed a response to the intervenors
reply comments. Additional intervenor comments were filed on
Nov. 22, 1995. The Company has met all previously stated FERC
criteria for merger approvals.
The issues raised by intervenors with respect to the
merger application at the FERC are primarily related to two
areas: the impact on competition and the nature of the cost
savings. The Company has settled with several intervenors and
is continuing to meet with interested parties in the FERC
proceeding, seeking resolution of the intervenor issues.
On Jan. 31, 1996, the FERC issued a ruling which put
the merger approval filing on an accelerated schedule. The FERC
set only one of six merger issues raised by intervenors to a
hearing. The FERC ordered a hearing regarding the effect of the
proposed merger on bulk power competition. The FERC
commissioners ordered the judge's initial decision by Aug. 30,
1996, and briefs on exception by Sept. 30, 1996. In March 1996,
the PSCW requested that the FERC broaden the scope of the merger
application hearing to evaluate whether the proposed merger will
impair effective state oversight of retail rates. While the
Company expects the FERC's decision on the merger approval
filing in the fourth quarter of 1996, the approval process may
extend beyond 1996.
In February 1996, the Company and WEC agreed to
freeze wholesale rates for four years subsequent to the Merger
Transaction.
Intervenors argue that competition will be adversely
affected because the Company and WEC will constrain the
transmission system at the interconnections between the NSP
system and a group of upper Wisconsin and northern Michigan
utilities, allowing the Company and WEC to increase the price
they charge for energy. In response to the intervenor concerns,
the Company and WEC have committed to make whatever changes are
required by FERC in its open access proceeding to ensure the
appropriate level of access is achieved. The Company and WEC
have filed to expand the capacity of the interconnections and
further expansion is being pursued. When the interface is
constrained, any economic energy sales that the Company and WEC
make into the upper Wisconsin and northern Michigan utilities
will be at incremental cost. The Company and WEC will waive
their AES (native load) and Mid-Continent Area Power Pool (MAPP)
line loading relief procedure 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, the Company and WEC are willing to establish
an unaffiliated entity as an Independent Tariff Administrator
that will schedule transmission use and otherwise ensure that
transmission is provided on a nondiscriminatory basis. (See
discussion of the negotiations to convert MAPP to a Regional
Transmission Group at the "Electric Utility Operations -
Capability and Demand" section herein.)
Other Wholesale Rate Proceedings (FERC)
In December 1993, the Company, in compliance with a
FERC order in the Central Maine case requiring that the FERC
approve all interstate, inter-utility contracts, filed over 300
such contracts with the FERC for review. The FERC established
76 separate dockets for review. Absent FERC acceptance, the
contracts could have been declared null and void, possibly
resulting in full refunds for all amounts paid. The FERC has
accepted each of the 76 dockets with little or no change. The
Company completed full resolution of the Central Maine
compliance filings in 1995.
ELECTRIC UTILITY OPERATIONS
Competition
NSP'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 NSP cannot predict
the extent to which its future business may be affected by
supply, relative cost or promotion of other electricity or
energy suppliers, NSP 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
the FERC and the Mega-NOPR issued by the FERC (as discussed in
"Utility Regulation and Revenues," 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. NSP 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. NSP's tariff filed
in 1994 and settled in 1995, preceded the FERC's pro-forma
tariff and provided significant input to its development. The
final rules the 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 the 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 NSP cannot be predicted at this
time.
NSP had municipal wholesale revenues from sales of
electricity of approximately $44 million in 1995 and
approximately $57 million in 1994. The trend of increased
competition has resulted in changes in the negotiation of
contracts with municipal wholesale customers. In the past
several years, these customers have begun to evaluate a variety
of energy sources to provide their power supply. While the full
impact of competition on this part of NSP's business is unknown
at this time, the following changes have occurred.
In 1990, 16 of the Company's 19 municipal wholesale
customers in Minnesota began reviewing their long-term power
supply options. Eight customers created a joint action group,
the Minnesota Municipal Power Agency (MMPA), to serve their
future power supply needs. An additional wholesale customer
became an associate member of the MMPA. In 1992, these nine
municipal customers notified the Company of their intent to
terminate their power supply agreements with the Company
effective July 1995 or July 1996. In July 1995, seven of these
nine customers took power supply service from MMPA and are now
transmission only customers of the Company. The loss of these
seven customers in 1995 resulted in a revenue decrease of
approximately $12 million from 1994 levels. The two other
wholesale customers will terminate their power supply service
with the Company in July 1996 and are expected to become
wheeling customers of the Company. These two customers provided
revenues of $3.6 million in 1995. These nine customers
affiliated with MMPA are expected to provide estimated annual
wheeling revenues of nearly $3 million.
Of the remaining 10 municipal wholesale customers of
the Company, nine have full requirements contracts with terms
expiring in the years 1999 through 2005, with three- to four-
year cancellation notice provisions. The other customer became
a member of Central Minnesota Municipal Power Agency (CMMPA) in
1995. CMMPA currently has seven members and the Company has
provided the energy requirements to CMMPA since it was formed in
1992. The Company recently won a bid to continue supplying
energy to CMMPA for six years beginning in March 1996. In
addition, during 1995, the Company signed contracts with three
other municipals to provide energy and some capacity for terms
ranging from five to 10 years, beginning in the years 1995
through 1998. The annual revenues from these three contracts
are estimated to be approximately $1 million.
The Wisconsin Company had 10 wholesale customers at
Dec. 31, 1995, with revenues of approximately $18 million in
1995. In 1995, the Wisconsin Company offered its wholesale
customers discounts from the FERC authorized rate. Seven of the
10 municipal customers elected to renew or extend their contracts to
receive these discounts. As part of the settlement agreement
between NSP, WEC and the Wisconsin intervenors in the Merger
Transaction approval filing, the cities of Medford and Rice Lake
have a five year power supply agreement. For the first year the
two cities receive 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.
In 1993, the Company signed an electric power
agreement with Michigan's Upper Peninsula Power Company with
service beginning in 1998. (See Management's Discussion and
Analysis under Item 7 for more discussion.)
In addition, with the development of the electric
industry competition, the Company has experienced an increase in
requests for the use of its transmission system. A large
portion of these requests can be identified as due to the
increase in FERC approved power marketers. In 1995, the Company
filed 23 transmission service agreements for FERC approval,
including 10 with power marketers. The annual transmission
revenue in 1995 from this activity was immaterial. However, in
1996 revenues are expected to increase due to growth of power
market activity in this region. Competition from FERC approved
power marketers is expected to increase. As of Dec. 31, 1995,
power marketers had filed 175 applications with the FERC and 151
of the applications had been approved by the FERC including 24
from utility affiliates (one of which is Cenergy). For the year
1995, power marketers in the United States made transactions of
26 million megawatt hours. The ultimate impact on NSP's sales
and purchases of power, and NSP's power marketing revenue (from
Cenergy activity) due to power marketing activity is not
determinable.
Many states are currently considering retail
competition. Regulators in Minnesota, Wisconsin and North
Dakota 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 Wisconsin Company
filed the following recommendations: (i) competition should be
phased in for retail markets by customer classes, with all
customers having choice of supplier by 2001, (ii) the generation
segment of the industry should be deregulated by 2001, (iii)
prudent stranded costs should be recovered prior to the advent
of retail wheeling and (iv) 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.
In Minnesota, regulators have developed draft
principles for electric industry restructuring to provide a
framework from which to proceed. One of the principles supports
an open transmission system and the establishment of a robust
wholesale competitive market. At this time, Minnesota
regulators have not established definitive timelines for
industry restructuring or changes. NSP believes the transition
to a more competitive electric industry is inevitable and
beneficial for all consumers. NSP supports an orderly and
efficient transition to an open, fair and competitive energy
market for all customers and suppliers. The timing of
regulatory actions and their impact on NSP cannot be predicted
and may be significant.
Michigan also has a retail wheeling experiment,
which is currently being challenged in court. The experiment is
limited to its two largest utilities and customers larger than
$50 million. The Wisconsin Company's customers are not included
in this experiment.
The Company is facing potential competition from a
retail customer's proposed cogeneration project. Koch Refining
Co. (Koch), the Company's largest customer which provides
approximately $30 million in annual revenues to NSP, proposes to
build a cogeneration plant that would burn petroleum coke, a
refinery byproduct, to produce between 180 and 250 Mw of
electricity. This would be enough supply for Koch's own use
plus an additional 80 to 150 Mw to be sold on the wholesale
market. Koch is requesting a legislative exemption from
Minnesota personal property tax for its plant. While NSP
supports the reduction of taxes on generating facilities, it
believes any reduction should be applied to all generating
facilities so that there are no unfair tax advantages available
to some generators. This project has several implications for
NSP: 1) Koch could become a competitor as it seeks markets for
its excess capacity; 2) Koch's capacity would also represent a
potential power source for NSP; and 3) Koch's plan represents a
potential loss of a large retail customer. The project's
anticipated three-year lead time will allow NSP to respond
appropriately.
NSP has proposed to fill future needs for new
generation through competitive bid solicitations. The use of
competitive bidding to select future generation sources allows
the Company to take advantage of the developing competition in
this sector of the industry. The Company's proposal, which has
been approved by both the MPUC and the PSCW, allows NRG to bid
in response to Company solicitations for proposals. The Company
is also seeking permission from the MPUC to include its own
generation construction department as a bidder in the
competitive process.
Retail competition represents yet another
development of a competitive electric industry. Management
plans to continue its ongoing efforts to be a low-cost supplier
of electricity and an active participant in the more competitive
market for electricity expected as a result of the Energy Act.
NSP will continue to work with regulators to complete the tariff
and infrastructure that will support an electric competitive
environment. The proposed merger with WEC is a key strategy in
ensuring competitive prices and high-quality services for
customers. Additional actions the Company is pursuing to
position itself for the competitive environment include:
creative partnership solutions with strategic customers
including communities; focusing on the unique needs of national
account customers; competitive pricing alternatives; improved
reliability; implementation of service guarantees; ease of
customer access including 24 hour, 7 days/week operation;
substantial customer convenience and flexibility improvements
via a new Customer Service System which includes appointment
scheduling upon first contact, improved outage call response,
and a wide array of new billing options; and centralization of
common services and aggressive cost management. In addition,
NSP will compete for service outside its traditional service
area. This process has begun via NSP's Cenergy subsidiary.
Capability and Demand
Assuming normal weather, NSP expects its 1996 summer
peak demand to be 7,326 Mw. NSP's 1996 summer capability is
estimated to be 8,843 Mw, (net of contract sales) including
1,153 Mw (including reserves) of contracted purchases from the
Manitoba Hydro-Electric Board, a Canadian Crown Corporation
(Manitoba Hydro) and 899 Mw of other contracted purchases. The
estimate assumes 7,731 Mw of thermal generating capability and
1,440 Mw of hydro and wind generating capability. Of the total
summer capability, NSP has committed 328 Mw for sales to other
utilities. Of the estimated net capability, including the
interconnection with Manitoba Hydro, 30 percent has been
installed during the last 10 years.
NSP's 1995 maximum demand of 7,519 Mw occurred on
July 13, 1995. Resources available at that time included 7,100
Mw of Company-owned capability and 1,910 Mw of purchased
capability net of contracted sales. Due to the MAPP's penalty
for reserve margin shortfalls and to be prepared for weather
uncertainty at the lowest potential cost, NSP carried a reserve
margin for 1995 of 20 percent. The minimum reserve margin
requirement as determined by the members of the MAPP, of which
NSP is a member, is 15 percent. In March 1996, the members of
MAPP approved a proposal to convert MAPP into a Regional
Transmission Group (RTG). This proposal will now be submitted
to the FERC for approval before April 1, 1996. By converting
MAPP to an RTG, members will have more input into transmission
access within other member's territories. This is one of the
proposals in response to intervenor concerns in the FERC
regulatory approval proceeding of the Company's proposed merger
with WEC. (See "Utility Regulation and Revenues - Rate Matters
by Jurisdiction" herein for more information and Note 15 of
Notes to Financial Statements under Item 8 for more discussion
of power agreement commitments.)
The Company is continuing an extensive performance-
based transmission and distribution reliability program. This
program includes preventative maintenance on transmission and
distribution power lines, improvements to existing equipment and
implementation of new technology. The program focuses on the
leading causes of outages consisting of lightning, trees and
underground cable and also concentrates on reducing the number
of human-error outages. In 1995, the reliability program
resulted in a reduction in the number of outages to the
Company's feeders, which had been the most likely to experience
an outage, from 600 in 1994 to 425 in 1995. The outage count on
the one feeder most likely to experience an outage was reduced
from 24 in 1994 to 12 in 1995. Reliability goals for 1996 have
already been formulated, and include emphasis on reliability-
focused maintenance programs, improved restoration processes,
and improved customer communication/access.
In 1994, NSP signed a long term power purchase
contract for 245 Mw of annual capacity for 30 years. The
purchase will be from a natural gas-fired combined cycle
facility that NSP can dispatch as system requirements dictate.
NSP expects the facility to be available in May 1997.
The Company filed an electric resource plan with the
MPUC on July 3, 1995. The plan shows how the Company intends to
meet the increased energy needs of its electric customers and
includes an approximate schedule of the timing of resources to
meet such needs. The plan contains: conservation programs to
reduce the Company's peak demand and conserve overall
electricity use; economic purchases of power; and programs for
maintaining reliability of existing plants. It also includes an
approximate schedule of the timing of such resource needs. The
plan does not anticipate the need for additional base-load
generating plants during the balance of this century and assumes
that all existing generating facilities will continue operating
through their license period or useful life. The plan also
assumes that modifications will be made to the Monticello
nuclear generating facility to increase its capacity by 46 Mw by
1997.
The following resource needs were included in the
resource plan. The plan does not specify the precise technology
to meet these needs, but does suggest energy source options.
Cumulative Mw Resource Needs By Type vs. Base of 1995
1998 2002 2006 2010
Renewables* 200 (40) 525 (212) 525 (212) 525 (212)
Peak 0-71 63-505 415-822 415-1,067
Intermediate 0-148 0-581 579-734 579-889
Base 0 0 247-1,253 927-2,176
Demand Side Management 512 968 1,348 1,657
Total 552-771 1,243-2,266 2,801-4,369 3,790-6,001
* Includes the Prairie Island legislation mandate of
an additional 400 Mw of wind generation and 125 Mw of biomass
generation. The amounts shown in parentheses are the estimated
MAPP accredited capacity values at the time of system peak
demand. The MAPP accreditation procedure for wind is intended
to measure wind generation's contribution to system reliability
at the time of system peak demand. Because wind generation is
a variable resource the accredited capacity is less than the
installed capacity.
The resource plan proposes to satisfy the above
resource needs through a combination of the following options:
Sources of Energy to Meet Needs
- Continued operation of existing generation facilities.
- Demand reduction of an additional 1,400 Mw by 2010
through conservation and load management.
- 425 Mw of wind generation in service by 2002.
- 125 Mw of biomass generation in service by 2002.
- Acquisition of competitively priced resources to
meet changing needs, i.e. competitive bidding.
The Company intends to seek competitive bids in 1996
for the following resources: 100 Mw of wind generation; 75 Mw of
biomass generation; 100 Mw of peaking generation; 200 Mw of
intermediate generation and 600 Mw of baseload generation. If
the Koch Refining Co. proposed cogeneration project is built, as
discussed previously, the Company's resource plan and bidding
schedules might be affected.
In connection with the approval of used nuclear fuel
storage facilities at the Company's Prairie Island generation
plant, legislation was enacted in 1994 which established certain
resource commitments, as discussed in Note 15 to the Financial
Statements under Item 8 and "Electric Utility Operations -
Nuclear Power Plants - Licensing, Operation and Waste Disposal,"
herein. The Company has taken steps to comply with the
requirements of these resource commitments. Twenty-five Mw of
third party wind generation has been fully operational since May
1, 1994. With respect to the additional 100 Mw of wind energy
to be under contract by the end of 1996, the Company has
obtained a site designation from the Minnesota Environmental
Quality Board (MEQB), and selected Zond Systems, Inc. to supply
the wind energy. The Company must now secure wind rights from
an unsuccessful bidder, which has indicated it will not
voluntarily transfer the wind rights. The Company has commenced
litigation to expedite resolution of the wind rights dispute.
Siting and design activities are proceeding while wind rights
acquisition efforts continue. The Company also used a
competitive bid solicitation to acquire 50 Mw of farm-grown
closed-loop biomass generation. An independent evaluator
reviewed proposals from bidders regarding this 50 Mw of farm-
grown closed-loop biomass generation and made a recommendation
to the Company in January 1996. On March 7, 1996, the Company
submitted a filing with the MPUC rejecting all bids primarily
due to price concerns. The Minnesota Legislature is considering
several bills which could affect the existing biomass resource
commitment. In order to include any legislative changes, the
Company is deferring its decision on future biomass generation
plans until after the expected close of the current Minnesota
legislative session in April 1996. The Company's construction
commitments disclosed in "Capital Spending and Financing",
herein, include the known effects of the 1994 Prairie Island
legislation. The impact of the legislation on power purchase
commitments is not yet determinable.
Minnesota utilities are required under a 1993
Minnesota law to use values established by the MPUC, which
assign a range of environmental costs with each method of
electricity generation that is not part of the price of
electricity, when evaluating and selecting generation resource
options. These values are known as environmental externalities.
NSP, along with several other parties, is currently
participating in a proceeding initiated by the MPUC to establish
final externality values. An order from this proceeding is not
expected until mid-1996. Pending the outcome of this
proceeding, utilities are required to use interim externality
values which were set by the MPUC in early 1994. The critical
issue and uncertainty for NSP is the extent to which the use of
these externality values will cause NSP to select higher priced
generation resources and increase NSP's cost to provide
electricity. The value assigned to the carbon dioxide factor
will most likely have the greatest impact on NSP in terms of
costs added for new coal or gas-fired plants. The high end of
the range of interim externality values add about 1.75 cents per
kwh to a typical new coal plant and about .65 cents per kwh to
a natural gas-fired plant. The carbon dioxide value comprises
about 80 percent to 90 percent of these amounts. NSP will be
affected in 1996 when it issues a Request for Proposal for peak,
intermediate and base plants. Depending on the values
established and how they are applied, externalities could
significantly affect resources available to NSP to meet future
demands for electricity.
NSP continues to implement various Demand Side
Management (DSM) programs designed to improve load factor and
reduce NSP's power production cost and system peak demands, thus
reducing or delaying the need for additional investment in new
generation and transmission facilities. NSP currently offers a
broad range of DSM programs to all customer sectors, including
information programs, rebate and financing programs, and rate
incentive programs. These programs are designed to respond to
customer needs and focus on increasing NSP's value of service
that, over the long term, will help its customer base become
more stable, energy efficient and competitive. During 1995,
NSP's programs reduced system peak demand by approximately 202
Mw. Since 1986, NSP's DSM programs have achieved 1,224 Mw of
summer peak demand reduction, which is equivalent to 16 percent
of its 1995 summer peak demand. In its 1995 Resource Plan and
Conservation Improvement Program (CIP) Filings with the MPUC and
the Minnesota Department of Public Service respectively, the
Company proposed to reduce its DSM expenditures from
approximately 3.5 percent of revenues in 1995 to 2.2 percent of
revenues by 1997. The corresponding long-term energy savings
goals would be reduced by approximately 50 percent, while the
long-term demand savings goals would be reduced by approximately
25 percent. The CIP filing was approved with modification,
requiring the Company to spend 2.8 percent and 2.6 percent of
its annual revenues on DSM in 1996 and 1997, respectively. A
decision on the long-term energy savings goal in the resource
plan is anticipated later in 1996.
In 1994, the MPUC increased the Company's cost
recovery and incentives for DSM by allowing recovery of a
portion of the lost margins due to DSM impacts on electric
revenues. This lost margin recovery, subject to annual review
by the MPUC, was approximately $7 million in 1995 and $3 million
in 1994. In addition, the MPUC allowed the Company to earn $5
million in 1995 and $4 million in 1994 for DSM investment
returns through an incentive program that rewards the attainment
of specified conservation goals.
Energy Sources
For the year ended Dec. 31, 1995, 45 percent of
NSP's Kwh requirements was obtained from coal generation and 30
percent was obtained from nuclear generation. Purchased and
interchange energy provided 21 percent, including 15 percent
from Manitoba Hydro; NSP's hydro and other fuels provided the
remaining 4 percent. The fuel resources for NSP's generation
based on Kwh were coal (57 percent), nuclear (38 percent),
renewable and other fuels (5 percent).
The following is a summary of NSP's electric power
output in millions of Kwh for the past three years:
1995 1994 1993
Thermal plants 33,802 32,710 33,130
Hydro plants 1,049 922 1,001
Purchased and interchange 9,189 9,054 8,541
Total 44,040 42,686 42,672
Many of NSP's power purchases from other utilities
are coordinated through the regional power organization MAPP,
pursuant to an agreement dated March 31, 1972, with amendments
filed in 1994. NSP is one of 58 members in MAPP consisting
of eight investor-owned systems, eight generation and transmission
cooperatives, three public power districts, eight municipal
systems, the Department of Energy'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 by the FERC on Dec. 15, 1994.
Fuel Supply and Costs
Coal and nuclear fuel will continue to dominate
NSP's regulated utility fuel requirements for generating
electricity. It is expected that approximately 97 percent of
NSP's fuel requirements, on a Btu basis, will be provided by
these two fuels over the next several years, leaving 3 percent
of NSP's annual fuel requirements for generation to be provided
by other fuels (including natural gas, oil, refuse derived fuel,
waste materials, renewable sources and wood). 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%
The Company normally maintains between 20 and 50
days of coal inventory depending on the plant site. The Company
has long-term contracts providing for the delivery of up to 100
percent of its 1996 coal requirements. Coal delivery may be
subject to short-term interruptions or reductions due to
transportation problems, weather and availability of equipment.
The Company expects that more than 98 percent of the
coal it burns in 1996 will have a sulfur content of less than 1
percent. The Company has contracts with three Montana coal
suppliers (Westmoreland Resources, Decker Coal Company, and Big
Sky Coal Company) and four Wyoming suppliers (Rochelle Coal
Company, Antelope Coal Company, Kerr-McGee Coal and Black
Thunder Coal Company) for a maximum total of 65 million tons of
low-sulfur coal for the next 5 years. These arrangements are
sufficient to meet the requirements of existing coal-fired
plants. They also permit the Company to purchase additional
coal when such purchase would improve fuel economics and
operations. The Company has options from suppliers for over 100
million tons of coal with a sulfur content of less than 1
percent that could be available for future generating needs.
The plants in the Minneapolis-St. Paul area are about 800 miles
from the mines in Montana and 1,000 miles from the mines in
Wyoming. Coal delivered by rail provides the Company with an
economical source of fuel.
The estimated coal requirements of the Company at
its major coal-fired generating plants for the periods indicated
and the coal supply for such requirements are as follows:
State
Sulfur
Dioxide
Emission
Maximum Amount Contract Approximate Limit
Annual Covered by Expiration Sulfur Pounds Per
Plant Demand Contract Date Content(%)(2) MBTU* Input
(Tons) (Tons)
Black Dog 1,200,000 1,200,000 (1) 0.5 1.3(3)
High Bridge 800,000 800,000 (1) 0.5 3.0
Allen S. King 2,000,000 2,000,000 (1) 0.9 1.6
Riverside 1,300,000 1,300,000 (1) 0.7 2.5(4)
Sherco 8,000,000 8,000,000 (1) 0.5 0.9(5)
13,300,000 13,300,000(6)
*MBTU = Million British Thermal Units
Notes:
(1) Contract expiration dates vary between 1996 and 2005
for western coal, which can provide up to 100 percent
of the required fuel supply for the designated
generating unit. Spot market purchases of other
western coal, and other fuels will provide the
remaining fuel requirements when such purchases would
improve fuel economics. The Company is also burning
petroleum coke as a source of fuel.
(2) This percentage represents the average blended sulfur
content of the combination of fuels typically burned
at each plant.
(3) The Black Dog Fluidized Bed (Unit 2) SO2 limit is 1.2
lb/MBTU.
(4) The SO2 limitation at Riverside Unit 8 is 2.5 lb/MBTU.
The limitation for units 6 and 7 is currently 0.9 lb
SO2/MBTU.
(5) The SO2 limitation at Units 1 and 2 is 70 percent
removal of SO2 input and a maximum emission rate of
0.96 lb SO2/MBTU averaged over 90 days. The SO2
limitation at Unit 3 is 70 percent removal of SO2 input
and a maximum emission rate of 0.60 lb SO2/MBTU
averaged over 30 days. The use of lime and/or
limestone in the plant's scrubbers may be necessary to
achieve these limits.
(6) Annual requirements are expected to range from 11.0 to
13.3 million.
The Company's current fuel oil inventory is adequate
to meet anticipated 1996 requirements. Additional oil may be
provided through spot purchases from two local refineries and
other domestic sources.
To operate the Company's nuclear generating plants,
the Company secures contracts for uranium concentrates, uranium
conversion, uranium enrichment and fuel fabrication. The
contract strategy involves a portfolio of spot, medium and long-
term contracts for uranium, conversion and enrichment. Current
contracts are flexible and cover between 70 percent and 100
percent of uranium, conversion and enrichment requirements
through the year 1997. These contracts expire at varying times
between 1997 and 2005. The overlapping nature of contract
commitments will allow the Company to maintain 70 percent to 100
percent coverage beyond 1997, if appropriate. The Company
expects sufficient uranium, conversion and enrichment to be
available for the total fuel requirements of its nuclear
generating plants. Fuel fabrication is 100 percent committed
through the year 2003. The Company expects the unit cost of
fuel to produce electricity with these nuclear facilities will
be lower than the comparable cost of fuel to produce electricity
with any other currently available fuel sources for the
sustained operation of a generation facility. The cost of
nuclear fuel, including disposal, is recovered in the customer
price of the electricity sold by the Company.
The Company's average electric fuel costs for the
past three years are shown below:
Fuel Costs *
Per Million Btu
Year Ended December 31
1993 1994 1995
Coal** $ 1.12 $ 1.13 $1.11
Nuclear*** .41 .47 .48
Composite All Fuels .87 .89 .87
* Fuel adjustment clauses in its electric rate schedules
or statutory provisions enable NSP to adjust for fuel
cost changes. (See "Utility Regulation and Revenues -
Fuel and Purchased Gas Adjustment Clauses" under Item
1.)
** Includes refuse-derived fuel and wood.
*** See Note 1 to the Financial Statements under Item 8
for an explanation of the Company's nuclear fuel
amortization policies.
Nuclear Power Plants - Licensing, Operation and Waste Disposal
The Company operates two nuclear generating plants:
the single unit, 539 Mw Monticello Nuclear Generating Plant and
the Prairie Island Nuclear Generating Plant with two units
totaling 1,025 Mw. The Monticello Plant received its 40-year
operating license from the Nuclear Regulatory Commission (NRC)
on Sept. 8, 1970, and commenced operation on June 30, 1971.
Prairie Island Units 1 and 2 received their 40-year operating
licenses on Aug. 9, 1973, and Oct. 29, 1974, respectively, and
commenced operation on Dec. 16, 1973, and Dec. 21, 1974,
respectively.
In its most recent ratings of Company nuclear
facilities, the NRC rated the overall performance of both the
Prairie Island and Monticello Plants as excellent. On a scale
of 1 to 3 (1 being the highest), the plants both rate at 1.25,
which is the average of ratings in the areas of plant
operations, maintenance, engineering, and plant support. These
ratings of the NRC's Systematic Assessment of Licensee
Performance (SALP) place the plants in the top quarter of the 18
plants located in the Midwest.
The Prairie Island and Monticello nuclear plants
currently hold the Institute of Nuclear Power Operations' (INPO)
top rating for plant operations and training. The Company is
one of only three utilities in the nation to achieve INPO's top
rating simultaneously at all of its nuclear plants.
The Company previously operated the Pathfinder Plant
near Sioux Falls, SD as a nuclear plant from 1964 until 1967,
after which it was converted to an oil and gas-fired peaking
plant. The nuclear portions were placed in a safe storage
condition in 1971, and the Company began decommissioning in
1990. Most of the plant's nuclear
material, which was contained in the reactor building and fuel
handling building, was removed during 1991. Decommissioning
activities cost approximately $13 million and have been
expensed. A few millicuries of residual contamination remain in
the operating plant.
Operating nuclear power plants produce gaseous,
liquid and solid radioactive wastes. The discharge and handling
of such wastes are controlled by federal regulation. For
commercial nuclear power plants, high-level radioactive waste
includes used nuclear fuel. Low-level radioactive wastes are
produced from other activities at a nuclear plant. They consist
principally of demineralizer resins, paper, protective clothing,
rags, tools and equipment that have become contaminated through
use in the plant.
A 1980 federal law places responsibility on each
state for disposal of its low-level radioactive waste. The law
encourages states to form regional agreements or compacts to
dispose of regionally generated waste. Minnesota is a member of
the Midwest Interstate Low-Level Radioactive Waste Compact
Commission. Following the expulsion of Michigan from the
Midwest Compact in 1991 for failing to make progress, Ohio was
designated the host state. The Ohio legislature in 1995 passed
amendments to the Midwest Compact agreement and established
procedures for the siting of a compact facility. Other member
states must pass the compact amendments. Wisconsin passed the
amendments at the end of 1995. Minnesota will seek passage in
the 1996 legislative session. Following acceptance of the
compact amendments within each member state, Congress is
expected to ratify the compact amendments by 1999. Ohio is
progressing with development of the low-level radioactive waste
disposal facility and expects to complete construction in 2005.
The development costs will be paid by the generators of low-
level radioactive waste within the compact. Currently, the
Barnwell facility, located in South Carolina, has been given
authorization by South Carolina to accept low-level radioactive
waste and the Midwest Compact has authorized its generators to
use the Barnwell facility from July 1, 1995, through June 30,
1996. The use of the Barnwell facility is expected to be
reauthorized on an annual basis through 2005.
The federal government has the responsibility to
dispose of or permanently store domestic used nuclear fuel and
other high-level radioactive wastes. The Nuclear Waste Policy
Act of 1982 requires the Department of Energy (DOE) to implement
a program for nuclear waste management including the siting,
licensing, construction and operation of repositories for
domestically produced used nuclear fuel from civilian nuclear
power reactors and other high-level radioactive wastes. The
Company has contracted with the DOE for the future disposal of
used nuclear fuel. The DOE is currently charging a quarterly
disposal fee based on nuclear electric generation sold. This
fee ranges from approximately $10 million to $12 million per
year, which NSP recovers from its customers in cost-of-energy
rate adjustments. In 1985, NSP paid the DOE a one-time fee of
$95 million for fuel used prior to April 7, 1983. None of the
Company's used nuclear fuel has been accepted by the DOE for
disposal due to the unavailability of a planned federal fuel
storage facility. The Company, along with a group of other
utilities, has commenced litigation against the DOE to ensure
that the federal facility will be available as contracted. (See
Item 3 - Legal Proceedings.) In addition, because of the DOE's
inadequate progress to provide a permanent repository and its
recent disavowal of its obligation, the Minnesota Department of
Public Service is investigating whether continued payments to
fund the DOE's permanent disposal is prudent use of ratepayer
dollars. The outcome of this investigation is unknown at this
time.
The DOE has stated in statute and by contract that
a permanent storage or disposal facility would be ready to
accept used nuclear fuel by 1998. However, indications from the
DOE are that a permanent federal facility will not be ready to
accept used nuclear fuel from utilities until approximately
2010. NSP, with regulatory and legislative approval, has been
providing its own temporary on-site storage facilities at its
Monticello and Prairie Island nuclear plants. In 1979, the
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 does not expect to run out of
storage capacity prior to the end of its current operating
license in 2010. The on-site storage pool for used nuclear fuel
at the Company's Prairie Island Nuclear Generating Plant
(Prairie Island) was filled during refueling in June 1994, so
adequate space for a subsequent refueling was no longer
available. In anticipation of this, the Company, in 1989,
proposed construction of a temporary on-site dry cask storage
facility for used nuclear fuel at Prairie Island. The Minnesota
Legislature (Legislature) considered the dry cask storage issue
during its 1994 legislative session as required by a Minnesota
Court of Appeals ruling in June 1993.
In May 1994, the Governor of the State of Minnesota
(Governor) signed into law a bill passed by the Legislature.
The law authorizes the Company to install 17 dry casks at
Prairie Island, each capable of holding 40 spent fuel assemblies
(approximately one-half year's used fuel) which should provide
storage capacity to allow operation until at least 2003 and 2004
for units 1 and 2 respectively, if the Company satisfies certain
requirements. The Company executed an agreement with the
Governor concerning the renewable energy and alternative siting
commitments contained in the new law. The law authorized
immediately the installation of the first increment of five
casks, three of which have been loaded on site as of Dec. 31,
1995. The second increment of four casks would be authorized in
1996 if the Minnesota Environmental Quality Board (MEQB) finds
that by Dec. 31, 1996: (i) the Company has applied to the NRC
for an alternative site license for an off-site temporary
nuclear fuel storage facility in Goodhue County (but not on the
Prairie Island Nuclear generating site), (ii) the Company has
used good faith in locating and building the alternative site,
and (iii) 100 Mw of wind generation is operational, under
construction or under contract. The final increment of eight
casks would be available unless prior to June 1, 1999, the
Legislature specifically revokes the authorization for the final
eight casks or if an alternative storage site is not operational
or under construction, or the Company fails to meet certain
renewable energy commitments, including the increased use of
wind power and biomass generation facilities by Dec. 31, 1998.
The Company continues to make substantial progress
toward fulfilling the commitments necessary to secure the use of
casks six through nine. On Aug. 17, 1995, the MEQB accepted the
Company's application for a site certificate outlining two
alternative sites for the alternate spent nuclear fuel storage
facility in Goodhue County. The MEQB has begun the 12 to 18
month public siting process to examine these sites and any
others that may be proposed. The Company expects to file its
application with the NRC by October 1996. In 1995, the Company
took steps for its wind and biomass resource commitments as
discussed under the caption "Electric Utility Operations-
Capability and Demand", herein. Other commitments resulting
from the legislation include a low-income discount for electric
customers, additional required conservation improvement
expenditures and various study and reporting requirements to a
legislative electric energy task force. In January
1995, the MPUC approved the Company's low-income discount
programs in accordance with the statute. The Company has
implemented programs to begin meeting the other legislative
commitments. (See "Electric Utility Operations - Capability and
Demand", herein and Notes 14 and 15 of Notes to Financial
Statements under Item 8 for further discussion of this matter.)
To address the issue of continued temporary storage
of used nuclear fuel until the DOE provides for permanent
storage or disposal, the Company is leading a consortium working
with the Mescalero Apache Tribe to establish a private facility
for interim storage of used nuclear fuel on the Tribe's
reservation in New Mexico. A core group of more than 20 United
States nuclear utilities has agreed to support the construction
and operation of the interim storage site. Work on the project
is underway in several areas, including environmental
assessment, facility design, and drafting of the detailed
contracts that will govern the construction and operation of the
site. An architect engineering firm and an environmental
contractor have been retained to perform the environmental and
licensing activities. The consortium is currently scheduled to
submit a license application for the facility to the Nuclear
Regulatory Commission (NRC) in December 1996. The spent fuel
storage facility is expected to be operational and able to
accept the first shipment of used nuclear fuel by mid-2002.
However, due to pending regulatory and governmental approval
uncertainty, it is possible that this interim storage may be
delayed or not available at all.
In January 1995, the Company received a notice of
violation from the United States Nuclear Regulatory Commission
(NRC). The notice was regarding an inspection of the quality
assurance programs for the spent nuclear fuel storage containers
to be used at the Prairie Island Nuclear Generating Plant. On
Feb. 1, 1995, the NRC supplemented the notice, stating, "...the
staff has no reason to conclude that the casks could not perform
their intended safety functions adequately." On March 21, 1995,
the NRC reviewed NSP's responses and concluded that the
Company's corrective actions associated with the violation were
acceptable, and that no further actions with respect to the
violations identified in the January 1995 Inspection Report are
required prior to cask use.
On Dec. 28, 1995, the Company received another
notice of violation from the NRC. This notice was regarding an
improperly positioned valve at the Monticello Nuclear Generating
Plant which violated NRC requirements. The valve had been
mispositioned since returning to power from the last refueling
outage on Oct. 23, 1994. This violation was categorized as a
Severity Level III problem. A base civil penalty in the amount
of $50,000 is considered for a Severity Level III problem.
However, due to Monticello's good past performance and the
initiation of immediate corrective actions upon determination of
the mispositioned valve, the NRC decided to waive the civil
penalty. The Company is continuing follow-up with the NRC to
implement any further corrective actions necessary.
A revision to NSP's 1993 nuclear decommissioning study and nuclear
plant depreciation capital recovery request was filed with the
MPUC and approved in 1994 for the Company's nuclear power plants.
Although management expects to operate the Prairie Island plant
units through the end of their useful lives, the approved
capital recovery would allow for the plant to be fully
depreciated, including the accrual and recovery of
decommissioning costs by 2008, about six years earlier than the
end of its licensed life. The approved cost recovery period has
been reduced because of the uncertainty regarding used fuel
storage.
During the past several years, the NRC has issued a
number of regulations, bulletins and orders that require
analyses, modification and additional equipment at commercial
nuclear power plants. The Company has spent approximately $530
million since 1971, and approximately $1 million, $6 million and
$11 million for 1995, 1994 and 1993, respectively, under such
requirements. The Company expects to expend a minimal amount
for currently required NRC analyses, modification and additional
equipment. The NRC is engaged in various ongoing studies and
rulemaking activities that may impose additional requirements
upon commercial nuclear power plants. Management is unable to
predict any new requirements or their impact on the Company's
facilities and operations.
See Note 14 to the Financial Statements under Item
8 for further discussion of nuclear fuel disposal issues and
information on decommissioning of the Company's nuclear
facilities. Also, see Note 15 to the Financial Statements under
Item 8 for a discussion of the Company's nuclear insurance and
potential liabilities under the Price-Anderson liability
provisions of the Atomic Energy Act of 1954.
Electric Operating Statistics
The following table summarizes the revenues, sales
and customers from NSP's electric transmission and distribution
business:
1995 1994 1993 1992 1991
Revenues (thousands)
Residential
With space heating $ 67 332 $ 66 962 $ 68 222 $ 63 376 $ 67 878
Without space heating 668 411 616 821 583 371 534 676 568 672
Small commercial and
industrial 362 521 351 287 327 888 312 581 315 946
Medium commercial and
industrial 399 259 * * * *
Large commercial and
industrial 448 226 824 195 780 444 718 712 713 177
Street lighting and other 29 162 28 936 29 214 29 764 30 720
Total retail 1 974 911 1 888 201 1 789 139 1 659 109 1 696 393
Sales for resale 133 961 146 239 159 498 137 962 145 008
Miscellaneous 33 898 32 204 26 279 26 245 21 837
Total $2 142 770 $2 066 644 $1 974 916 $1 823 316 $1 863 238
Sales (millions of
kilowatt-hours)
Residential
With space heating 1 111 1 076 1 094 1 041 1 141
Without space heating 8 845 8 227 7 998 7 640 8 226
Small commercial and
industrial 5 763 5 585 5 307 5 224 5 330
Medium commercial and
industrial 7 511 * * * *
Large commercial and
industrial 10 941 17 874 17 117 16 365 16 286
Street lighting and other 329 334 344 372 386
Total retail 34 500 33 096 31 860 30 642 31 369
Sales for resale 6 500 6 733 8 044 6 530 6 083
Total 41 000 39 829 39 904 37 172 37 452
Customer accounts (at Dec. 31)
Residential
With space heating 76 344 76 050 75 644 74 939 74 646
Without space heating 1 162 232 1 146 578 1 131 928 1 119 354 1 104 772
Small commercial and
industrial 144 774 142 858 141 446 140 768 139 266
Medium commercial and
industrial 7 906 * * * *
Large commercial and
industrial 652 8 172 8 114 7 904 7 758
Street lighting and other 4 883 4 836 4 813 4 627 7 662
Total retail 1 396 791 1 378 494 1 361 945 1 347 592 1 334 104
Sales for resale 67 70 71 74 72
Total 1 396 858 1 378 564 1 362 016 1 347 666 1 334 176
* Beginning in 1995, the commercial and industrial customer
class has been segmented into small (less than 100 kw in demand
per year), medium (100 kw to 1,000 kw) and large (1,000 kw or
more). The estimated medium group was reported as large prior
to 1995.
GAS UTILITY OPERATIONS
Competition
NSP provides retail gas service in portions of
eastern North Dakota and northwestern Minnesota, the eastern
portions of the Twin Cities metro area, and other regional
centers in Minnesota (Mankato, St. Cloud and Winona) and
Wisconsin (Eau Claire, La Crosse and Ashland). NSP is directly
connected to four interstate natural gas pipelines serving these
regions: Northern Natural Gas Company (Northern), Viking,
Williston Basin Interstate Pipeline Company (Williston) and
Great Lakes Transmission Limited Partnership (Great Lakes).
Approximately 90 percent of NSP's retail gas customers are
served from the Northern pipeline system.
During 1992 and 1993, the FERC issued a series of
orders (together called Order 636) that addressed interstate
natural gas pipeline restructuring. This restructuring required
all interstate pipelines, including those serving NSP, to
"unbundle" each of the services they provide: sales,
transportation, storage and ancillary services. To comply with
Order 636, NSP executed new pipeline transportation service and
gas supply agreements effective Nov. 1, 1993, as discussed
below. While these new agreements create a new form of
contractual obligation, NSP believes the new agreements provide
flexibility to respond to future changes in the retail natural
gas market. NSP expects its financial risk under the new
transportation agreements to be no greater than the risk faced
under the previous long-term full requirements gas supply contracts
with interstate pipelines.
The implementation of Order 636 applies additional
competitive pressure on all local distribution companies (LDCs)
including NSP, to keep gas supply and transmission prices for
their large customers competitive because of the alternatives
now available to these customers. Like gas LDCs, these
customers now have expanded ability to buy gas directly from
suppliers and arrange pipeline and LDC transportation service.
NSP has provided unbundled transportation service since 1987.
Transportation service does not currently have an adverse effect
on earnings because NSP's sales and transportation rates have
been designed to make NSP economically indifferent to sales or
transportation of gas. However, some transportation customers
may have greater opportunities or incentives to physically
bypass the LDC distribution system. NSP has arranged its gas
supply and transportation portfolio in anticipation that it may
be required to terminate its retail merchant sales function.
Overall, NSP believes Order 636 has enhanced its ability to
remain competitive and allowed it to increase certain of its
margins by providing an increased selection of services to its
customers.
Order 636 allows interstate pipelines to negotiate
with customers to recover up to 100 percent of prudently
incurred "transition costs" (i.e., stranded costs) attributable
to Order 636 restructuring. Recoverable transition costs can
include "buy down" and "buy out" costs for remaining gas supply
and upstream pipeline transportation agreements, unrecovered
deferred gas purchase costs, and the cost to dispose of
regulated assets no longer needed because of the termination of
the merchant function (e.g., financial losses on the sale of
regulated gathering or storage facilities).
NSP's primary gas supplier, Northern, is in the
process of determining the final amount of transition costs to
be passed on to customers as a result of Order 636
restructuring. Northern's restructuring settlement provided for
the assignment of a significant portion of Northern's gas supply
and upstream contract obligations. This solution was beneficial
because Northern's customers contracted directly for
obligations, rather than paying to buy out of those obligations
and then contracting with the same gas suppliers and pipelines
to replace the merchant function. The total transition costs
recoverable for the remaining unassigned agreements is limited
to $78 million. In addition, Northern may seek transition cost
recovery for certain other costs, subject to prudency review.
Northern's total Order 636 transition costs, to be passed on to
all of its customers, are estimated to be approximately $100
million. Northern 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. NSP estimates that it will be
responsible for less than $11 million of Northern's transition
costs, spread over a period of approximately five years, which
began Nov. 1, 1993. To date, NSP's regulatory commissions have
approved recovery of restructuring charges in retail gas rates.
NSP has no significant Order 636 transition cost
responsibilities to its other pipeline suppliers.
The gas services available to NSP's customers were
enhanced beginning in 1993 through the acquisitions of Viking in
June 1993 and the assets of a gas marketing business by a new
NSP subsidiary, Cenergy, Inc., in October 1993. See the Non-
Regulated Subsidiaries section herein for further discussion of
Cenergy. See further discussion of Viking below.
NSP's gas utility took advantage of opportunities
to expand into new service territory during 1995. NSP extended
service to approximately 1,600 customers in 8 new communities.
In addition to exploring new growth opportunities, NSP is also
focusing on conversion of potential customers who are located
near NSP's gas mains but are not hooked up to receive the
service. NSP estimates there are approximately 28,000 potential
customers that fall into this category.
The most recent large gas expansion project occurred
in Crow Wing and Cass counties in north central Minnesota.
Outside the St Paul-Minneapolis area, these counties are
experiencing the fastest growth of all counties in Minnesota.
The project included laying approximately 550 miles of pipeline
in 11 of the cities in the Brainerd Lakes area. The project's
net capitalized investment cost was approximately $23 million.
Construction began in 1994. The MPUC approved a "new town" rate
surcharge for customers in this area to support NSP's capital
investment in the project. The surcharge will be in effect for
up to 15 years.
The Company's gas operation has organized a non-
utility service offering individuals service contracts on a
variety of home appliances. Working in partnership with local
independent service contractors, NSP Advantage Service offers 24
hour appliance repair service. Depending on the level of
service contracted, Advantage Service customers have coverage to
help avoid the expense and inconvenience of unexpected appliance
repairs. This service is being offered to individuals within
NSP's service territory.
Capability and Demand
NSP categorizes its gas supply requirements as firm
(primarily for space heating customers) or interruptible
(commercial/industrial customers with an alternate energy
supply). NSP's maximum daily sendout (firm and interruptible)
of 659,800 MMBtu for 1995 occurred on Jan. 3, 1995.
NSP's primary gas supply sources are purchases of
third-party gas which are delivered under gas transportation
service agreements with interstate pipelines. These agreements
provide for firm deliverable pipeline capacity of approximately
557,810 MMBtu/day. In addition, NSP has contracted with four
providers of underground natural gas storage services to meet
the heating season and peak day requirements of NSP gas
customers. Using storage reduces the need for firm pipeline
capacity. These storage agreements provide NSP storage for
approximately 19 percent of annual and 31 percent of peak daily
firm requirements. NSP also owns and operates two liquified
natural gas (LNG) plants with a storage capacity of 2.53 Bcf
equivalent and four propane-air plants with a storage capacity
of 1.42 Bcf equivalent to help meet the peak requirements of its
firm residential, commercial and industrial customers. These
peak shaving facilities have production capacity equivalent to
242,300 Mcf of natural gas per day, or approximately 34 percent
of peak day firm requirements. NSP's LNG and propane-air plants
provide a cost-effective alternative to annual fixed pipeline
transportation charges to meet the "needle peaks" caused by firm
space heating demand on extremely cold winter days and can be
used to minimize daily imbalance fees on interstate pipelines.
The cost of gas supply, transportation service and
storage service is recovered through the PGA rate adjustment
mechanism. The average cost of gas and propane held in
inventory for the latest test year is allowed in rate base by
the MPUC and the PSCW.
A number of NSP's interruptible industrial customers
purchase their natural gas requirements directly from producers
or brokers for transportation and delivery through NSP's
distribution system. The transportation rates have been
designed to make NSP economically indifferent as to whether NSP
sells and transports gas or only transports gas.
Gas Supply and Costs
As a result of Order 636 restructuring, NSP's
natural gas supply commitments have been unbundled from its gas
transportation and storage commitments. NSP's gas utility
actively seeks gas supply, transportation and storage
alternatives to yield a diversified portfolio that provides
increased flexibility, decreased interruption and financial
risk, and economical rates. This diversification involves
numerous domestic and Canadian supply sources, varied contract
lengths, and transportation contracts with seven natural gas
pipelines.
Among other things, Order 636 provides for the use
of the "straight fixed/variable" rate design that allows
pipelines to recover all their fixed costs through demand
charges. NSP has firm gas transportation contracts with the
following seven pipelines. The contracts expire in various
years from 1996 through 2013.
Northern Natural Gas Company Great Lakes Transmission
Limited Partnership
Williston Basin Interstate Pipeline Co. Northern Border Pipeline Company
Viking Gas Transmission Company ANR Pipeline Company
TransCanada Gas Pipeline Ltd.
The agreements with Great Lakes, Northern Border,
ANR and TransCanada provide for firm transportation service
upstream of Northern Natural and Viking, allowing competition
among suppliers at supply pooling points, minimizing commodity
gas costs.
In addition to these fixed transportation charge
obligations, NSP has entered into firm gas supply agreements
that provide for the payment of monthly or annual reservation
charges irrespective of the volume of gas purchased. The total
annual obligation is approximately $34.4 million. These
agreements are beneficial because they allow NSP to purchase the
gas commodity at a high load factor at rates below the
prevailing market price reducing the total cost per Mcf.
NSP has certain gas supply and transportation
agreements, which include obligations for the purchase and/or
delivery of specified volumes of gas, or to make payments in
lieu thereof. At Dec. 31, 1995, NSP was committed to
approximately $511.8 million in such obligations under these
contracts, over the remaining contract terms, which range from
the years 1996-2013. These obligations include some of the
effects of contract revisions made to comply with Order 636.
NSP has negotiated "market out" clauses in its new supply
agreements, which reduce NSP's purchase obligations if NSP no
longer provides merchant gas service.
NSP purchases firm gas supply from a total of
approximately 20 domestic and Canadian suppliers under contracts
with durations of one year to 10 years. NSP purchases no more
than 20 percent of its total daily supply from any single
supplier. This diversity of suppliers and contract lengths
allows NSP to maintain competition from suppliers and minimize
supply costs. NSP's objective is to be able to terminate its
retail merchant sales function, if either demanded by the
marketplace or mandated by regulatory agencies, with no
financial cost to NSP.
The state utility commissions in Minnesota, North
Dakota, Wisconsin and Michigan allowed NSP to fully recover the
costs of these restructured services through purchased gas
adjustments to customer rates.
In July 1995, the FERC issued an order on remand in
the 1991 and 1992 general rate cases filed by Great Lakes Gas
Transmission Limited Partnership, one of NSP's transportation
suppliers. The primary issue in the cases involved whether
Great Lakes must use "incremental" or "rolled in" pricing for
approximately $900 million of pipeline capacity expansion costs.
The FERC had initially ruled that Great Lakes' rates should be
designed to collect the incremental cost of the new facilities
only from the new customers of the expansion project. On remand
from the United States Circuit Court of Appeals, FERC reversed
its previous order and ruled Great Lakes could include the
expansion costs in rates for all transportation customers. The
reversal increases NSP's costs for transportation service by
approximately $1.1 million annually; the Company and the
Wisconsin Company are recovering this increase through the PGA
clause. However, the FERC also ruled Great Lakes could collect
the higher rates from non-expansion customers retroactive to
Nov. 1, 1991. This surcharge for NSP is expected to be
approximately $2.8 million. NSP will seek PGA recovery of the
surcharges if they are billed. In addition, NSP and numerous
other parties have requested rehearing of the July 1995 remand
order. A final FERC decision is pending.
On March 1, 1995, Northern Natural Gas filed for
FERC approval to implement a general increase in its rates for
transportation and other services. Northern implemented the
increased rates on Jan. 1, 1996, subject to refund. The rate
change is expected to increase the Company's costs by
approximately $5.9 million annually. The Company and the
Wisconsin Company are recovering this increase through the PGA
clause. The FERC hearings are scheduled for August 1996.
Purchases of gas supply or services by the Company
from the Wisconsin Company, its Viking pipeline affiliate and
its Cenergy gas marketing affiliate are subject to approval by
the MPUC. The MPUC has approved all the Company's
transportation contracts with Viking and a spot gas purchase
agreement with Cenergy. In September 1995, the MPUC approved a
settlement authorizing a gas supply management agreement between
the Company's gas utility and generating business units. In
January 1996, the MPUC approved a three-month capacity release
agreement between the Company and the Wisconsin Company, which
allowed gas and pipeline capacity sales between the two
companies in 1996.
The following table summarizes the average cost per
MMBtu of gas purchased for resale by NSP's regulated retail gas
distribution business, which excludes Viking and Cenergy:
The Company Wisconsin Company
1992 $2.71 $2.80
1993 $3.11 $3.02
1994 $2.59 $3.13
1995 $2.29 $2.78
Viking Gas Transmission Company
In June 1993, the Company acquired 100 percent of
the stock of Viking Gas Transmission Company (Viking) from
Tenneco Gas, a unit of Tenneco Inc., in Houston, Texas. Viking,
which is now a wholly owned subsidiary of the Company, owns and
operates a 500-mile interstate natural gas pipeline serving
portions of Minnesota, Wisconsin and North Dakota with a
capacity of approximately 400 million cubic feet per day. The
Viking pipeline currently serves 10 percent of NSP's gas
distribution system needs. Viking currently operates
exclusively as a transporter of natural gas for third-party
shippers under authority granted by the FERC. Rates for
Viking's transportation services are regulated by FERC. In
addition to revenue derived from FERC-approved rates, which are
reported in Operating Revenues, Viking is receiving intercompany
revenues from the Company and the Wisconsin Company for
jurisdictional allocations of the acquisition adjustment paid by
NSP (in excess of Tenneco's pipeline carrying value) to acquire
Viking. The Company is not recovering this cost in retail gas
rates in Minnesota, but is recovering this cost in North Dakota.
The Wisconsin Company is recovering this cost in its retail gas
rates.
In October 1995, Viking filed an application with
the FERC for authorization to install 13.5 miles of pipeline
looping in northwestern Minnesota to increase Viking's capacity
by approximately 19,400 million cubic feet per day. The total
expected cost is approximately $8.4 million, with a proposed in-
service date of November 1996. This would be Viking's first
mainline capacity expansion since the 1960s. This capacity is
for four expansion customers: two municipal gas utilities
already served by Viking, Perham and Randall, Minn.; and two
large industrial customers, American Crystal Sugar and ProGold,
LLC. Viking may have further expansion opportunities in 1997.
The FERC authorization of the application is pending. A
decision is expected in April 1996.
In 1995, the Viking pipeline experienced a leak
which may be attributable to stress corrosion cracking (SCC).
Permanent repairs were made to correct the problem without
impacting service to customers. Viking is reviewing current
industry practices and is developing plans to minimize the
possibility of future SCC problems. This was the first
occurrence since the line went in service in the early 1960s.
Gas Operating Statistics
The following table summarizes the revenue, sales
and customers from NSP's regulated gas businesses:
1995 1994 1993 1992 1991
Revenues (thousands)
Residential
With space heating $ 212 853 $ 204 668 $ 220 828 $ 178 164 $ 179 161
Without space heating 2 690 2 838 2 715 2 523 2 614
Commercial and
industrial
Firm 119 863 120 912 131 431 105 829 105 703
Interruptible 48 646 49 384 52 216 41 612 40 768
Interstate transmission
(Viking) * 13 954 14 075 9 019
Miscellaneous ** 27 808 28 026 12 867 8 078 9 674
Total $ 425 814 $ 419 903 $ 429 076 $ 336 206 $ 337 920
Sales (thousands of mcf)
Residential
With space heating 41 993 38 427 40 946 35 136 37 493
Without space heating 301 323 331 323 359
Commercial and
industrial 28 275 27 342 28 622 24 273 25 429
Interruptible 22 408 19 373 18 559 15 823 15 813
Miscellaneous 772 212 186 108 325
Total 93 749 85 677 88 644 75 663 79 419
Other gas delivered (thousands of mcf)
Interstate transmission
(Viking) * 132 512 131 074 75 188
Agency, transportation
and off-system sales 19 679 13 466 8 128 7 332 7 549
Total 152 191 144 540 83 316 7 332 7 549
Customer accounts (at Dec. 31)
Residential
With space heating 367 811 351 773 337 868 326 439 314 843
Without space heating 18 196 18 961 19 408 19 841 20 294
Commercial and industrial 38 575 37 140 36 185 35 458 34 663
Total 424 582 407 874 393 461 381 738 369 800
* Excludes intercompany sales revenues of $2.4 million (20,441
thousands of mcf) in 1995 and $2.2 million (16,845 thousands of
mcf) in 1994.
** Includes NSP revenues for agency and transportation services
and off-system sales.
NON-REGULATED SUBSIDIARIES
NRG Energy, Inc.
NRG Energy, Inc. (NRG) is the Company's subsidiary
that develops, builds, acquires, owns and operates several non-
regulated energy-related businesses. It was incorporated in
Delaware on May 29, 1992, and assumed ownership of the assets of
NRG Group, Inc., including its subsidiary companies. NRG
businesses generated 1995 operating revenues of $64 million and
had assets of $452 million at Dec. 31, 1995.
NRG conducts business through various subsidiaries,
including: NRG International, Inc.; Graystone Corporation;
Scoria Incorporated; San Joaquin Valley Energy I, Inc.; San
Joaquin Valley Energy IV, Inc.; NRG Energy Jackson Valley I,
Inc.; NRG Energy Jackson Valley II, Inc.; NEO Corporation; NRG
Energy Center, Inc; NRG Sunnyside Inc. and NRG Operating
Services, Inc.
Operating Businesses
In December 1993, NRG, through a wholly owned
foreign subsidiary, agreed to acquire a 33 percent interest in
the coal mining, power generation and associated operations of
Mitteldeutsche Braunkohlengesellschaft mbh (MIBRAG), located
south of Leipzig, Germany. MIBRAG is a German corporation
formed by the German government to hold two open-cast brown coal
(lignite) mining operations, a lease on an additional mine, the
associated mining rights and rights to future mining reserves,
two small industrial power plants and a circulating fluidized
bed power plant, a district heating system and coal briquetting
and dust production facilities. Under the acquisition
agreement, Morrison Knudsen Corporation and PowerGen plc also
each acquired a 33 percent interest in MIBRAG, while the German
government retained a one-percent interest in MIBRAG. The
investor partners began operating MIBRAG effective Jan. 1, 1994,
and the legal closing occurred Aug. 11, 1994.
In December 1993, NRG, through a wholly owned
foreign subsidiary, acquired a 50 percent interest in a German
corporation, Saale Energie GmbH (Saale). Saale owns a 400 Mw
share of a 960 Mw power plant currently under construction in
Schkopau, Germany, which is near Leipzig. PowerGen plc of the
United Kingdom acquired the remaining 50 percent interest in
Saale. Saale was formed to acquire a 41.1 percent interest in
the power plant. VEBA Kraftwerke Ruhr AG of Gelsenkirchen,
Germany (VKR), is the builder of the Schkopau plant. VKR owns
the remaining 58.9 percent interest in the power plant and will
operate the plant. The plant will be fired by brown coal
(lignite) mined by MIBRAG under a long-term contract. Saale has
a long-term power sales agreement for its 400 Mw share of the
Schkopau facility with VEAG of Berlin, Germany, the company that
controls the high-voltage transmission of electricity in the
former East Germany. The first 425 Mw unit of the plant began
test operations in January 1996 and the second 425 Mw unit is
expected to commence commercial operation in July 1996. The 110
Mw turbine began commercial operations in February 1996.
Through Dec. 31, 1995, NRG had invested approximately $31
million to acquire its interest in Saale including capitalized
development costs. NRG's future equity commitment to Saale
through 1996 is expected to be no more than $25 million.
In March 1994, NRG, through wholly owned foreign
subsidiaries, acquired a 37.5 percent interest in the Gladstone
Power Station, a 1680 Mw coal-fired plant in Gladstone,
Queensland, Australia from the Queensland Electricity
Commission. Other members of the unincorporated joint venture,
including Comalco Limited of Australia (Comalco), acquired the
remaining interest. A large portion of the electricity
generated by the station is sold to Comalco for use in its
aluminum smelter, pursuant to long-term power purchase
agreements. NRG, through an Australian subsidiary, operates the
Gladstone plant.
In 1994, NRG signed a Joint Development Agreement
with Advanced Combustion Technologies, Inc. (ACT) with respect
to the acquisition, upgrading, expansion and development of
Energy Center Kladno ("Kladno") in Kladno, Czech Republic. NRG
and ACT jointly have acquired a 36.5 percent interest in Kladno,
which owns and operates an existing coal-fired power and thermal
energy generation facility that can supply 28 Mw of electrical
energy to an industrial complex and to the local electric
distribution company and 150 megawatts thermal-equivalent steam
and heated water to a district heating system and thermal energy
to an industrial complex. Kladno also owns certain ancillary
utility assets. The acquisition of the existing facility is the
first phase of a development project that would include
upgrading the existing plant and would explore developing a new
power generation facility with up to 240 Mw of coal-fired
generation and up to 100 Mw of gas-fired generation depending on
the ongoing analysis of the alternatives. The new facility
would supply back-up steam to the district heating system and
sell electricity to STE, the principal regional electric
distribution company in Prague, via an existing 23 kilometer
transmission line owned by Kladno.
NRG operates two refuse-derived fuel (RDF)
processing plants and an ash disposal site in Minnesota. The
ownership of one plant was transferred by the Company to NRG at
the end of 1993. NRG manages the operation of the other RDF
plant, of which the Company owns 85 percent, and of the ash
disposal site. The Company and NRG are currently negotiating a
new operation and maintenance agreement for approval by the
MPUC. In 1995, workers at the RDF plants processed more than
750,000 tons of municipal solid waste into approximately 660,000
tons of RDF that was burned at two NSP power plants and at a
power plant owned by United Power Association.
NRG also owns and operates three steam lines in
Minnesota that provide steam from the Company's power plants to
the Waldorf Corporation, the Andersen Corporation and the
Minnesota Correctional Facility in Stillwater.
During 1993, the Company formed NEO Corporation
(NEO), a wholly owned subsidiary, to develop small power
generation facilities in the United States. During 1994, the
ownership of NEO was transferred by the Company to NRG. NEO
owns a 50 percent interest in Minnesota Methane LLC. Minnesota
Methane LLC is developing small scale waste to energy facilities
utilizing landfill gas. In December 1994, NEO acquired a 50
percent ownership in STS HydroPower Limited, an independent
power producer with 21 Mw of hydroelectric facilities throughout
the United States. STS HydroPower Limited currently is successfully
operating 11 hydroelectric facilities across the United States and four
generating plants that use renewable landfill gas as fuel. Minnesota
Methane LLC is pursuing 10 additional landfill gas projects.
NRG, through wholly owned subsidiaries, owns 45
percent of the San Joaquin Valley Energy Partnerships (SJVEP),
which own four power plants located near Fresno, California with
a total capacity of 55 megawatts. Through February 1995, the
plants operated under long-term Standard Offer 4 (SO4) power
sales contracts with Pacific Gas and Electric (PG&E) which
expire in 2017. On February 28, 1995, PG&E reached basic
agreements with SJVEP to acquire the SO4 contracts. The
negotiated agreements will result in cost savings for PG&E
customers as well as economic benefits for SJVEP. Under the
terms of the agreements, PG&E has been released from its
contractual obligation to purchase power generated by SJVEP.
Proceeds received from PG&E under the agreements were used to
repay SJVEP debt obligations and recover investments in the
facilities. SJVEP continues to own and maintain the facilities
and to evaluate opportunities to market power without the prior
costs incurred for plant depreciation and interest on debt. All
regulatory approvals for the agreements were received in the
second quarter of 1995. NRG's share of the pretax gain realized
by SJVEP from this transaction, which was recorded in June 1995,
was approximately $30 million (26 cents per share after tax).
Approximately $12 million in settlement distributions were paid
to NRG from SJVEP in 1995, and additional distributions are
expected in 1996.
NRG, through wholly owned subsidiaries, owns 50
percent of the Jackson Valley Energy partnership, which owns and
operates a 16 Mw cogeneration power plant near Sacramento,
California. The plant had a long-term power sales agreement
with Pacific Gas & Electric through 2014. On April 1, 1995,
Jackson Valley Energy Partners reached an agreement with PG&E
regarding the idling of the Jackson Valley plant near
Sacramento. Under this agreement, which is similar to the SJVEP
agreement, the plant will remain idle until May 1, 1997, and
will then restart and sell power to PG&E under a new long term
agreement. No gain or cash distribution has resulted or is
expected from this transaction.
NRG, through a wholly owned subsidiary, purchased
the assets of the Minneapolis Energy Center (MEC), a downtown
Minneapolis district heating and cooling system in August 1993.
The system utilizes steam and chilled water generating
facilities to heat and cool buildings for 86 heating and 29
cooling customers. The primary assets include the main plant,
with 800,000 lbs/hour of steam capacity and 22,000 tons/hour of
chilled water capacity, two satellite plants, two standby
plants, six miles of steam lines and two miles of chilled water
distribution lines. Existing long-term contracts with MEC
customers remained in effect under NRG's ownership. During
1995, MEC negotiated contracts with two new customers for 25,000
lbs/hour of steam and 2,400 tons/hour of chilled water.
On August 1, 1995, NRG closed on the acquisition of
a 49 percent limited partnership interest in the partnerships
holding the operating assets of the district and heating and
cooling systems in Pittsburgh and San Francisco. The interest
was acquired from Thermal Ventures, Inc., which will continue to
operate these systems. Current annual revenue of the San
Francisco thermal system is approximately $9 million, and the
annual steam sales volumes are approximately 700 million pounds.
The San Francisco thermal system provides service to more than
200 buildings. The Pittsburgh thermal system currently has $8
million of annual revenue and provides annual steam sales
volumes of 300 million pounds, and chilled water sales volumes
of 21 million ton-hours to 24 customers.
In December 1994, NRG, through a wholly owned
subsidiary, purchased a 50 percent ownership interest in
Sunnyside Cogeneration Associates (SCA), a Utah joint venture
(partnership), which owns and operates a 58 Mw waste coal plant
in Utah. The waste coal plant is currently being operated by a
partnership that is 50 percent owned by an NRG affiliate.
Scoria Incorporated and Western SynCoal Co., a
subsidiary of Montana Power Co., completed construction in
January 1992 of a demonstration coal conversion plant designed
to improve the heating value of coal by removing moisture,
sulfur and ash. The plant, located in Montana, began commercial
operation in August 1993. NRG's net capitalized investment in
the Scoria coal project was written down by $3.5 million in 1994
and $5 million in 1995 to reflect reductions in the expected
future operating cash flows from the project. NRG continues to
evaluate the recoverability of its remaining investment of
approximately $2.5 million in the Scoria project.
New Business Development
NRG is pursuing several energy-related investment
opportunities, including those discussed below, and continues to
evaluate other opportunities as they arise. Potential capital
requirements for these opportunities are discussed in the
"Capital Spending and Financing" section.
On November 17, 1995, NRG through a wholly owned
subsidiary, entered into an agreement with the Aetna Life
Insurance Company to acquire a 50 percent interest in Capital
District Energy Center Cogeneration Associates, a joint venture
general partnership which owns and operates a 56 Mw, natural
gas-fired, cogeneration facility located in Hartford,
Connecticut. The closing of the transaction is conditioned upon
receipt of third party consents.
Early in 1996, NRG was negotiating the purchase of
a 42 percent interest in O'Brien Environmental Energy, Inc.
(O'Brien) from bankruptcy. The remaining 58 percent interest
will be held by shareholders of O'Brien and will be publicly
traded. O'Brien has interests in eight domestic operating power
generation facilities with aggregate capacity of approximately
230 megawatts, and in one 150-megawatt facility in the contract
stage of development. O'Brien's principal operating projects
have an aggregate capacity of 183 Mw and include: (a) the 52 Mw
Newark Boxboard Project (which is owned 100 percent by a wholly
owned subsidiary of O'Brien), a gas-fired cogeneration facility
that sells electricity to Jersey Central Power and Light Company
(JCP&L) and steam to Newark Boxboard Company; (b) the 122 Mw
E.I. du Pont Parlin Project (which is owned 100 percent by a
wholly owned subsidiary of O'Brien), a gas-fired cogeneration
facility that sells electricity to JCP&L and steam to E.I. du
Pont de Nemours and Company; and (c) four biogas projects in
Pennsylvania and California with total power generation capacity
of 9.2 Mw. In addition, at Dec. 31, 1995, O'Brien had a 50 percent
interest in the 150 Mw Grays Ferry Project, a proposed cogeneration
project that would, upon successful development, sell electricity to
Philadelphia Electric Company and district heating steam to
Trigen Philadelphia Energy Corporation (TPEC). As a result of
the purchase of O'Brien, approximately $107 million would be
made available to O'Brien creditors by NRG. See additional
discussion of commitments for the O'Brien acquisition in Note 15
to Financial Statements under Item 8.
A joint venture between NRG and Transfield, an
Australian infrastructure contractor, signed an 18-year power
purchase agreement and an acquisition agreement with the
Queensland Transmission and Supply Corporation for the
acquisition and refurbishment of the 189 Mw Collinsville coal-
fired power generation facility in Queensland, Australia. If
successful in the acquisition of this project, NRG would own a
50 percent interest and operate the facility. Transfield would
perform the facility refurbishment and environmental remediation
under a fixed price turnkey contract and would perform facility
maintenance under a subcontract with NRG.
In July 1993, NRG, together with the International
Finance Corporation (an affiliate of the World Bank), CMS Energy
Corporation (the parent company of Consumers Power Company) and
Corporation Andina de Fomento (CAF) formed the Scudder Latin
American Trust for Independent Power (Scudder), an investment
fund which is intended to invest in the development of new power
plants and privatization of existing power plants in Latin
America and the Caribbean. The fund has retained Scudder
Stevens & Clark, Inc. as its investment manager. The fund
commenced its investment development efforts in September 1993.
Each of the four investors has committed $25 million which the
fund is seeking to invest over the five year period 1994 - 1998.
The fund has commenced private placement activities to obtain
additional investors in the fund, particularly other utility
affiliates and institutional investors. Scudder holds
investments in two power generation facilities in Latin America
and one in the Caribbean. As of Dec. 31, 1995, NRG has invested
$9 million in Scudder for equity interests ranging from 7.7
percent to 10.3 percent.
Graystone Corporation, with several other
companies, continues with permitting plans to build the first
privately owned uranium enrichment plant in the United States.
Construction of the Louisiana plant, which would provide fuel
for the nuclear power industry, could begin in the next few
years. Because of the uncertainty surrounding the ultimate
successful operation of this plant, NRG wrote off its $1.5
million investment in Graystone during 1994.
Cenergy, Inc.
NSP's non-regulated wholly owned subsidiary,
Cenergy, Inc. (which changed its name to Cenerprise, Inc.
effective Jan. 1, 1996) commenced operations in October 1993
through the acquisition from bankruptcy of selected assets of
Centran Corporation, a natural gas marketing company. Cenergy,
in addition to marketing natural gas, provides customized value-
added energy services to customers, both inside NSP service
territory and on a national basis. Cenergy offers customers
many energy products and services including: utility billing
analysis, end-use gas marketing, risk management, construction,
energy services consulting and administrative services. The
MPUC has approved an affiliate transaction contract, whereby
Cenergy may make natural gas sales at market based rates
(determined by competitive bids) to NSP for resale to retail gas
customers.
In December 1994, the FERC approved Cenergy's
application to sell electric power (except electricity generated
by NSP) in the United States, giving NSP an opportunity to enter
the increasingly deregulated and competitive electric market.
Cenergy was one of the first utility affiliates to obtain this
approval from the FERC. NSP is allowing open access to its
electric transmission lines by other electric power providers
throughout North America. Cenergy's initiative to buy and sell
deregulated electricity is consistent with NSP's objective to
embrace competition, which will benefit NSP customers and
shareholders.
In 1995, Cenergy and Atlantic Energy Enterprises
(AEE) established Atlantic CNRG Services LLC (Atlantic CNRG).
Cenergy and AEE each own 50 percent of the new venture that will
develop new and expanded natural gas and electric energy
products and services, primarily in the northeast United States.
On Feb. 1, 1996, Atlantic CNRG acquired the natural gas
marketing assets of Interstate Gas Marketing (IGM). IGM, which
has offices in Scranton and Pittsburgh, Pennsylvania, markets
natural gas to customers in the northeastern United States.
On Sept. 1, 1995, a non-regulated subsidiary of NSP
was merged with Kansas City-based Energy Masters Corporation
(EMC) resulting in the Company's acquisition of an 80 percent
ownership interest in EMC. The Company subsequently assigned
its interest in EMC to Cenergy. Cenergy has the option to
acquire the remaining 20 percent of EMC in three years. EMC has
offices in seven states nationwide and specializes in energy
efficiency improvement services for commercial, industrial and
institutional customers. For its fiscal year ended Oct. 31,
1994 (the latest EMC fiscal year prior to acquisition), EMC,
with more than 60 employees, had operating revenues of $5.9
million. EMC will continue to operate as a separate legal
entity, as a subsidiary of Cenergy.
On Nov. 15, 1995, Cenergy and its partners sold
their oil and gas leasehold interest in approximately 1,000
acres to TransTexas Gas Co. for $5 million. Cenergy purchased
the property, located in Zapata County, Texas, in July 1994.
Earlier in 1995 Cenergy redirected its oil and natural gas unit
to focus on financing flowing production rather than engaging in
exploratory and development drilling ventures. The sale of the
Zapata County leases is the first step in shifting production
area business to more closely follow its corporate energy
service focus. The pretax gain recognized in 1995 from the sale
of these leases, net of valuation adjustments for investments in
remaining oil and gas properties held by Cenergy was
approximately $1.1 million.
Eloigne Company
In 1993, the Company established Eloigne Company
(Eloigne), to identify and develop affordable housing investment
opportunities. Eloigne's principal business is the acquisition
of a broadly diversified portfolio of rental housing projects
which qualify for low income housing tax credits under current
federal tax law. As of Dec. 31, 1995, approximately $38.5
million had been invested in Eloigne projects, including $13.3
million in wholly owned properties (at net book value) and $25.2
million in equity interests in jointly-owned projects. These
investments and related working capital requirements have been
financed with $25.3 million of equity capital (including
undistributed earnings) and $20.7 million of long-term debt
(including current maturities). Completed projects as of Dec.
31, 1995, are expected to generate tax credits of $45.6 million
over the 10-year period 1996-2005. Tax credits recognized in
1995 as a result of these investments were approximately $3.0
million. A proposed "phase-out" of these tax credits is
currently under consideration by the United States Congress.
The proposal would sunset the low-income housing tax credit
allocation after Dec. 31, 1997. Projects with credits allocated
prior to that date would continue to generate tax credits over
the remainder of the 10-year credit period allowed.
Non-Regulated Business Information
(Thousands of dollars, except per share data) 1995 1994 1993
Operating Results
Operating Revenues $313 082 $241 827 $90 531
Operating Expenses (1) (327 894) (241 480) (81 480)
Equity in earnings of unconsolidated
affiliates:
Earnings from operations (2) 28 055 31 595 2 695
Gains from contract terminations 29 850 9 685
Other income (deductions)---net 6 518 1 843 1 040
Interest expense (9 879) (7 975) (3 146)
Income taxes (2) (6 119) (2 591) (3 548)
Net income $ 33 613 $ 32 904 $ 6 092
Contribution of Non-regulated Businesses to NSP Earnings per Share
NRG Energy, Inc. $0.46 $0.44 $0.04
Eloigne Company 0.02 0.02 0.00
Cenergy, Inc. (Cenerprise, Inc.,
effective Jan. 1, 1996) (0.02) 0.00 0.00
Other (3) 0.04 0.03 0.05
Total $0.50 $0.49 $0.09
(Thousands of dollars) 1995 1994
Equity Investment by Non-regulated Businesses in Unconsolidated Projects at
Dec. 31
(Including undistributed earnings and capitalized development costs)
Australian projects $81 885 $75 108
German projects 87 699 55 337
Other international projects 14 920 4 013
Affordable housing projects (U.S.) 25 211 7 148
Other U.S. projects 54 276 36 152
Total Equity Investment in Unconsolidated
Non-regulated Projects $263 991 $177 758
Additional Equity Invested in Consolidated
Non-regulated Businesses 115 276 104 011
Total Net Assets of Non-regulated
Businesses $379 267 $281 769
Significant Unconsolidated Non-Regulated Projects at Dec. 31, 1995
Generation Projects Total NRG Mw-
Operating Location MW Ownership Equity Operator
Gladstone Power Station Australia 1680 37.5% 630 NRG
MIBRAG mbh Germany 200 33.3% 67 Joint Venture-MIBRAG (NRG/PowerGen
plc/Morrison Knudsen Corp.)
San Joaquin Valley Energy
Partners California, USA 55 45.0% 25 Joint Venture-NRG/Volkar Coombs
Jackson Valley Energy
Partners California, USA 16 50.0% 8 Joint Venture-NRG/Volkar Coombs
Scudder Latin American
Power Projects Latin America 254 7.7%-10.3% 23 Stewart & Stevenson/Wartsila
Sunnyside Cogeneration
Associates Utah, USA 58 50.0% 29 Joint Venture-NRG/Babcock & Wilcox
Energy Center Kladno Czech Republic 28 18.3% 5 Energy Center Kladno
Generation Projects Total NRG Mw-
Under Construction Location MW Ownership Equity Operator
Schkopau Power Station Germany 960 20.6% 200 Veba Kraftwerke Ruhr A.G.
Generation Projects Total NRG Mw-
Under Development(4) Location MW Ownership Equity Operator
O'Brien Environmental
Energy, Inc. New Jersey, USA 203 42% 85 Stewart & Stevenson
Capitol District Energy
Center Cogeneration
Associates Connecticut, USA 56 50% 28 Coastal
Collinsville Australia 189 50% 95 NRG
(1) Includes project write-downs of $5.0 million in 1995 and $5.0
million in 1994.
(2) Equity in operating earnings is presented net of foreign income
taxes of $6.3 million in 1995 and $3.8 million in 1994.
(3) Includes NSP-owned refuse-derived fuel operations managed by NRG.
(4) Projects under development may or may not be completed.
ENVIRONMENTAL MATTERS
NSP's policy is to proactively prevent adverse
environmental impacts by regularly monitoring 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. NSP strives to maintain compliance with all applicable
environmental laws.
In general, NSP has been experiencing a trend
toward increasing environmental monitoring and compliance costs,
which has caused and may continue to cause slightly higher
operating expenses and capital expenditures. The Company has
spent approximately $700 million on capitalized environmental
improvements to new and existing facilities since 1968. NSP
expects to incur approximately $20 million in capital
expenditures and approximately $28 million in operating expenses
for compliance with environmental regulations in 1996. The
precise timing and amount of future environmental costs are
currently unknown. (For further discussion of environmental
costs, see "Environmental Matters" under Management's Discussion
and Analysis of Financial Condition and Results of Operations
under Item 7, and Note 15 to the Financial Statements under Item
8.)
Permits
NSP is required to seek renewals of environmental
operating permits for its facilities at least every five years.
NSP believes that it is in compliance, in all material respects,
with environmental permitting requirements.
Waste Disposal
Used nuclear fuel storage and disposal issues are
discussed in "Electric Utility Operations - Nuclear Power Plants
- - Licensing, Operation and Waste Disposal and Capability and
Demand," herein, in Management's Discussion and Analysis under
Item 7 and in Notes 14 and 15 of Notes to Financial Statements
under Item 8.
The Company and NRG have contractual commitments to
convert municipal solid waste to boiler fuel and burn the fuel
to generate electricity. NRG owns and/or operates two resource
recovery plants that produce RDF from the waste. The RDF is
burned at the Company's Red Wing and Wilmarth plants in the
Company's service area, the French Island plant in the Wisconsin
Company's service area, and the Elk River plant owned by United
Power Association. Processing and burning RDF provides an
additional economical source of electric capacity and energy,
which is beneficial to NSP's electric customers. The Company's
commitment to this program enables counties to meet state-
mandated goals to reduce the amount of solid waste now going to
landfills. In addition, the program provides for increased
materials recovery and increased use of municipal solid waste as
an energy source.
NSP has met or exceeded the removal and disposal
requirements for polychlorinated biphenyl (PCB) equipment as
required by state and federal regulations. NSP has removed
nearly all known PCB capacitors from its distribution system.
NSP also has removed nearly all known network PCB transformers
and equipment in power plants containing PCBs. NSP continues to
test and dispose of PCB-contaminated mineral oil and equipment
in accordance with regulations. PCB-contaminated mineral oil is
detoxified and reused or burned for energy recovery
at permitted facilities. Any future cleanup or remediation
costs associated with past PCB disposal practices is unknown at
this time.
Air Emissions Control And Monitoring
In 1994, the U.S. Environmental Protection Agency
(EPA) proposed new air emission guidelines for municipal waste
combustors. These proposed guidelines were finalized in
December 1995. The Minnesota Pollution Control Agency has
indicated its plans to update Minnesota state waste combustor
rules to meet or be more restrictive than the final federal
guidelines. The June 1997 effective date for the state waste
combustor rules is expected to be extended due to the issuance
of the new federal combustor rules. To meet the new federal and
state requirement, the Company must install additional pollution
control and monitoring equipment at the Red Wing plant and
additional monitoring equipment at the Wilmarth plant. The
Company is evaluating equipment to meet the requirements. The
required equipment may cost between $6 million and $10 million.
The Clean Air Act, including the Amendments of
1990, (the "Clean Air Act") calls for reductions in emissions of
sulfur dioxide and nitrogen oxides from electric generating
plants. These reductions, which will be phased in, began in
1995. The majority of the rules implementing this complex
legislation are finalized. No additional capital expenditures
are anticipated to comply with the sulfur dioxide emission
limits of the Clean Air Act. NSP has expended significant
amounts over the years to reduce sulfur dioxide emissions at its
plants. Based on revisions to the sulfur dioxide portion of the
program, NSP's emission allowance allocations for the years
1995-1999 were dramatically reduced from prior rulemaking. The
Company's Sherburne County Generating Plant (Sherco) unit 2 Low
Nox Burner Technology was upgraded in 1994 to further reduce its
emissions of nitrogen oxides. It is expected that approximately
$7 million will be spent on a similar upgrade at Sherco unit 1
in 1998. Other expenditures may be necessary upon the EPA's
finalization of remaining rules. Capital expenditures will be
required for opacity compliance in 1996-2000 at certain
facilities as discussed below.
As a part of its Clean Air Act compliance effort,
the Company is testing a type of air quality control device
called a wet electrostatic precipitator at the Sherco generating
plant. The equipment was installed in 1995 inside one of the
existing scrubber modules. Testing, anticipated to be completed
in 1996, will determine the equipment's operational requirements
and ability to reduce particulate emissions and opacity. The
equipment is being examined as one option to lower opacity from
Sherco units 1 and 2, as required by the EPA. Until testing is
completed, it is unknown whether the equipment will result in
full compliance with air quality standards, however, testing
results to date have been favorable. Total costs for equipment
to reduce particulate emissions and opacity range from $90
million for the equipment being tested to approximately $300
million for other technology options. As of Dec. 31, 1995,
approximately $3 million of these costs had already been
incurred and capitalized.
The Company has conducted testing for air toxics at
its major facilities and shared these results with state and
federal agencies. The Company also conducted research on ways
to reduce mercury emissions. This information has also been
shared with state and federal agencies. The Clean Air Act
requires the EPA to look at issuing rules for air toxic
emissions from electric utilities. A report is expected from
the EPA to Congress in 1996. There is continued interest at the
Minnesota Legislature to pass legislation restricting emissions
of air toxics in the state. The Company cannot predict what
impact these rules will have if passed.
On March 11, 1996, the Company received a Notice of
Violation from the Wisconsin Department of Natural Resources
(WDNR) stating that emissions from the Wisconsin Company's
French Island facility had exceeded allowable levels for dioxin.
The WDNR has requested a written response from the Wisconsin
Company no later than April 15, 1996, setting forth the
Wisconsin Company's plans for bringing the emissions levels back
into compliance. The Wisconsin Company is currently
investigating this matter to determine the cause of this
unexpected event. At this time, the Wisconsin 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 Wisconsin Company does not believe any fines, if levied, or
corrective actions, if required, will have a material adverse
effect on NSP's financial condition or results of operations.
Water Quality Monitoring
In compliance with federal and state laws and state
regulatory permit requirements, and also in conformance with the
Company's corporate environmental policy, the Company has
installed environmental monitoring systems at all coal and RDF
ash landfills and coal stockpiles to assess and monitor the
impact of these facilities on the quality of ground and surface
waters. Degradation of water quality in the state is prohibited
by law and requires remedial action for restoration to an agreed
upon acceptable clean-up level. The cost of overall water
quality monitoring is not material in relation to NSP's
operating results.
Site Remediation
Through the end of 1995, the Company had been
designated by the EPA or state environmental agencies as a
"potentially responsible party" (PRP) for 12 waste disposal
sites to which the Company allegedly sent hazardous materials.
Under applicable law, the Company, along with each PRP, could be
held jointly and severally liable for the total site remediation
costs. Those costs have been estimated between $123 and $126
million for all 12 PRP sites. In the event additional
remediation is necessary or unexpected costs are incurred, the
amount could be in excess of $126 million. The Company is not
aware of the other parties inability to pay, nor does it know if
responsibility for any of the sites is disputed by any party.
Settlement with the EPA, state environmental
agencies and other PRPs has been reached for eight of these
waste disposal sites for reimbursement of the past costs and
expected future costs of remedial action. By reaching early
settlement, the Company avoided litigation costs, increased
costs of investigation and remediation and possible penalties
that could have resulted and substantially increased the
Company's allocation. For the four remaining sites, neither the
amount of cleanup costs nor the final method of their allocation
among all designated PRP's has been determined. However, the
current estimate of the Company's share of future remediation
costs for all four sites is approximately $1.0 million, which
has been recorded as a liability at Dec. 31, 1995.
Until final settlement, neither the amount of
cleanup costs nor the final method of their allocation among all
designated PRPs can be determined. While it is not feasible to
determine the precise outcome of these matters, amounts accrued
represent the best current estimate of the Company's future
liability for the cleanup costs of these sites. It is the
Company's practice to vigorously pursue and, if necessary,
litigate with insurers to recover costs. Through litigation,
the Company has recovered from other PRPs a portion of the
remedial costs paid to date. Management also believes that
costs incurred in connection with the sites, which are not
recovered from insurance carriers or other parties, may be
recoverable in future ratemaking.
Both the Company and the Wisconsin Company have
received notices for requests for information concerning
groundwater contamination at a landfill site in Wisconsin.
While neither the Company nor the Wisconsin Company have been
named PRP's, both companies voluntarily joined a group of other
parties to address the contamination at this site. This site is
included in the description of the 12 Company sites described
above. In addition, the administrator of a group of PRP's has
notified the Wisconsin Company that it might be responsible for
cleanup of a solid and hazardous waste landfill site. The
Wisconsin Company contends that it did not dispose of hazardous
wastes in the subject landfill during the time period in
question. Because neither the amount of cleanup costs nor the
final method of their allocation among all designated PRP's has
been determined, it is not feasible to predict the outcome of
the matter at this time.
On March 2, 1995, the WDNR notified the Wisconsin
Company that it is a PRP at a creosote/coal tar contamination
site in Ashland, Wisconsin. At this time, the WDNR has
determined that the Wisconsin Company is the only PRP at this
site. The site has three distinct portions - the Wisconsin
Company portion of the site, the Kreher Park portion of the site
and the Chequamegon Bay (of Lake Superior) portion of the site.
The Wisconsin Company portion of the site, formerly a coal gas
plant site, is Wisconsin Company property. The Kreher Park
portion of the site is adjacent to the Wisconsin Company site
and is not owned by the Wisconsin Company. The Chequamegon Bay
portion of the site is adjacent to the Kreher Park portion of
the site and is not owned by the Wisconsin Company. The
Wisconsin Company is discussing its potential involvement in the
Kreher Park and Chequamegon Bay portions of the site with the
WDNR and the City of Ashland.
On Feb. 19, 1996, the Wisconsin Company received a
draft report from the WDNR's consultant 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 some
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
Wisconsin 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 Wisconsin Company's
responsibility, if any, for sharing the costs, the ultimate cost
to the Wisconsin Company and the expected timing of any payments
related to the Ashland site is not determinable. At Dec. 31,
1995, the Wisconsin 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.
The Company is continuing to investigate 15
properties either presently or previously owned by the Company
which were, at one time, sites of gas manufacturing or storage
plants, or coal gas pipelines. The purpose of this
investigation is to determine if waste materials are present, if
such materials constitute an environmental or health risk, if
the Company has any responsibility for remedial action and if
recovery under the Company's insurance policies can contribute
to any remediation costs. The Company has commenced remediation
efforts at five of the 15 sites. One of the active sites has
been completed, while the remaining four are in various stages
of remediation. Monitoring continues at the completed site. In
addition, the Company has been notified that two other sites
will require remediation, and a study will be initiated in 1996
to determine the cost and method of clean up. Clean up is
expected to begin in 1997. The total cost of remediation of
these sites is expected to be approximately $13 million,
including $6.7 million which has been paid to date. As for the
eight inactive sites, no liability has been recorded for
remediation or investigation because the present land use at
each of these sites does not warrant a response action.
Management believes costs incurred in connection with the sites
that are not recovered from insurance carriers or other parties
may be allowable costs for future ratemaking purposes. In 1994
the Company received MPUC approval of deferred accounting for
certain investigation and remediation expenses associated with
four active gas sites. The ultimate rate treatment of any costs
deferred will be determined in the Company's future general gas
rate cases. (See Note 15 of Notes to the Financial Statements
under Item 8 for further discussion of this matter.)
NSP has not developed any specific site restoration
and exit plans for its fossil fuel plants, hydroelectric plants
or substation sites as it currently intends to operate at these
sites indefinitely. NSP intends to treat any future costs
incurred related to decommissioning and restoration of its non-
nuclear 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).
Contingencies
Electric and magnetic fields (sometimes referred to
as EMF) surround electric wires and conductors of electricity
such as electrical tools, household wiring, appliances, electric
distribution lines, electric substations and high-voltage
electric transmission lines. NSP owns and operates many of
these types of facilities. Some studies have found statistical
associations between surrogates of EMF and some forms of cancer.
The nation's electric utilities, including NSP, have
participated in the sponsorship of more than $50 million in
research to determine the possible health effects of EMF.
Through its participation with the Electric Power Research
Institute and the EMF Research and Public Information
Dissemination Program, sponsored by the National Institute of
Environmental Health Sciences and the U.S. Department of Energy,
NSP will continue its investigation and research with regard to
possible health effects posed by exposure to EMF. No litigation
has been commenced or claims asserted against NSP for adverse
health effects related to EMF. However, several immaterial
claims have been asserted against NSP for diminution of property
values due to EMF. No litigation has commenced or is expected
from these claims.
Both regulatory requirements and environmental
technology change rapidly. Accordingly, NSP cannot presently
estimate the extent to which it may be required by law, in the
future, to make additional capital expenditures or to incur
additional operating expenses for environmental purposes. NSP
also cannot predict whether future environmental regulations
might result in significant reductions in generating capacity or
efficiency or otherwise affect NSP's income, operations or
facilities.
CAPITAL SPENDING AND FINANCING
NSP's capital spending program is designed to
assure that there will be adequate generating and distribution
capacity to meet the future electric and gas needs of its
utility service area, and to fund investments in non-regulated
businesses. NSP continually reassesses needs and, when
necessary, appropriate changes are made in the capital
expenditure program.
Total NSP capital expenditures (including allowance
for funds used during construction and excluding business
acquisitions and equity investments in non-regulated projects)
totaled $401 million in 1995, compared to $409 million in 1994
and $362 million in 1993. These capital expenditures include
gross additions to utility property of $386 million, $387
million and $357 million, (excluding Viking property acquired in
1993) for years ended 1995, 1994 and 1993, respectively.
Internally generated funds could have provided approximately 85
percent of all capital expenditures for 1995, 69 percent for
1994 and 99 percent for 1993.
NSP's utility capital expenditures (including
allowance for funds used during construction) are estimated to
be $410 million for 1996 and $1.9 billion for the five years
ended Dec. 31, 2000. Included in NSP's projected utility
capital expenditures is $50 million in 1996 and $250 million
during the five years ended Dec. 31, 2000, for nuclear fuel for
NSP's three existing nuclear units. The remaining capital
expenditures through 2000 are for many utility projects, none of
which are extraordinarily large relative to the total capital
expenditure program. Internally generated funds from utility
operations are expected to equal approximately 90 percent of the
1996 utility capital expenditures and approximately 100 percent
of the 1996-2000 utility capital expenditures. Internally
generated funds from all operations are expected to equal
approximately 75 percent and 90 percent respectively, of NSP's
total capital requirements (including equity investments in non-
regulated projects as discussed below) anticipated for 1996 and
the five-year period 1996-2000. The foregoing estimates of
utility capital expenditures and internally generated funds may
be subject to substantial changes due to unforeseen factors,
such as changed economic conditions, competitive conditions,
resource planning, new government regulations, changed tax laws
and rate regulation.
In addition to capital expenditures, NSP invested
$54 million in 1995, $137 million in 1994 and $184 million in
1993 for interests in existing and additional non-regulated
businesses and Viking. Investments in 1993 included business
acquisitions of $159 million. (See "Gas Utility Operations -
Viking Gas Transmission Company" and "Non-Regulated
Subsidiaries" herein.) NSP and its subsidiaries continue to
evaluate opportunities to enhance its competitive position and
shareholder returns through strategic acquisitions of existing
businesses. Long-term financing may be required for any such
future acquisitions that NSP (including its subsidiaries)
consummates.
Although they may vary depending on the success,
timing, level of involvement in planned and future projects and
other unforeseen factors, potential capital requirements for
investments in existing and additional non-regulated projects
are estimated to be $140 million in 1996 and $550 million for
the five-year period 1996-2000. The majority of these non-
regulated capital requirements relate to equity investments
(excluding costs financed by project debt) in NRG's projects, as
discussed previously and include commitments for certain NRG
investments, as discussed in Note 15 of Notes to the Financial
Statements under Item 8. The remainder consists mainly of
affordable housing investments by Eloigne Company. Equity
investments by NRG and Eloigne would be funded through their own
internally generated funds, equity investments by NSP, or long-
term debt issued by the subsidiary. Such equity investments by
NSP are expected to be financed on a long-term basis through
NSP's internally generated funds or through NSP's issuance of
common stock.
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1995 the total number of full- and
part-time employees of NSP was approximately 7,505. Of this
number approximately 2,900 employees are represented by five
local IBEW labor unions under a three year collective bargaining
agreement expiring Dec. 31, 1996.
Recent changes to NSP's employee and retiree
benefits, which support NSP's 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 percent in 1994 and 20 percent 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 percent in 1999.
401(k) changes: NSP currently offers eligible
employees a 401(k) Retirement Savings Plan. In 1994, NSP began
matching employees' pre-tax 401(k) contribution for a total of
$2.6 million. NSP's matching contributions were $3.7 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 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
bargaining employees will increase to $600 in 1996.
Wage increases: Under a market-based pay structure
implemented for nonbargaining employees in 1994, NSP 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 percent, while bargaining employees received a 2 percent
base wage increase and 1.5 percent lump sum payment. In January
1996, nonbargaining employees received an average wage scale
increase of 4 percent, while bargaining employees received a 4
percent base wage increase.
EXECUTIVE OFFICERS *
Present Positions and Business Experience
Name Age During the Past Five Years
James J Howard 60 Chairman of the Board, President and Chief Executive
Officer since 12/1/94; and prior thereto Chairman of
the Board and Chief Executive Officer.
Douglas D Antony 53 President - NSP Generation since 9/07/94; Vice
President - Nuclear Generation from 1/01/93 to 9/06/94;
and prior thereto General Manager - Monticello Nuclear Site.
Loren L Taylor 49 President - NSP Electric since 10/27/94; Vice President
- Customer Operations from 1/01/93 to 10/26/94; and
prior thereto Vice President - Transmission and Inter-
Utility Services.
Keith H Wietecki 46 President - NSP Gas since 1/11/93; Vice President -
Corporate Strategy from 1/01/93 to 1/10/93; and prior
thereto Vice President - Electric Marketing & Sales.
Arland D Brusven 63 Vice President - Finance since 7/01/94; Vice President -
Finance and Treasurer from 1/01/93 to 6/30/94; and prior
thereto Vice President and Treasurer.
Jackie A Currier 44 Vice President and Treasurer since 7/01/94; Vice
President - Corporate Strategy from 1/11/93 to 6/30/94;
Director - Corporate Finance and Assistant Treasurer from
9/17/92 to 1/10/93; and prior thereto Director -
Corporate Finance.
Gary R Johnson 49 Vice President & General Counsel since 11/01/91; and prior
thereto Vice President - Law.
Cynthia L Lesher 47 Vice President - Human Resources since 3/01/92; Director -
Power Supply Human Resources from 8/15/91 to 2/29/92; and
prior thereto Manager - White Bear Lake Area.
Edward J McIntyre 45 Vice President and Chief Financial Officer since 1/01/93;
and prior thereto President and Chief Executive Officer of
Northern States Power Company (a Wisconsin corporation), a
wholly owned subsidiary of the Company.
Thomas A Micheletti 49 Vice President - Public and Government Affairs since 10/27/94;
Vice President - General Counsel and Secretary of NRG Energy,
Inc. a wholly owned subsidiary of the Company from 5/11/94 to
10/26/94; Vice President-General Counsel, NRG from 9/15/93 to
5/10/94; and prior thereto Group Vice President for Minnesota
Power and Light Company, a public utility located in Duluth, MN.
Roger D Sandeen 50 Vice President, Controller and Chief Information Officer since
4/22/92; and prior thereto Vice President and Controller.
Edward L Watzl 56 Vice President - Nuclear Generation since 9/07/94; and
prior thereto Prairie Island Site General Manager.
* As of 3/01/96
Item 2 - Properties
The Company's major electric generating facilities consist of
the following:
1995
Capability Output
Station and Unit Fuel Installed (Mw) (Millions of Kwh)
Sherburne
Unit 1 Coal 1976 712 4 130.4
Unit 2 Coal 1977 712 4 212.5
Unit 3 Coal 1987 514 3 989.8
Prairie Island
Unit 1 Nuclear 1973 514 4 522.9
Unit 2 Nuclear 1974 513 3 964.3
Monticello Nuclear 1971 544 4 756.3
King Coal 1968 567 3 202.7
Black Dog
4 Units Coal/Natural 1952-1960 461 1 411.3
Gas
High Bridge
2 Units Coal 1956-1959 262 932.0
Riverside
2 Units Coal 1964-1987 366 1 959.8
Other Various Various 1,934 1 769.3
NSP's electric generating facilities provided 79
percent of its Kwh requirements in 1995. The current generating
facilities are expected to be adequate base load sources of
electric energy until 2003-2006, as detailed in the Company's
electric resource plan filed with the MPUC in 1995. All of
NSP's major generating stations are located in Minnesota on land
owned by the Company.
In late 1995, NSP converted three of its older, less
efficient generating units from an intermediate load status to
peaking plant operations. This change is expected to save
approximately $3 million annually. The Company's 47 Mw
Minnesota Valley generating plant in Granite Falls and the 65 Mw
Black Dog Unit 1 in Burnsville will be dispatched as peaking
units and fired on 100 percent natural gas. Black Dog Unit 2,
with capacity of approximately 100 Mw, will also be dispatched
as a peaking unit but will continue to be fired on coal.
At Dec. 31, 1995, NSP had transmission and distribution
lines as follows:
Voltage Length (Pole Miles)
500Kv 265
345Kv 733
230Kv 283
161Kv 339
115Kv 1,650
Less than 115 Kv 31,509
NSP also has approximately 300 transmission and
distribution substations with capacities greater than 10,000
kilovoltamperes (Kva) and approximately 270 with capacities less
than 10,000 Kva.
Manitoba Hydro, Minnesota Power Company and the
Company completed the construction of a 500-Kv transmission
interconnection between Winnipeg, Manitoba, Canada, and the
Minneapolis-St Paul, Minnesota, area in May 1980. NSP has a
contract with Manitoba Hydro-Electric Board for 500 Mw of firm
power utilizing this transmission line. In addition, the
Company is interconnected with Manitoba Hydro through a 230 Kv
transmission line completed in 1970. In May of 1995 a project
was completed to increase the Manitoba-US transmission
interconnection by a nominal 400 Mw, to 1900 Mw. This project
was undertaken as part of a contract where NSP and Manitoba
Hydro have established an additional 150 Mw of seasonal power
exchange. (Also, see Note 15 of Notes to Financial Statements
under Item 8.)
The electric delivery system utilization has
increased during recent years due to better analytical methods
and enhanced Energy Management System monitoring and control
capability. This increased utilization has been achieved while
continuing to operate within reliability parameters established
by MAPP and North American Electric Reliability Council (NERC).
In April 1995, a plan was completed to determine
electric delivery system upgrades required to accommodate load
growth expected in the Minneapolis/St. Paul geographic area
through 2010. The results indicated load growth at a rate of
approximately 2 percent per year. To accommodate the load
growth, portions of the 69 Kv transmission, especially located
on the outskirts of the Twin Cities, will be reconductored and
operated at 115 Kv; distribution development in these areas will
largely be at 34.5 Kv. By reconductoring on existing right-of-
ways and increasing distribution voltage, the requirements for
new right-of-ways and substation sites are minimized as compared
with other alternatives for serving the load growth.
The natural gas properties of NSP include about
8,060 miles of natural gas transmission and distribution mains.
NSP natural gas mains include approximately 116 miles with a
capacity in excess of 275 pounds per square inch (psi) and
approximately 7,944 miles with a capacity of less than 275 psi.
In addition, Viking owns a 500-mile interstate natural gas
pipeline serving portions of Minnesota, Wisconsin and North
Dakota.
Virtually all of the utility plant of the Company
and the Wisconsin Company are subject to the lien of their first
mortgage bond indentures pursuant to which they have issued
first mortgage bonds.
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits
and claims have arisen against NSP. Management, after
consultation with legal counsel, has recorded an estimate of the
probable cost of settlement or other disposition for such
matters.
On July 22, 1993, a natural gas explosion occurred
on the Company's distribution system in St. Paul, MN. Seventeen
lawsuits have been filed against the Company in regard to the
explosion, including one suit with multiple plaintiffs. In
April 1995, the National Transportation Safety Board concluded
the City of St. Paul contractors were largely responsible for
the natural gas explosion. The report found little, if any,
fault with the actions taken by or conduct of the Company. A
trial to decide civil liability and the parties responsible for
the explosion has been scheduled for February 1997, with the
damages portion of the trial scheduled for six months
thereafter.
In February 1996, the Company and Westinghouse
Electric Corp. (Westinghouse) reached a settlement in principle
of a lawsuit which the Company had filed against Westinghouse
related to steam generators installed at the Company's Prairie
Island plant. The parties have agreed to keep the specific
terms of the settlement confidential. The Company expects to
share all of the benefits of the settlement with its customers.
On June 20, 1994, the Company and 13 other major
utilities filed a lawsuit against the Department of Energy (DOE)
in an attempt to clarify the DOE's obligation to accept spent
nuclear fuel beginning in 1998. The suit was filed in the U.S.
Court of Appeals, Washington, D.C. The primary purpose of the
lawsuit is to insure that the Company and its customers receive
timely storage of used nuclear fuel in accordance with the terms
of the Company's contract with the DOE. The lawsuit was argued
before the United States Circuit Court of Appeals for the
District of Columbia on Jan. 17, 1996, and a decision is
expected in three to six months from the time of argument.
The Federal Energy Regulatory Commission (FERC) made
a favorable decision for the Company regarding its Sherco unit
3 transmission contracts with the Southern Minnesota Municipal
Power Agency (SMMPA). A hearing judge had previously issued
several rulings in favor of the Company, but had refused to find
SMMPA obligated to pay for any transmission service since
deliveries had commenced on November 1, 1987. FERC reversed and
ordered SMMPA to pay for the 172 megawatts (MW) of transmission
service in an amount determined by applying NSP's filed wheeling
rate. It is anticipated that SMMPA will appeal. NSP will ask
FERC to reconsider its decision as to the total transmission
service SMMPA is responsible for because NSP believes SMMPA owes
for 56 Mw more than FERC allowed. Until the appeal and
reconsideration processes are complete, the ultimate impact of
this decision on NSP's results of operation and financial
condition are not determinable.
For a discussion of environmental proceedings, see
"Environmental Matters" under Item 1, incorporated herein by
reference. For a discussion of proceedings involving NSP's
utility rates, see "Utility Regulation and Revenues" under Item
1, incorporated herein by reference.
Item 4 - Submission of Matters to a Vote of Security Holders
None
PART II
Item 5 - Market for Registrant's Common Equity and Related
Stockholder Matters
Quarterly Stock Data
The Company's common stock is listed on the New York
Stock Exchange (NYSE), Chicago Stock Exchange (CHX) and the
Pacific Stock Exchange (PSE). Following are the reported high
and low sales prices based on the NYSE Composite Transactions
for the quarters of 1995 and 1994 and the dividends declared per
share during those quarters:
1995 1994
High Low Dividends High Low Dividends
First Quarter $46 3/4 $42 1/2 $.660 $43 7/8 $40 1/8 $.645
Second Quarter 47 3/8 42 7/8 .675 43 5/8 38 3/4 .660
Third Quarter 46 7/8 42 1/2 .675 43 7/8 40 3/8 .660
Fourth Quarter 49 1/2 45 1/8 .675 47 41 7/8 .660
The Company's Restated Articles of Incorporation
and First Mortgage Bond Trust Indenture provide for certain
restrictions on the payment of cash dividends on common stock.
At Dec. 31, 1995, the payment of cash dividends on common stock
was not restricted except as described in Note 5 to the
Financial Statements under Item 8.
For a discussion of the anticipated dividend
payment level of Primergy, see "Proposed Merger with Wisconsin
Energy Corporation" under Item 1, incorporated herein by
reference.
1995 1994 1993 1992 1991
Shareholders of record
at year-end 83 902 85 263 86 404 72 525 72 704
Book value per share
at year-end $29.74 $28.35 $27.32 $25.91 $25.21
Shareholders of record as of March 15, 1996 were 83,517.
Item 6 - Selected Financial Data
1995 1994 1993 1992 1991(2) 1985(2)
(Dollars in millions except per share data)
Utility operating
revenues $2 568.6 $2 486.5 $2 404.0 $2 159.5 $2 201.1 $1 778.3
Utility operating
expenses $2 222.7 $2 178.2 $2 100.1 $1 903.5 $1 895.6 $1 531.6
Income from continuing
operations before
accounting change (1) $275.8 $243.5 $211.7 $160.9 $207.0 $195.8
Net income (3) $275.8 $243.5 $211.7 $206.4 $224.1 $197.7
Earnings available for
common stock $263.3 $231.1 $197.2 $190.3 $206.1 $184.7
Average number of common
and equivalent shares
outstanding (000's) 67 416 66 845 65 211 62 641 62 566 62 274
Earnings per average
common share:
Continuing operations
before accounting
change (1) $3.91 $3.46 $3.02 $2.31 $3.02 $2.94
Total (3) $3.91 $3.46 $3.02 $3.04 $3.29 $2.97
Dividends declared
per share $2.685 $2.625 $2.565 $2.495 $2.395 $1.725
Total assets $6 228.6 $5 949.7 $5 587.7 $5 142.5 $4 918.8 $4 047.6
Long-term debt $1 542.3 $1 463.4 $1 291.9 $1 299.9 $1 233.9 $1 252.5
Ratio of earnings (from
continuing operations
before accounting change,
excluding undistributed
equity income and including
AFC) to fixed charges 3.9 4.0 4.0 3.2 3.9 4.7
Notes:
(1) Income and earnings from continuing operations
exclude discontinued telephone operations (in 1991 and prior
years) and an accounting change (in 1992). They include non-
recurring items in 1994 and 1995, as discussed in
Management's Discussion and Analysis under Item 7.
(2) Operating revenues and operating expenses in years
prior to 1992 have been restated to exclude the results of
discontinued telephone operations.
(3) In 1992, the Company changed its method of
accounting for revenue recognition to begin recording unbilled
revenue. The cumulative effect of this accounting change was an
increase in net income of $45.5 million after tax, or $0.73 per
share.
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations
Northern States Power Company, a Minnesota corporation (the
Company), has two significant subsidiaries, Northern States
Power Company, a Wisconsin corporation (the Wisconsin Company),
and NRG Energy, Inc., a Delaware corporation (NRG). The Company
also has several other subsidiaries, including Viking Gas
Transmission Company (Viking) and Cenergy, Inc., (Cenergy). The
Company and its subsidiaries collectively are referred to herein
as NSP.
FINANCIAL RESULTS AND OBJECTIVES
1994 Financial Results
NSP's 1995 earnings per share were $3.91, an increase of 45
cents, or 13.0 percent, over the $3.46 earned in 1994. The
effects of sales growth in the core electric and gas utility
businesses, favorable weather and reduced operating and
maintenance costs more than offset higher costs for
depreciation, tax and interest expenses. This provided a
regulated utility earnings increase of 44 cents, or 14.8
percent, from 1994. In 1995, non-regulated businesses
contributed earnings of 50 cents, up 1 cent, or 2.0 percent,
from 1994 earnings. Investor returns also were enhanced in 1995
by an increase in the common dividend rate, as discussed below.
NSP remained financially strong in 1995, as evidenced by
continued high operating cash flows and interest coverage. NSP
maintained its first mortgage bond ratings with all rating
agencies during 1995. NSP bonds are rated double A by all rating
agencies except Moody's Investors Services (Moody's). Moody's
downgraded NSP's first mortgage bond ratings in May 1994 to A1
based on its interpretation of provisions of a Minnesota law
enacted in 1994 regarding the used fuel storage project for the
Prairie Island nuclear generating plant. (See discussion of this
legislation in Notes 14 and 15 to the Financial Statements.) In
1995, Moody's placed the Company's ratings on credit review for
possible upgrade based on anticipated cost savings from the
proposed merger with Wisconsin Energy Corporation, which is
discussed later.
Total Return
Total return to investors is measured by dividends plus
stock price appreciation. NSP's common dividend rate increased
by more than 2 percent and its stock price increased by 11.6
percent in 1995. For the most recent 15-, 10- and five-year
periods, the total return on NSP common stock averaged 18.1
percent, 12.7 percent and 13.8 percent per year, respectively.
For the same periods, the total return for the Standard & Poor's
(S&P) composite stock index for 500 industrial companies
averaged 14.8 percent, 14.8 percent and 16.5 percent per year,
respectively.
Financial Objectives
NSP's financial objectives are:
- To provide investor returns in the top one-fourth of the
utility industry as measured by a three-year average
return on equity. NSP's average return on common equity
for the three years ending in 1995 was 12.5 percent.
Based on a three-year average, this return was below the
top one-fourth of the industry, which was approximately
13.0 percent, but above the median three-year industry
average of approximately 11.6 percent.
- To increase dividends on a regular basis and maintain a
long-term average payout ratio in the range of 65 to 75
percent. The objective payout ratio is based on long-term
earnings expectations. In June 1995, NSP's annualized
common dividend rate was increased by 6 cents per share,
or 2.3 percent, from $2.64 to $2.70. The dividend payout
ratio was 69 percent in 1995, within the objective range.
- To maintain continued financial strength with a double A
bond rating. The Company's first mortgage bonds continued
to be rated AA- by S&P, AA- by Duff & Phelps, Inc. and AA
by Fitch Investors Service, Inc. Since May 1994, Moody's
has rated NSP's first mortgage bonds A1 based on its
interpretations of a Minnesota law enacted in 1994
regarding the used fuel storage project for the Prairie
Island nuclear generating plant. First mortgage bonds
issued by the Wisconsin Company carry comparable ratings.
NSP's pretax interest coverage ratio, based on income
without Allowance for Funds Used During Construction
(AFC), was 3.8 in 1995. A capital structure consisting of
48.4 percent common equity at year-end 1995, including
both regulated and non-regulated operations, contributes
to NSP's financial flexibility and strength.
- To provide at least 20 percent of NSP earnings from NRG
businesses by the year 2000. NRG expects to meet this
goal through growing profitability of existing businesses
and the addition of new businesses. Businesses owned or
managed by NRG provided 12.4 percent of NSP's earnings in
1995 and 13.5 percent in 1994.
- To maintain long-term average annual earnings growth of
5 percent from ongoing operations, as described below.
Excluding the non-recurring items discussed later under
Factors Affecting Results of Operations, NSP achieved
earnings per share growth of 7.0 percent in 1995 over
1994 and an average annual growth of 10.5 percent since
1993.
1995 1994 1993
Total earnings per share $3.91 $3.46 $3.02
Less earnings from
non-recurring items 0.22 0.01
Earnings from ongoing
operations $3.69 $3.45 $3.02
Total earnings per share increased 13.0 percent in 1995 over 1994.
Business Strategies
NSP's management is proactive in shaping the new business
environment in which it will be operating. In April 1995,
the Company and Wisconsin Energy Corporation (WEC) entered
into a definitive agreement that provides for a strategic
business combination in a "merger-of-equals" transaction to
operate as Primergy Corporation (Primergy), as discussed
further under Factors Affecting Results of Operations. Both
companies' management teams view this transaction as
creating a combined enterprise well-positioned for an
increasingly competitive energy industry environment. The
goal of the merger is to achieve continued competitive
energy rates over the long term for the companies'
respective customers and to enhance value for the
shareholders of both companies. In addition to this merger
strategy, management's business strategies include:
- Focusing on the core energy business. The electric
utility industry is becoming more complex as customers,
as well as utilities and federal and state regulators,
promote competition. To remain successful in this more
complex environment, NSP will maintain its focus on its
core energy-related activities.
- Providing reliable, low-cost, environmentally responsible
energy. Whether energy is produced or purchased through
NSP's regulated utility or its non-regulated businesses,
three general concepts provide a focus for its energy
businesses: reliable energy, low-cost energy and
environmentally responsible energy.
- Responding to customer needs. Customers will have an
increasing number of options for meeting their energy
needs, and there will be competition among energy
companies for the privilege of serving those customers.
NSP will work with its customers to develop innovative
products and services that benefit both customers and
NSP.
- Increasing non-regulated investments and earnings. Non-
regulated businesses will be an important part of NSP's
future. Deregulation in the utility industry is expected
to provide new investment opportunities in non-regulated
businesses. Participation in these opportunities is
expected to improve NSP's total profitability.
RESULTS OF OPERATIONS AND LIQUIDITY AND CAPITAL RESOURCES
The following discussion and analysis by management focuses on
those factors that had a material effect on NSP's financial
condition and results of operations during 1995 and 1994. It
should be read in conjunction with the accompanying Financial
Statements and Notes thereto. Trends and contingencies of a
material nature are discussed to the extent known and considered
relevant. Material changes in balance sheet items are discussed
below and in the accompanying Notes to Financial Statements. The
discussion and analysis and the related financial statements do
not reflect the impact of the Company's proposed merger with WEC
except for pro forma information included in Note 18 to the
Financial Statements.
RESULTS OF OPERATIONS
1995 Compared with 1994 and 1993
NSP's 1995 earnings per share were $3.91, up 45 cents from the
$3.46 earned in 1994 and up 89 cents from the $3.02 earned in
1993. Regulated utility businesses generated earnings per share
of $3.41 in 1995, $2.97 in 1994 and $2.93 in 1993. Non-regulated
businesses generated earnings per share of 50 cents in 1995, 49
cents in 1994 and 9 cents in 1993. The results of the regulated
utility businesses and the non-regulated businesses are
discussed in more detail later. In addition to the revenue and
expense changes, earnings per share have been affected by an
increasing average number of common and equivalent shares
outstanding. Common and equivalent shares increased in 1995 and
1994 due mainly to stock issuances for the Company's dividend
reinvestment and stock ownership plans.
Utility Operating Results
Electric Revenues Sales to retail customers, which account for
more than 90 percent of NSP's electric revenue, increased 4.2
percent in 1995 and 3.9 percent in 1994. Retail revenues were
favorably affected by sales growth, weather and increased cost
recovery for conservation expenditures. During 1995, NSP added
18,297 retail electric customers, a 1.3 percent increase. Total
sales of electricity increased 2.9 percent in 1995 and decreased
0.2 percent in 1994. Warmer-than-normal summer weather in 1995
contributed to sales growth compared with 1994, which had a
cooler-than-normal summer.
On a weather-adjusted basis, sales to retail customers
increased an estimated 2.4 percent in 1995 and 3.4 percent in
1994. Retail sales growth for 1996 is estimated to be 0.8
percent over 1995, or 1.9 percent on a weather-adjusted basis.
Sales to other utilities increased 1.0 percent in 1995
after decreasing 21.6 percent in 1994. The 1994 decrease from
1993 largely was due to unusually high demand in 1993 from
utilities in flood-stricken Midwestern states.
The table below summarizes the principal reasons for the
electric revenue changes during the past two years:
(Millions of dollars) 1995 vs. 1994 1994 vs. 1993
Retail sales growth (excluding weather
impacts) $ 46 $ 56
Estimated impact of weather on retail
sales volume 42 8
Sales to other utilities 1 (20)
Wholesale sales (13) 7
Conservation cost recovery 19 2
Fuel adjustment clause recovery (7) 23
Other rate changes (2) 15
Energy management discounts
and other (10) 1
Total revenue increase $ 76 $ 92
NSP's electric rates are adjusted for changes in fuel and
purchased energy costs from amounts currently included in
approved base rates through fuel adjustment clauses in all
jurisdictions, except as noted below for Wisconsin. While the
lag in implementing these billing adjustments is approximately
60 days, an estimate of the adjustments is recorded in unbilled
revenue in the month in which costs are incurred. In Wisconsin,
the biennial retail rate review process considers changes in
electric fuel and purchased energy costs in lieu of a fuel
adjustment clause.
In 1995, a new rate adjustment clause was approved. It
accelerated recovery of deferred electric conservation and
energy management program costs in the Company's Minnesota
jurisdiction. This adjustment clause helps reduce the need for
filing a general rate increase request for recovery of increases
in conservation expenditures. The Company is required to request
a new cost recovery level annually. In January 1996, a number of
changes to the Company's regulatory deferral and amortization
practices for Minnesota conservation program expenditures were
approved. These changes allow the Company to expense rather than
amortize new conservation expenditures beginning in 1996 and to
increase its recovery of electric margins lost due to
conservation activity. In addition, the Company received
approval for 1996 and 1997 conservation expenditures at levels
lower than 1995. On April 1, 1996, the Company expects to file
for annual changes to the Minnesota conservation rate adjustment
clause with an effective period of July 1, 1996, through June
30, 1997. Revenues in 1996 are expected to increase by an
estimated $17 million, compared with 1995, due to the effects of
the rate recovery changes for conservation programs in 1995 and
1996. These revenue increases will be largely offset by a
corresponding increase in conservation expenses.
Electric Production Expenses Fuel expense for electric
generation increased $4.5 million, or 1.4 percent, in 1995
compared with an increase of $5.6 million, or 1.8 percent, in
1994. The 1995 increase was primarily attributable to an
increase in output from NSP's generating plants, resulting from
increased sales and fewer scheduled plant maintenance outages.
Although output from NSP's generating plants declined slightly
in 1994 because of more scheduled fossil plant maintenance
outages, fuel expenses were higher in 1994 because of the higher
cost of nuclear fuel per megawatt-hour due to increased payments
to the U.S. Department of Energy (DOE) for decommissioning and
decontamination of the DOE's uranium enrichment facilities and
nuclear fuel disposal costs. In addition, the costs of fossil
fuel were higher in 1994 because of fewer coal purchases at the
lowest contractual prices due to lower fossil plant output.
Purchased power costs decreased $5.2 million, or 2.1
percent, in 1995 after increasing $41.1 million, or 19.7
percent, in 1994. The decrease in 1995 was primarily due to
lower average market prices and less energy purchased. The level
of purchases declined due to fewer scheduled plant maintenance
outages in 1995. The increase in 1994 primarily was due to
additional demand expenses of $21 million for the full-year
impact of capacity charges from the power purchase agreements
with the Manitoba Hydro-Electric Board (MH), which went into
effect in May 1993, as discussed in Note 15 to the Financial
Statements. In addition to demand expenses, purchased power
costs increased from 1993 due to higher average market prices
and increased purchases because of more plant maintenance
outages in 1994.
Gas Revenues The majority of NSP's retail gas sales are
categorized as firm (primarily space heating customers) and
interruptible (commercial/industrial customers with an alternate
energy supply). Firm sales in 1995 increased 6.8 percent
compared with 1994 sales, while firm sales in 1994 decreased 5.4
percent compared with 1993 sales. The 1995 increase primarily is
due to increased sales of natural gas resulting from 16,680
additional new firm gas customers, a 4.1 percent increase, and
slightly more favorable weather in 1995. The 1994 decrease was
due largely to warm weather in the last quarter of 1994.
On a weather-adjusted basis, firm sales are estimated to
have increased 4.6 percent in 1995 and decreased 0.7 percent in
1994. Firm gas sales in 1996 are estimated to increase by 2.6
percent relative to 1995, a 3.6 percent increase on a weather-
adjusted basis.
Interruptible sales of gas increased 15.7 percent in 1995
and 4.4 percent in 1994. The 1995 increase is the result of
favorable gas market prices that caused large interruptible
customers with alternate fuel sources to use more natural gas.
Other gas deliveries increased 46.1 percent primarily due to
additional gas sales to off-system customers. Other gas
deliveries increased 65.7 percent in 1994 due to gas sales to
off-system customers. Viking wholesale transmission deliveries
increased 1.1 percent in 1995. These wholesale deliveries
increased 74.3 percent in 1994 due to a full year of Viking
activity.
The table below summarizes the principal reasons for the
gas revenue changes during the past two years.
(Millions of dollars) 1995 vs 1994 1994 vs 1993
Sales growth (excluding
weather impacts) $26 $0
Estimated impact of weather on
firm sales volume 7 (8)
Sales to off-system customers 2 14
Purchased gas adjustment clause
recovery (26) (24)
Rate changes and other (3) 4
Viking Gas (acquired in
June 1993) 5
Total revenue increase
(decrease) $6 $(9)
NSP's retail gas rates are adjusted for changes in
purchased gas costs from amounts currently included in approved
base rates through purchased gas adjustment clauses in all
jurisdictions. Effective November 1995, a new rate adjustment
clause was approved that accelerated recovery of deferred gas
conservation and energy management program costs in the
Company's Minnesota jurisdiction, similar to the retail electric
rate clause discussed previously. The Company estimates it will
receive an additional $2.7 million in revenues from this new
rate mechanism in 1996 compared with 1995. This increased
recovery will result in a corresponding increase in conservation
expenses.
Cost of Gas Purchased and Transported The cost of gas purchased
and transported decreased $7.1 million, or 2.7 percent, in 1995
primarily due to a 12.6 percent decline in the per unit cost of
purchased gas, partially offset by higher sendout volumes due to
increased sales and off-system deliveries. The lower cost of
purchased gas reflects continuing favorable market pricing,
while the higher gas sendout reflects sales growth in 1995 and
higher gas sales to off-system customers. The cost of gas
associated with off-system sales was $14.3 million in 1995 and
$12.7 million in 1994. The cost of gas purchased and transported
decreased $18.6 million, or 6.6 percent, in 1994. The decrease
reflects lower gas prices and cost recovery adjustments,
partially offset by higher sendout volumes primarily for gas
sales to off-system customers. The average cost per unit of NSP-
owned gas sold in 1994 was 8.4 percent lower than it was in
1993, mainly due to lower market prices for gas.
Other Operation, Maintenance and Administrative and General
These expenses, in total, decreased by $9.1 million, or 1.4
percent, in 1995 compared with an increase of $26.0 million, or
4.0 percent, in 1994. The 1995 decrease is largely due to fewer
employees, fewer scheduled plant maintenance outages, lower
property insurance premiums and a one-time charge in 1994 for
postemployment benefits. Partially offsetting these decreases
were higher employee benefit costs, and higher electric line
maintenance costs, mostly for tree trimming and heat-related
repairs. The 1994 increase resulted primarily from higher
postretirement health care costs, including amounts deferred
from 1993, and higher postemployment costs as discussed in Note
2 to the Financial Statements. (See Note 12 to the Financial
Statements for a summary of administrative and general
expenses.)
Conservation and Energy Management Expenses in 1995 were higher
than in 1994 primarily due to higher amortization levels of
deferred conservation program costs, consistent with cost
recovery under new electric and gas rate adjustment clauses in
the Company's Minnesota jurisdiction effective May 1, 1995, and
Nov. 1, 1995, respectively. The deferred costs being amortized
are higher due to increased customer participation in NSP's
conservation and energy management programs.
Depreciation and Amortization The increases in 1995 and 1994
reflect higher levels of depreciable plant.
Property and General Taxes Property and general taxes increased
in 1995 and 1994 primarily due to property additions and higher
property tax rates.
Utility Income Taxes The variations in income taxes primarily
are attributable to fluctuations in taxable income. (See Note
9 to the Financial Statements for a detailed reconciliation of
the statutory tax rate to NSP's effective tax rate.)
Non-operating Items Related to Utility Businesses
Allowance for Funds Used During Construction (AFC) The
differences in AFC for the reported periods are attributable to
varying levels of construction work in progress and changing AFC
rates associated with various levels of short-term borrowings to
fund construction. In addition, returns allowed on deferred
costs for conservation and energy management programs increased
AFC-equity by $2.6 million and $2.0 million in 1995 and 1994,
respectively, and increased AFC-debt by the amounts of $1.5
million and $0.9 million in 1995 and 1994, respectively.
Other Income (Expense) Note 12 to the Financial Statements lists
the components of Other Income (Deductions)- Net reported on the
Consolidated Statements of Income. Other than the operating
revenues and expenses of non-regulated businesses, as discussed
in the next section, non-operating income (net of expense items
and associated income taxes) related to utility businesses
increased $5.6 million in 1995 and decreased $2.4 million in
1994. The 1995 increase primarily is due to higher expense
levels in 1994 for environmental and regulatory contingencies,
and public and governmental affairs costs related to the Prairie
Island fuel storage issue. These were partly offset by lower
interest income associated with the Company's settlement of
federal income tax disputes in 1995. The 1994 decrease primarily
is due to higher expenses for environmental and regulatory
contingencies, and higher public and governmental affairs
expenses associated with the Prairie Island fuel storage issue,
partially offset by interest income associated with the
Company's settlement of federal income tax disputes.
Interest Charges (Before AFC) Interest costs recognized for
NSP's utility businesses, including amounts capitalized to
reflect the financing costs of construction activities, were
$123.4 million in 1995, $107.1 million in 1994 and $110.4
million in 1993. The 1995 increase is largely due to long-term
debt issues in 1995 and 1994 (net of retirements) and higher
short-term interest rates, which affect commercial paper
borrowings and variable rate long-term debt. The 1994 decrease
reflects the impact of refinancing several higher-rate long-term
debt issues in 1993 and 1994. These interest savings were
partially offset by interest on higher short-term debt balances
and Viking debt (issued late in 1993). The average short-term
debt balance was $208.7 million in 1995, $204.5 million in 1994
and $77.0 million in 1993.
Preferred Dividends Dividends on the Company's preferred stock
decreased in 1994 primarily due to redemption of the $7.84
Series Cumulative Preferred Stock in October 1993.
Non-regulated Business Results
NSP's non-regulated operations include many diversified
businesses, such as independent power production, gas marketing,
industrial heating and cooling, and energy-related refuse-
derived fuel (RDF) production. NSP also has investments in
affordable housing projects and several income-producing
properties. The following discusses NSP's diversified business
results in the aggregate.
Operating Revenues and Expenses The net results of non-regulated
businesses that are consolidated are reported in Other Income
(Deductions)-Net on the Consolidated Statements of Income. (Note
12 to the Financial Statements lists the individual components
of this line item.) Non-regulated operating revenues increased
$71.3 million, or 29 percent, in 1995, and $151.3 million, or
167 percent, in 1994. The 1995 increase was largely due to
increased gas marketing sales by Cenergy. The 1994 increase was
mainly due to the impact of Cenergy gas marketing and NRG
industrial heating and cooling businesses acquired in 1993. Non-
regulated operating expenses increased in 1995 primarily due to
higher gas costs associated with Cenergy gas sales and higher
project development expenses by NRG on pending projects. Non-
regulated operating expenses increased in 1994 consistent with
revenue increases resulting from 1993 acquisitions. In addition,
such expenses increased in 1994 due to fewer project development
costs being capitalized on pending projects in 1994 compared
with 1993, and project write-downs. Non-regulated operating
expenses include charges of $5.0 million in 1995 and $5.0
million in 1994 for previously capitalized development and
investment costs to reflect a decrease in the expected future
cash flows of certain energy projects.
Equity in Operating Earnings NSP has a less-than-majority equity
interest in many non-regulated projects, as discussed in Note 3
to the Financial Statements. Consequently, a large portion of
NSP's non-regulated earnings is reported as Equity in Earnings
of Unconsolidated Affiliates on the Consolidated Statements of
Income. The 1995 decrease in equity in project operating
earnings is due to lower earnings from an NRG cogeneration
project contract that was terminated in 1995 and other domestic
projects, somewhat offset by higher earnings from NRG
international energy projects (one of which did not provide
earnings prior to the second quarter of 1994). The 1994 increase
in equity in project operating earnings primarily is due to new
international energy projects in which NRG entered during 1994
(as discussed in Note 3 to the Financial Statements), and more
profitable operations of other energy projects in which NRG had
been an investor for several years.
Equity in Gains From Contract Terminations In June 1995, after
receiving final regulatory approvals, a power sales contract
between a California energy project, in which NRG is a 45
percent investor, and an unaffiliated utility company was
terminated. A pretax gain of approximately $30 million was
recognized by NRG for its share of the termination settlement.
In 1994, a Michigan cogeneration project, in which NRG was a 50
percent investor, received a payment from an unaffiliated
utility company as compensation for the termination of an energy
purchase agreement. A pretax gain of $9.7 million was recognized
by NRG for its share of the contract termination settlement, net
of project investment costs.
Other Income (Expense) Other than the operating revenues and
expenses of non-regulated businesses, as discussed above, non-
operating income (net of expense items) related to non-regulated
businesses increased $4.7 million in 1995 and increased $0.8
million in 1994. The 1995 increase primarily is due to a gain on
the sale of Cenergy oil and gas properties, higher income from
cash investments, and an adjustment to the 1994 contract
termination gain recorded by NRG.
Interest Expense Interest charges on the Consolidated Statements
of Income include interest and amortization expenses related to
non-regulated businesses. The expenses were $9.9 million in
1995, $8.0 million in 1994 and $3.1 million in 1993. The
increase in 1995 mainly is due to the issuance of long-term debt
on new affordable housing projects by Eloigne Company, a wholly
owned subsidiary of the Company. The increase in 1994 relates
primarily to non-utility long-term debt issued to finance the
1993 acquisitions of NRG's industrial heating and cooling
business (Minneapolis Energy Center), a gas marketing business
now operated by Cenergy, and 1994 investments in affordable
housing projects by Eloigne Company. In addition, during 1994
and late 1993, United Power & Land and First Midwest Auto Park,
wholly owned subsidiaries of the Company, issued long-term debt
secured by non-regulated properties and lowered NSP's equity
investment in these subsidiaries.
Income Taxes The Consolidated Statements of Income include
income tax expense related to non-regulated businesses of $6.1
million in 1995, $2.6 million in 1994 and $3.5 million in 1993.
The increase in 1995 mainly is due to a gain from an NRG energy
contract termination, as discussed previously, somewhat offset
by higher income tax credits from Eloigne Company's affordable
housing projects. The decrease in 1994 mainly is due to higher
income tax credits from affordable housing projects and energy
tax credits related to an NRG project, somewhat offset by higher
taxes due to higher operating earnings, as discussed above. The
effective tax rate in 1995 and 1994 is substantially less than
the U.S. federal tax rate mainly due to the tax treatment of
income from unconsolidated international affiliates, and energy
and affordable housing tax credits, as shown in Note 9 to the
Financial Statements.
Factors Affecting Results of Operations
NSP's results of operations during 1995, 1994 and 1993 were
primarily dependent upon the operations of the Company's and
Wisconsin Company's utility businesses consisting of the
generation, transmission, distribution and sale of electricity
and the distribution, transportation and sale of natural gas.
NSP's utility revenues depend on customer usage, which varies
with weather conditions, general business conditions, the state
of the economy and the cost of energy services. Various
regulatory agencies approve the prices for electric and gas
service within their respective jurisdictions. In addition,
NSP's non-regulated businesses are contributing significantly to
NSP's earnings. The historical and future trends of NSP's
operating results have been and are expected to be affected by
the following factors:
Proposed Merger On April 28, 1995, the Company and WEC entered
into an Agreement and Plan of Merger that provides for a
business combination of NSP and WEC in a "merger-of-equals"
transaction. As a result of the mergers contemplated by the
merger agreement, Primergy will become the holding company for
the regulated operations of both the Company and the utility
subsidiary of WEC. The business combination is intended to be
tax-free for income tax purposes, and accounted for as a
"pooling of interests." On Sept. 13, 1995, more than 95 percent
of the respective shareholders of the Company and WEC voting
approved the merger plan at their respective shareholder
meetings. Under the proposed business combination, shareholders
of the Company would receive 1.626 shares of Primergy common
stock for each share of the Company's common stock owned at the
time of the merger.
After the merger is completed, a transition to a new
organization would begin. Anticipated cost savings of the new
organization (compared with the continued independent operation
of NSP and WEC) are estimated to be $2 billion over a 10-year
period, net of transaction costs (about $30 million) and costs
to achieve the merger savings (about $122 million). It is
anticipated that the proposed merger will allow the companies to
implement a modest reduction in electric retail rates and a
four-year rate freeze for electric retail customers. In
addition, the companies agreed to provide a four-year freeze in
wholesale rates. After the merger, the regulated businesses of
NSP and WEC would continue to operate as utility subsidiaries of
Primergy, which would be registered under the Public Utility
Holding Company Act of 1935 (PUHCA), as amended, and some of the
Company's subsidiaries would be transferred to direct Primergy
ownership. Except for certain gas distribution properties
transferred to the Company, the Wisconsin Company will become
part of the regulated business of WEC. Although NSP and WEC are
working to avoid divestitures, the PUHCA may require the merged
entity to divest certain of its gas utility and/or non-regulated
operations. Also, regulatory authorities may require the
restructuring of transmission system operations or
administration. NSP currently cannot determine if such
divestitures or restructuring would be required. In addition,
Wisconsin state law limits the total assets of non-utility
affiliates of Primergy. This could affect the growth of non-
regulated operations.
The agreement to merge is subject to a number of
conditions, including approval by applicable regulatory
authorities. During 1995, NSP and WEC received a ruling from the
Internal Revenue Service indicating that the proposed successive
merger transactions would not prevent treatment of the business
combination as a tax-free reorganization under applicable tax
law if each transaction independently qualified. During 1995,
NSP and WEC submitted filings to the Federal Energy Regulatory
Commission (FERC), applicable state regulatory commissions and
other governmental authorities seeking approval of the proposed
merger to form Primergy. The FERC has put the merger application
on an accelerated schedule, ordering the administrative law
judge's initial decision by Aug. 30, 1996, and briefs on
exception by Sept. 30, 1996, which makes possible a FERC ruling
on the merger application by the end of 1996. Although the goal
of NSP and WEC is to receive approvals from all regulatory
authorities by the end of 1996, some regulatory authorities have
not established a timetable for their decision. Therefore, the
timing of the approvals necessary to complete the merger is not
known at this time. The state filings included a request for
deferred accounting treatment and rate recovery of costs
incurred associated with the proposed merger. At Dec. 31, 1995,
$13.9 million of costs associated with the proposed merger had
been deferred as a component of Intangible and Other Assets. In
February 1996, the appropriate committees of the Minnesota
Legislature passed legislation that would affect merger approval
for electric utilities. The bill, if passed into law, would
provide for certain binding commitments regarding minimum levels
of staffing and investment for electric service.
In addition to the regulatory and other governmental approvals
of the proposed merger, certain NSP financial and other
agreements may be construed to require that, in the case of a
change in ownership (such as the proposed merger), the other
party to the agreement must consent to the change or waive the
requirement. Agreements with such provisions at Dec. 31, 1995,
include $101.7 million of long-term debt, operating lease
agreements with annual payments of $1.3 million in 1996 and a
$10 million credit line agreement, under which there were no
borrowings at Dec. 31, 1995. Although neither consents nor
waivers from the other parties have yet been obtained, NSP will
seek to obtain them prior to the completion of the merger. (See
further discussion of the proposed business combination in Note
18 to the Financial Statements.)
Regulation NSP's utility rates are approved by the FERC, the
Minnesota Public Utilities Commission (MPUC), the North Dakota
Public Service Commission, the Public Service Commission of
Wisconsin (PSCW), the Michigan Public Service Commission and the
South Dakota Public Utilities Commission. Rates are designed to
recover plant investment and operating costs and an allowed
return on investment, using an annual period upon which rate
case filings are based. NSP requests changes in rates for
utility services as needed through filings with the governing
commissions. The rates charged to retail customers in Wisconsin
are reviewed and adjusted biennially. Because comprehensive rate
changes are not requested annually in Minnesota, NSP's primary
jurisdiction, changes in operating costs can affect NSP's
earnings, shareholders' equity and other financial results.
Except for Wisconsin electric operations, NSP's rate schedules
provide for cost-of-energy and resource adjustments to billings
and revenues for changes in the cost of fuel for electric
generation, purchased energy, purchased gas, and conservation
and energy management program costs. For Wisconsin electric
operations, the biennial retail rate review process considers
changes in electric fuel and purchased energy costs in lieu of
a cost-of-energy adjustment clause. In addition to changes in
operating costs, other factors affecting rate filings are sales
growth, conservation and demand-side management efforts and the
cost of capital.
Competition The Energy Policy Act of 1992 (the Act) was a
catalyst for comprehensive and significant changes in the
operation of electric utilities, including increased
competition. The Act's reform of the PUHCA promotes creation of
wholesale non-utility power generators and authorizes the FERC
to require utilities to provide wholesale transmission services
to third parties. The legislation allows utilities and non-
regulated companies to build, own and operate power plants
nationally and internationally without being subject to
restrictions that previously applied to utilities under the
PUHCA. Management believes this legislation will promote the
continued trend of increased competition in the electric energy
markets. NSP management plans to continue its efforts to be a
competitively priced supplier of electricity and an active
participant in the competitive market for electricity. The
proposed merger with WEC is a key strategic initiative designed
to facilitate NSP's effective competition in the future energy
marketplace.
In March 1995, the FERC issued a 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). The Mega-
NOPR is intended to create a vigorous wholesale electric market
by requiring transmission providers to offer open access to
their transmission systems. The FERC is proposing to require
utilities to unbundle power sales from transmission. This "unbundled
service" requirement would apply only to new requirements
contracts and new coordination trade contracts. The Mega-NOPR
would apply to all utilities under the FERC's jurisdiction and
would require each utility to file individual tariffs. The FERC
also seeks to require non-jurisdictional transmission-providing
entities (such as municipals and cooperatives) to offer open
access by including a reciprocity clause in their individual
tariffs so that those who take service from a FERC
jurisdictional utility must also offer open access. Concurrently
with the Mega-NOPR, the FERC issued a proposal for a Real-Time
Information Network intended to facilitate open access by
requiring all public utilities to create an electronic bulletin
board of information regarding their transmission system
services, availability and rates. Also in the Mega-NOPR, the
FERC proposed to consider cases involving stranded costs
resulting from open access (a) when a state regulatory
commission does not have authority under state law to address
such 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, and (b) after a state commission has addressed such
costs. In response to the FERC's proposals, NSP filed comments
with the FERC that supported the Mega-NOPR's open access
initiative and asserted NSP's intent that open access
transmission tariffs filed in 1994 comply with the spirit of the
Mega-NOPR. NSP expects the impact of any rulemaking such as the
Mega-NOPR to be consistent with its efforts to be a
competitively priced supplier of electricity and an active
participant in the competitive market for electricity.
With the development of electric industry competition, the
Company has experienced an increase in requests for the use of
its transmission system. A large portion of these requests is
due to the increase in FERC-approved power marketers. In 1995,
the Company filed 23 transmission service agreements for FERC
approval, including 10 with power marketers. While the annual
transmission revenue in 1995 from this activity was immaterial,
it is expected that 1996 revenues will increase due to the
growth of power marketing activity in this region.
In response to the developing electric industry
competition, Cenergy applied for and was granted permission by
the FERC to market electricity (except electricity generated by
NSP) in the United States, effective Dec. 1, 1994. Cenergy was
one of the first affiliates of an electric utility to obtain
this approval from the FERC.
Some states are considering proposals to increase
competition in the supply of electricity. In response to a
proposal in 1994 by its regulator in Wisconsin, NSP outlined the
transitional steps necessary to create an open and fair
competitive electric market. NSP's position is that all
customers should be able to choose their electric supplier by
2001, and that generation also should be deregulated by 2001.
NSP proposes that utilities retain operational control of their
transmission and distribution systems, and that utilities should
be permitted to recover the cost of investments made under
traditional regulation. Regulators in Minnesota and Wisconsin
are currently considering what actions they should take
regarding electric industry competition. In Wisconsin,
regulators developed a plan for a phased approach. They voted to
adopt a 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
control transmission access. In Minnesota, regulators have
developed draft principles to provide a framework for electric
industry restructuring. They have not established definitive
timelines for industry restructuring or changes. One of the
principles supports an open transmission system and establishing
a robust wholesale competitive market. NSP believes the
transition to a more competitive electric industry is inevitable
and beneficial for all consumers. NSP supports an orderly and
efficient transition to an open, fair and competitive energy
market for all customers and suppliers. The timing of regulatory
actions and their impact on NSP cannot be predicted and may be
significant.
During 1992 and 1993, the FERC issued a series of orders
(together called Order 636) addressing interstate natural gas
pipeline service restructuring. This restructuring "unbundled"
each of the services (sales, transportation, storage and
ancillary services) traditionally provided by gas pipeline
companies. Interstate pipelines have been allowed to recover
from their customers 100 percent of prudently incurred
transition costs attributable to Order 636 restructuring. Under
service agreements that went into effect Nov. 1, 1993, NSP
estimates that it will be responsible for less than $11 million
of transition costs over a five-year period beginning on that
date. To date, NSP's regulatory commissions have approved
recovery of these restructuring charges in retail gas rates
through the purchased gas adjustment. NSP does not believe Order
636 has materially affected its cost of gas supply. NSP's
acquisitions of Viking and Cenergy in 1993 have enhanced its
ability to participate in the more competitive gas
transportation business. In implementing Order 636, Viking
incurred no transition costs.
Customer Cogeneration Koch Refining Co. (Koch), the Company's
largest customer which provides approximately $30 million in
annual revenues to NSP, proposes to build a cogeneration plant
to burn petroleum coke, a refinery byproduct, to produce between
180 and 250 megawatts of electricity. This would be enough
supply for Koch's own use plus an additional 80 to 150 megawatts
to be sold on the wholesale market. Koch is requesting a
legislative exemption from Minnesota property tax for its plant.
While NSP supports the reduction of taxes on generating
facilities, it believes any reduction should be applied to all
generating facilities so that there are no unfair tax advantages
available to some generators. This project has several
implications for NSP: 1) Koch could become a competitor as it
seeks markets for its excess capacity; 2) Koch's capacity would
also represent a potential power source for NSP; and 3) Koch's
plan represents a potential loss of a large retail customer. The
project's anticipated three-year lead time will allow NSP to
respond appropriately.
Wholesale Customers NSP had wholesale revenues from sales of
electricity of approximately $44 million in 1995 and
approximately $57 million in 1994. The trend of increased
competition, as previously discussed, has resulted in
significant changes in the negotiation of contracts with
wholesale customers. In the past several years, these customers
have begun to evaluate a variety of energy sources to provide
their power supply. While the full impact of these changes is
unknown at this time, the following changes have been
identified.
In 1992, nine of the Company's municipal wholesale electric
customers notified the Company of their intent to terminate
their power supply agreements with the Company, effective July
1995 or July 1996. The loss of seven of these customers in July
1995 resulted in a revenue decrease of approximately $12 million
from 1994 levels. The other two customers, who are expected to
terminate their power agreements in July 1996, provided revenues
of $3.6 million in 1995. These nine customers are expected to
become wheeling customers providing estimated annual revenues of
nearly $3 million. NSP's remaining 19 municipal wholesale
electric customers are under contracts with terms expiring in
the years 1999 through 2008.
During 1993, the Company signed an electric power agreement
to provide Michigan's Upper Peninsula Power Company (UPPCO) with
up to 150 megawatts of baseload service, peaking service options
and load regulation service options for 20 years from January
1998 through December 2017. Load regulation service is designed
to change the level of power delivery during each hour to match
UPPCO's load requirements. UPPCO has nominated 50 megawatts of
baseload and five megawatts of winter season peaking power
purchases from NSP beginning Jan. 1, 1998. The annual revenue
for 1998 is projected to be approximately $11 million to $14
million. The interchange agreement between UPPCO and NSP for
this sale was accepted by the FERC. The Michigan Public
Utilities Commission also must approve the transaction.
Rate Changes As discussed previously under Utility Operating
Results, filings for rate changes in 1995 had an immaterial
impact on financial results. No significant general rate filings
in any of NSP's utility jurisdictions are expected for 1996.
However, the Company has proposed rate changes in connection
with requested approvals of its proposed business combination
with WEC, as discussed previously.
Used Nuclear Fuel Storage and Disposal In 1994, NSP received
legislative authorization from the State of Minnesota for dry
cask fuel storage facilities at the Company's Prairie Island
nuclear generating facility. As a condition of this
authorization, the Minnesota Legislature established several
resource commitments for the Company, including wind and biomass
generation sources, as well as other requirements. In addition,
the Company and other utilities filed a lawsuit against the DOE
in 1994 to compel the DOE to fulfill its statutory and
contractual obligations to store and dispose of used nuclear
fuel as required by the Nuclear Waste Policy Act of 1982. Also,
the Company is leading a consortium to establish a private
facility for interim storage of used nuclear fuel, the outcome
of which is uncertain at this time. (See Notes 14 and 15 to the
Financial Statements for more information.)
Environmental Matters NSP incurs several types of environmental
costs, including nuclear plant decommissioning, storage and
ultimate disposal of used nuclear fuel, disposal of hazardous
materials and wastes, remediation of contaminated sites and
monitoring of discharges into the environment. Because of the
continuing trend toward greater environmental awareness and
increasingly stringent regulation, NSP has been experiencing a
trend toward increasing environmental costs. This trend has
caused, and may continue to cause, slightly higher operating
expenses and capital expenditures for environmental compliance.
In addition to nuclear decommissioning and used nuclear fuel
disposal expenses (as discussed in Note 14 to the Financial
Statements), costs charged to NSP's operating expenses for
environmental monitoring and disposal of hazardous materials and
wastes in 1995 were approximately $26 million and are expected
to increase to an average annual amount of approximately $30
million for the five-year period 1996-2000. However, the precise
timing and amount of environmental costs, including those for
site remediation and disposal of hazardous materials, are
currently unknown. In each of the years, 1995, 1994 and 1993,
the Company spent about $15 million for capital expenditures on
environmental improvements at its utility facilities. In 1996,
the Company expects to incur approximately $20 million in
capital expenditures for compliance with environmental
regulations and approximately $180 million for the five-year
period 1996-2000. These capital expenditure amounts include the
costs of constructing used nuclear fuel storage casks. (See
Notes 14 and 15 to the Financial Statements for further
discussion of these and other environmental contingencies that
could affect NSP.)
Weather NSP's earnings can be significantly affected by unusual
weather. In 1995, unusual weather, mainly a hot summer,
increased earnings over a normal year by an estimated 21 cents
per share. Mild weather, mainly cool summers, reduced earnings
from a normal year by an estimated 13 cents per share in 1994
and 18 cents per share in 1993. The effect of weather is
considered part of NSP's ongoing business operations.
Acquisitions In 1994, NRG acquired ownership interests in three
significant international energy projects (listed in Note 3 to
the Financial Statements). NSP also made three other
strategically important business acquisitions in 1993, including
an interstate natural gas pipeline (Viking), an energy services
marketing business (Cenergy) and a steam heating and chilled
water cooling system business (Minneapolis Energy Center, now an
NRG subsidiary). NSP continues to evaluate opportunities to
enhance its competitive position and shareholder returns through
strategic business acquisitions.
Impact of Non-regulated Investments NSP's net income includes
after-tax earnings of $33.6 million, or 50 cents per share, from
all of its non-regulated businesses in 1995 and $32.9 million,
or 49 cents per share, in 1994. As discussed previously, NRG
acquired equity interests in three significant energy projects
in 1994. NSP expects to continue investing significant amounts
in non-regulated projects, including domestic and international
power production projects through NRG, as described under Future
Financing Requirements. Depending on the success and timing of
involvement in these projects, NSP's goal is for NRG earnings to
increase in the future to contribute at least 20 percent of
NSP's earnings by the year 2000. The non-regulated projects in
which NRG has invested carry a higher level of risk than NSP's
traditional utility businesses. Current and future investments
in non-regulated projects are subject to uncertainties prior to
final legal closing, and continuing operations are subject to
foreign government actions, foreign economic and currency risks,
partnership actions, competition, operating risks, dependence on
certain suppliers and customers, domestic and foreign
environmental and energy regulations, or all of these items.
Most of NRG's current project investments consist of minority
interests, and a substantial portion of future investments may
take the form of minority interests, which limits NRG's ability
to control the development or operation of the projects. In
addition, significant expenses may be incurred for potential
projects pursued by NRG that may never materialize. The
operating results of NSP's non-regulated businesses in 1995 and
1994 may not necessarily be indicative of future operating
results.
Accounting Changes The Financial Accounting Standards Board
(FASB) has issued two new accounting standards that become
effective in 1996. Statement of Financial Accounting Standards
(SFAS) No. 121, Accounting for the Impairment of Long-Lived
Assets, establishes standards for measuring and recognizing
asset impairments. SFAS No. 123, Accounting for Stock-Based
Compensation, provides an optional accounting method for
compensation from stock option and other stock award programs
that NSP does not intend to use. NSP does not expect the
adoption of these new accounting standards to have a material
impact on its results of operations or financial condition.
However, the principles of SFAS No. 121 will be followed to
measure the effects of any stranded investments that could arise
from the Act, the FERC's Mega-NOPR proposal or other competitive
business developments.
The FASB also has proposed new accounting standards
expected to go into effect in 1997. The standards would require
the full accrual of nuclear plant decommissioning and certain
other site exit obligations. Material adjustments to NSP's
balance sheet could occur under the FASB's proposal. However,
the effects of regulation are expected to minimize or eliminate
any impact on operating expenses and earnings from this future
accounting change. (For further discussion of the expected
impact of this change, see Note 14 to the Financial Statements.)
Use of Derivatives Through its non-regulated subsidiaries, NSP
uses derivative financial instruments to hedge the risks of
fluctuations in foreign currencies and natural gas prices. Also,
to hedge the interest rate risk associated with fixed rate debt
in a declining interest rate environment, NSP uses interest rate
swap agreements to convert fixed rate debt to variable rate
debt. (See Notes 1 and 11 to the Financial Statements for
further discussion of NSP's financial instruments and
derivatives.)
Non-recurring Items NSP's earnings for 1995 include two
significant unusual or infrequently occurring items. As
discussed in the Non-regulated Business Results section, NRG
recognized a pretax gain of approximately $30 million (26 cents
per share) from a power sales contract termination settlement.
Partially offsetting this gain was an asset impairment write-
down of $5 million before taxes (4 cents per share) for a non-
regulated domestic energy project.
NSP's 1994 earnings also included several significant
unusual or infrequently occurring items. Although their net
effect was an earnings increase of only 1 cent per share,
individually significant non-recurring items included a gain on
termination of a non-regulated cogeneration contract, interest
income from the settlement of a federal income tax dispute, a
charge for pre-1994 postemployment costs associated with
adopting SFAS No. 112, and asset impairment write-downs for
certain non-regulated energy projects.
Inflation Historically, certain operating costs, mainly labor
and property taxes, have been affected by inflation. Also,
inflation has tended to increase the replacement cost of
operating facilities, which has increased depreciation expense
when replacement facilities are constructed. However, several
significant expense items, including fuel costs, income taxes
and interest expense have been less sensitive to inflation.
Overall, inflation at the levels currently being experienced is
not expected to materially affect NSP's prices to customers or
returns to shareholders.
LIQUIDITY AND CAPITAL RESOURCES
1995 Financing Requirements NSP's need for capital funds is
primarily related to the construction of plant and equipment to
meet the needs of electric and gas utility customers and to fund
equity commitments or other investments in non-regulated
businesses. Total NSP utility capital expenditures (including
AFC) were $386 million in 1995. Of that amount, $318 million
related to replacements and improvements of NSP's electric
system and nuclear fuel, and $37 million involved construction
of natural gas distribution facilities. NSP companies invested
$71 million in non-regulated projects and property in 1995. NRG
primarily invested in existing projects. In 1995, Cenergy became
a majority investor (80 percent) in Energy Masters Corporation,
a firm specializing in energy efficiency improvement services
for commercial, industrial and institutional customers. The
investment is accounted for on a consolidated basis. Eloigne
Company invested in affordable housing projects, including
wholly owned and limited partnership ventures.
1995 Financing Activity During 1995, NSP's primary sources of
capital included internally generated funds, long-term debt,
short-term debt and common stock issuances, as discussed below.
The allocation of financing requirements between these capital
options is based on the relative cost of each option, regulatory
restrictions and the constraints of NSP's long-range capital
structure objectives. During 1995, NSP continued to meet its
long-range regulated capital structure objective of 45-50
percent common equity and 42-50 percent debt.
Funds generated internally from operating cash flows in
1995 remained sufficient to meet working capital needs, debt
service, dividend payout requirements and non-regulated
investment commitments, as well as fund a significant portion of
construction expenditures. The pretax interest coverage ratio,
excluding AFC, was 3.8 in 1995 and 3.9 in 1994. These ratios met
NSP's objective range of 3.5-5.0 for interest coverage.
Internally generated funds could have provided financing for 85
percent of NSP's total capital expenditures for 1995 and 72
percent of the $1.9 billion in capital expenditures incurred for
the five-year period 1991-1995.
NSP had approximately $216 million in short-term borrowings
outstanding as of Dec. 31, 1995. Throughout 1995, short-term
borrowings were used to finance a portion of utility capital
expenditures and provide for other NSP cash needs.
In 1995, the Company issued $250 million of first mortgage
bonds to refinance higher-cost debt issues and reduce short-term
debt levels. Eloigne Company also issued approximately $12.5
million of long-term debt to finance affordable housing project
investments.
During 1995, the Company issued new shares of common stock
under various stock plans, including 536,360 new shares under
the Employee Stock Ownership Plan (ESOP), 527,671 new shares
under the Dividend Reinvestment and Stock Purchase Plan (DRSPP),
and 63,780 new shares under the Executive Long-Term Incentive
Award Stock Plan. In addition, the Company issued common stock
in connection with a non-regulated business acquisition. At Dec.
31, 1995, the total number of common shares outstanding was
68,175,934.
NSP's equity investments in non-regulated projects during
1995 were financed through internally generated funds. Project
financing requirements, in excess of equity contributions from
investors, were satisfied with project debt. Project debt
associated with many of NSP's non-regulated investments is not
reflected in NSP's balance sheet because the equity method of
accounting is used for such investments. (See Note 3 to the
Financial Statements.)
In January 1996, NRG issued $125 million of 7.625 percent
unsecured Senior Notes maturing in 2006 to support equity
requirements for projects currently under way and in
development. The Senior Notes were assigned ratings of BBB- by
S&P's Rating Group and Baa3 by Moody's.
Future Financing Requirements Utility financing requirements for
1996-2000 may be affected in varying degrees by numerous
factors, including load growth, changes in capital expenditure
levels, rate changes allowed by regulatory agencies, new
legislation, market entry of competing electric power
generators, changes in environmental regulations and other
regulatory requirements. NSP currently estimates that its
utility capital expenditures will be $410 million in 1996 and
$1.9 billion for the five-year period 1996-2000. Of the 1996
amount, approximately $345 million is scheduled for utility
electric facilities and approximately $45 million for natural
gas facilities including Viking. In addition to utility capital
expenditures, expected financing requirements for the 1996-2000
period include approximately $480 million to retire long-term
debt and meet first mortgage bond sinking fund requirements.
Through its subsidiaries, NSP expects to invest significant
amounts in non-regulated projects in the future. Financing
requirements for non-regulated project investments may vary
depending on the success, timing and level of involvement in
projects currently under consideration. NSP's potential capital
requirements for non-regulated projects and property are
estimated to be approximately $140 million in 1996 and
approximately $550 million for the five-year period 1996-2000.
These amounts include commitments for NRG investments, as
discussed in Note 15 to the Financial Statements, and Eloigne
Company investments of up to $13 million annually in 1996-2000
for affordable housing projects. Eloigne Company expects to
finance approximately 65 percent of these investments in
affordable housing projects with equity and approximately 35
percent with long-term debt. In addition to investments in non-
regulated projects, NSP continues to evaluate opportunities to
enhance shareholder returns and achieve long-term financial
objectives through acquisitions of existing businesses. Long-
term financing may be required for such investments.
The Company also will have future financing requirements
for the portion of nuclear plant decommissioning costs not
funded externally. Based on the most recent decommissioning
study, these amounts are anticipated to be approximately $363
million, and are expected to be paid during the years 2010 to
2022.
Future Sources of Financing NSP expects to obtain external
capital for future financing requirements by periodically
issuing long-term debt, short-term debt, common stock and
preferred stock as needed to maintain desired capitalization
ratios. Over the long-term, NSP's equity investments in non-
regulated projects are expected to be financed through
internally generated funds or the Company's issuance of common
stock. Financing requirements for the non-regulated projects, in
excess of equity contributions from investors, are expected to
be fulfilled through project or subsidiary debt. Decommissioning
expenses not funded by an external trust are expected to be
financed through a combination of internally generated funds,
long-term debt and common stock. The extent of external
financing to be required for nuclear decommissioning costs, as
discussed above, is unknown at this time.
NSP's ability to finance its utility construction program
at a reasonable cost and to provide for other capital needs
depends on its ability to meet investors' return expectations.
Financing flexibility is enhanced by providing working capital
needs and a high percentage of total capital requirements from
internal sources, and having the ability to issue long-term
securities and obtain short-term credit. NSP expects to maintain
adequate access to securities markets in 1996. Access to
securities markets at a reasonable cost is determined in large
part by credit quality. The Company's first mortgage bonds are
rated AA- by Standard & Poor's Corporation, A1 by Moody's
Investors Service, Inc. (Moody's), AA- by Duff & Phelps, Inc.,
and AA by Fitch Investors Service, Inc. Ratings for the
Wisconsin Company's first mortgage bonds are generally
comparable. These ratings reflect the views of such
organizations, and an explanation of the significance of these
ratings may be obtained from each agency. In May 1994, Moody's
downgraded the Company's first mortgage bond ratings to A1 based
on its interpretation of provisions of a Minnesota law enacted
in 1994 for used nuclear fuel storage at the Prairie Island
generating plant. (The other three rating agencies reaffirmed
their ratings of the Company's bonds after considering the
potential impact of the legislation on NSP.) As discussed in
Notes 14 and 15 to the Financial Statements, the legislation
requires the Company to increase its use of renewable energy
sources such as wind and biomass power. Moody's has indicated
that it believes these sources of power are considerably more
costly than the power currently generated and that NSP's
electric production costs will increase materially over current
levels. NSP acknowledges that electric production costs may
increase as a result of the Prairie Island legislation. In 1995,
Moody's placed the Company's ratings on credit review for
possible upgrade based on anticipated cost savings from the
proposed merger with WEC, which was discussed previously.
The Company's and the Wisconsin Company's first mortgage
indentures limit the amount of first mortgage bonds that may be
issued. The MPUC and the PSCW have jurisdiction over securities
issuance. At Dec. 31, 1995, with an assumed interest rate of 7.0
percent, the Company could have issued about $2.5 billion of
additional first
mortgage bonds under its indenture, and the Wisconsin Company
could have issued about $356 million of additional first
mortgage bonds under its indenture.
The Company filed a shelf registration for first mortgage
bonds with the Securities and Exchange Commission (SEC) in
October 1995. Depending on capital market conditions, the
Company expects to issue the $300 million of registered, but
unissued, bonds over the next several years to raise additional
capital or redeem outstanding securities. In addition, depending
on market conditions, the Wisconsin Company may issue up to $65
million in first mortgage bonds to redeem outstanding securities
or raise additional capital.
The Company's Board of Directors has approved short-term
borrowing levels up to 10 percent of capitalization. The Company
has received regulatory approval for up to $445 million in
short-term borrowing levels and plans to keep its credit lines
at or above its average level of commercial paper borrowings.
Commercial banks presently provide credit lines of approximately
$265 million to the Company and an additional $17 million to
subsidiaries of the Company. These credit lines make short-term
financing available in the form of bank loans.
The Company's Articles of Incorporation authorize the
maximum amount of preferred stock that may be issued. Under
these provisions, the Company could have issued all $460 million
of its remaining authorized, but unissued, preferred stock at
Dec. 31, 1995, and remained in compliance with all interest and
dividend coverage requirements.
The level of common stock authorized under the Company's
Articles of Incorporation is 160 million shares. In January
1996, the Company filed a registration statement with the SEC to
provide for the sale of up to 1.6 million additional shares of
new common stock under the Company's Dividend Reinvestment and
Stock Purchase Plan (DRSPP) and Executive Long-Term Incentive
Award Stock Plan. The Company may issue new shares or purchase
shares on the open market for its stock-based plans. (See Note
5 to the Financial Statements for discussion of stock awards
outstanding.) The Company plans to issue new shares for its
DRSPP, ESOP and Executive Long-Term Incentive Award Stock plans
in 1996. While no general public stock offerings are currently
anticipated in 1996, such offerings may be necessary to fund
significant equity investments in non-regulated projects should
they occur.
Internally generated funds from utility operations are
expected to equal approximately 90 percent of anticipated
utility capital expenditures for 1996 and approximately 100
percent of the $1.9 billion in anticipated utility capital
expenditures for the five-year period 1996-2000. Internally
generated funds from all operations are expected to equal
approximately 75 percent and 90 percent, respectively, of the
anticipated total capital expenditures for 1996 and the five-
year period 1996-2000. Because NSP intends to reinvest foreign
cash flows in non-U.S. operations, the equity income from
international investments currently does not provide operating
cash available for U.S. cash requirements such as payment of
dividends, domestic capital expenditures and domestic debt
service. Through NRG, NSP intends to pursue a diverse portfolio
of foreign energy projects with varying levels of cash flows,
income and foreign taxation to allow maximum flexibility of
foreign cash flows.
The merger agreement, as previously discussed, provides for
restrictions on certain transactions by both the Company and
WEC, including the issuance of debt and equity securities. While
the Company currently does not plan to enter into transactions
that would not comply with these restrictions, circumstances may
arise to make such transactions necessary. Under such
circumstances, the Company and WEC would need to mutually agree
to amend the merger agreement.
Item 8 - Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for index of financial
statements included herein.
See Note 17 of Notes to Financial Statements for summarized
quarterly financial data.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Northern States Power Company:
In our opinion, the accompanying consolidated balance sheet
and statement of capitalization and the related consolidated
statements of income, of common stockholders' equity and of cash
flows present fairly, in all material respects, the financial
position of Northern States Power Company, a Minnesota
corporation, and its subsidiaries at Dec. 31, 1995, and the
results of their operations and their cash flows for the year in
conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these
financial statements based on our 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 a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable
basis for the opinion expressed above. The consolidated
financial statements of the Company and its subsidiaries for the
years ended Dec. 31, 1994 and 1993 were audited by other
independent accountants whose report dated Feb. 8, 1995
expressed an unqualified opinion on those statements and
included an explanatory paragraph related to a change in method
of accounting for postretirement health care costs in 1993.
(Price Waterhouse LLP)
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
February 5, 1996
INDEPENDENT AUDITORS' REPORT
To the Shareholders of Northern States Power Company:
We have audited the accompanying consolidated balance sheet and
statement of capitalization of Northern States Power Company
(Minnesota) and its subsidiaries (the Companies) as of December 31,
1994, and the related consolidated statements of income, changes
in common stockholders' equity, and cash flows for each of the
two years in the period ended December 31, 1994, listed in the
accompanying table of contents in Item 14(a)1. These consolidated
financial statements and financial statement schedules are the
responsibility of the Companies' management. Our responsibility
is to express an opinion on the consolidated financial
statements and financial statement schedules 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 consolidated financial statements present
fairly, in all material respects, the financial position of the
Companies 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.
As discussed in Note 2 to the financial statements, the
Companies changed their method of accounting for postretirement
health care costs in 1993.
(Deloitte & Touche LLP)
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 8, 1995
Consolidated Statements of Income Year Ended Dec. 31
(Thousands of dollars, except per share data) 1995 1994 1993
Utility Operating Revenues
Electric $2 142 770 $2 066 644 $1 974 916
Gas 425 814 419 903 429 076
Total 2 568 584 2 486 547 2 403 992
Utility Operating Expenses
Electric production expenses---fuel and
purchased power 570 245 570 880 524 126
Cost of gas purchased and transported 256 758 263 905 282 036
Other operation 321 121 316 479 310 585
Maintenance 158 203 170 145 161 413
Administrative and general 186 147 187 996 176 617
Conservation and energy management 53 466 31 231 29 358
Depreciation and amortization 290 184 273 801 264 517
Property and general taxes 239 433 234 564 223 108
Income taxes 147 148 129 228 128 346
Total 2 222 705 2 178 229 2 100 106
Utility Operating Income 345 879 308 318 303 886
Other Income (Expense)
Equity in earnings of unconsolidated affiliates:
Earnings from operations 29 217 32 024 3 030
Gain from contract termination 29 850 9 685
Allowance for funds used during
construction---equity 6 794 4 548 7 328
Other income (deductions) --- net (7 975) (3 686) 7 982
Income taxes on non-regulated operations
and non-operating items (5 080) (199) (2 394)
Total 52 806 42 372 15 946
Income Before Interest Charges 398 685 350 690 319 832
Interest Charges
Interest on utility long-term debt 103 298 89 553 101 677
Other utility interest and amortization 20 151 17 555 8 739
Non-regulated interest and amortization 9 879 7 975 3 146
Allowance for funds used during
construction---debt (10 438) (7 868) (5 470)
Total 122 890 107 215 108 092
Net Income 275 795 243 475 211 740
Preferred Stock Dividends 12 449 12 364 14 580
Earnings Available for Common Stock $263 346 $231 111 $197 160
Average Number of Common and Equivalent
Shares Outstanding (000's) 67 416 66 845 65 211
Earnings Per Average Common Share $3.91 $3.46 $3.02
Common Dividends Declared per Share $2.685 $2.625 $2.565
See Notes to Financial Statements
Consolidated Statements of Cash Flows Year Ended Dec. 31
(Thousands of dollars) 1995 1994 1993
Cash Flows from Operating Activities:
Net Income $275 795 $243 475 $211 740
Adjustments to reconcile net income to cash
from operating activities:
Depreciation and amortization 322 296 304 583 286 855
Nuclear fuel amortization 49 778 45 553 43 120
Deferred income taxes (11 076) (6 101) 12 256
Deferred investment tax credits recognized (9 117) (9 501) (9 223)
Allowance for funds used during
construction---equity (6 794) (4 548) (7 328)
Undistributed equity in earnings of unconsolidated
affiliate operations (24 305) (23 588) (1 142)
Undistributed equity in gain from non-regulated contract
termination settlements (17 565)
Cash provided by (used for) changes in certain
working capital items (791) (8 627) 33 259
Conservation program expenditures - net
of amortization (21 668) (29 963) (21 185)
Cash provided by (used for) changes in other
assets and liabilities 17 234 (1 042) 12 340
Net Cash Provided by Operating Activities 573 787 510 241 560 692
Cash Flows from Investing Activities:
Capital expenditures:
Utility businesses (386 022) (387 026) (356 836)
Non-regulated businesses (14 984) (22 260) (4 859)
Increase (decrease) in construction payables (12 588) 11 668 2 598
Allowance for funds used during
construction---equity 6 794 4 548 7 328
Sale (purchase) of short-term investments---net 743 (866) 62
Investment in external decommissioning fund (33 196) (42 677) (32 578)
Business acquisitions (159 385)
Equity investments in non-regulated
projects and other (55 859) (132 511) (25 957)
Net Cash Used for Investing Activities (495 112) (569 124) (569 627)
Cash Flows from Financing Activities:
Change in short-term debt---net issuances
(repayments) (22 245) 132 239 (40 361)
Proceeds from issuance of long-term debt 277 174 367 184 613 120
Loan to ESOP (15 000)
Repayment of long-term debt, including
reacquisition premiums (195 683) (272 097) (489 106)
Proceeds from issuance of common stock 56 185 1 368 183 654
Redemption of preferred stock, including premium (36 092)
Dividends paid (191 367) (186 568) (180 220)
Net Cash Provided by (Used for) Financing
Activities (90 936) 42 126 50 995
Net Increase (Decrease) in Cash and
Cash Equivalents (12 261) (16 757) 42 060
Cash and Cash Equivalents at Beginning of Period 41 055 57 812 15 752
Cash and Cash Equivalents at End of Period $28 794 $41 055 $57 812
Cash Provided by (Used for) Changes in Certain Working Capital Items:
Customer accounts receivable and
unbilled utility revenues $(66 311) $14 708 $(43 219)
Materials and supplies inventories 14 290 (13 462) 13 911
Payables and accrued liabilities
(excluding construction payables) 53 141 32 550 54 247
Customer rate refunds (1 825) (10 410) 12 235
Other (86) (32 013) (3 915)
Net $(791) $(8 627) $33 259
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized) $113 705 $106 867 $107 037
Income taxes (net of refunds received) $131 452 $170 474 $120 491
See Notes to Financial Statements
Consolidated Balance Sheets
Dec. 31
(Thousands of dollars) 1995 1994
Assets
Utility Plant
Electric---including construction work in progress:
1995, $137,662; 1994, $117,235 $6 553 383 $6 372 317
Gas 710 035 677 233
Other 299 585 262 506
Total 7 563 003 7 312 056
Accumulated provision for depreciation (3 343 760) (3 116 811)
Nuclear fuel---including amounts in process:
1995, $34,235; 1994, $12,505 843 919 797 097
Accumulated provision for amortization (752 821) (718 690)
Net utility plant 4 310 341 4 273 652
Current Assets
Cash and cash equivalents 28 794 41 055
Short-term investments 149 892
Customer accounts receivable---net of
accumulated provision for uncollectible
accounts: 1995, $4,338; 1994, $3,912 281 584 229 272
Unbilled utility revenues 112 650 98 651
Other receivables 78 993 80 444
Materials and supplies---at average cost
Fuel 43 941 56 960
Other 100 607 101 878
Prepayments and other 57 745 56 075
Total current assets 704 463 665 227
Other Assets
Regulatory assets 374 212 357 576
Non-regulated property---net of accumulated
depreciation: 1995, $83,724; 1994, $73,296 177 598 172 961
Equity investments in non-regulated
projects and other investments 289 495 197 490
External decommissioning fund investments 203 625 145 467
Long-term receivables 83 065 68 735
Intangible and other assets 85 786 68 624
Total other assets 1 213 781 1 010 853
Total $6 228 585 $5 949 732
Liabilities & Equity
Capitalization
Common stockholders' equity $2 027 391 $1 896 967
Preferred stockholders' equity 240 469 240 469
Long-term debt 1 542 286 1 463 354
Total capitalization 3 810 146 3 600 790
Current Liabilities
Long-term debt due within one year 25 760 16 106
Other long-term debt potentially due
within one year 141 600 141 600
Short-term debt---primarily commercial paper 216 194 238 439
Accounts payable 246 051 234 905
Taxes accrued 202 777 178 119
Interest accrued 31 806 28 164
Dividends payable on common and preferred stocks 48 875 47 283
Accrued payroll, vacation and other 78 310 79 029
Total current liabilities 991 373 963 645
Other Liabilities
Deferred income taxes 841 153 845 031
Deferred investment tax credits 161 513 173 838
Regulatory liabilities 242 787 200 517
Pension and other benefit obligations 115 797 92 514
Other long-term obligations and deferred income 65 816 73 397
Total other liabilities 1 427 066 1 385 297
Commitments and Contingent Liabilities (See Notes 14 and 15)
Total $6 228 585 $5 949 732
See Notes to Financial Statements
Consolidated Statements of Common Stockholders' Equity
Cumulative
Currency
Number of Retained Shares Held Translation
(Dollar amounts in thousands) Shares Issued Par Value Premium Earnings by ESOP Adjustments
Balance at Dec. 31, 1992 62 598 360 $156 496 $370 819 $1 099 896 $(5 113)
Net income 211 740
Dividends declared:
Cumulative preferred stock
at required rates (14 580)
Common stock (168 615)
Issuances of common stock 4 281 217 10 703 176 296
Preferred stock redemption and
stock issuance costs (3 345) (1 069)
Loan to ESOP to purchase shares (15 000)
Repayment of ESOP loan 9 226
Balance at Dec. 31, 1993 66 879 577 $167 199 $543 770 $1 127 372 $(10 887)
Net income 243 475
Dividends declared:
Cumulative preferred stock
at required rates (12 364)
Common stock (175 292)
Issuances of common stock 42 567 106 1 342
Stock issuance costs (80)
Tax benefit from stock options exercised 843
Repayment of ESOP loan 7 897
Currency translation adjustments $3 586
Balance at Dec. 31, 1994 66 922 144 $167 305 $545 875 $1 183 191 $(2 990) $3 586
Net income 275 795
Dividends declared:
Cumulative preferred stock
at required rates (12 450)
Common stock (180 510)
Issuances of common stock 1 253 790 3 135 53 051
Stock issuance costs (1)
Tax benefit from stock options exercised 169
Loan to ESOP to purchase shares (15 000)
Repayment of ESOP loan 7 333
Currency translation adjustments (1 098)
Balance at Dec. 31, 1995 68 175 934 $170 440 $599 094 $1 266 026 $(10 657) $2 488
See Notes to Financial Statements
Consolidated Statements of Capitalization
Dec. 31
(Thousands of dollars) 1995 1994
Common Stockholders' Equity
Common stock---authorized 160,000,000 shares
of $2.50 par value; issued shares:
1995, 68,175,934; 1994, 66,922,144 $170 440 $167 305
Premium on common stock 599 094 545 875
Retained earnings 1 266 026 1 183 191
Leveraged common stock held by Employee
Stock Ownership Plan (ESOP)---shares at
cost: 1995, 229,154; 1994, 59,445 (10 657) (2 990)
Currency translation adjustments
---net 2 488 3 586
Total common stockholders'
equity $2 027 391 $1 896 967
Cumulative Preferred Stock---authorized 7,000,000
shares of $100 par value; outstanding shares:
1995 and 1994, 2,400,000
Minnesota Company
$3.60 series, 275,000 shares $27 500 $ 27 500
4.08 series, 150,000 shares 15 000 15 000
4.10 series, 175,000 shares 17 500 17 500
4.11 series, 200,000 shares 20 000 20 000
4.16 series, 100,000 shares 10 000 10 000
4.56 series, 150,000 shares 15 000 15 000
6.80 series, 200,000 shares 20 000 20 000
7.00 series, 200,000 shares 20 000 20 000
Variable Rate series A, 300,000 shares 30 000 30 000
Variable Rate series B, 650,000 shares 65 000 65 000
Total 240 000 240 000
Premium on preferred stock 469 469
Total preferred stockholders' equity $240 469 $240 469
Long-Term Debt
First Mortgage Bonds Minnesota Company
Series due:
March 1, 1996, 6.2% $8 800* $8 800*
Oct. 1, 1997, 5 7/8% 100 000 100 000
Feb. 1, 1999, 5 1/2% 200 000 200 000
Dec. 1, 2000, 5 3/4% 100 000 100 000
Oct. 1, 2001, 7 7/8% 150 000 150 000
March 1, 2002, 7 3/8% 50 000 50 000
Feb. 1, 2003, 7 1/2% 50 000 50 000
April 1, 2003, 6 3/8% 80 000 80 000
Dec. 1, 2005, 6 1/8% 70 000 70 000
Dec. 1, 1994-2006, 6.60% 21 100** 22 300**
March 1, 2011, Variable Rate 13 700* 13 700*
July 1, 2019, 9 1/8% 98 000
June 1, 2020, 9 3/8% 70 000
July 1, 2025, 7 1/8% 250 000
Total $1 093 600 $1 012 800
Less redeemable bonds classified as current
(See Note 7) (13 700) (13 700)
Less current maturities (10 100) (1 200)
Net $1 069 800 $ 997 900
* Pollution control financing
** Resource recovery financing
See Notes to Financial Statements
Dec. 31
(Thousands of dollars) 1995 1994
Long-Term Debt---continued
First Mortgage Bonds Wisconsin Company
(less reacquired bonds: 1995, $3,365; 1994, $490)
Series due:
Oct. 1, 2003, 5 3/4% $40 000 $40 000
April 1, 2021, 9 1/8% 44 635 48 010
March 1, 2023, 7 1/4% 110 000 110 000
Total 194 635 198 010
Less current maturities (2 910)
Net $194 635 $195 100
Guaranty Agreements---Minnesota Company
Series due:
Feb. 1, 1994-2003, 5.41% $ 5 700* $ 5 900*
May 1, 1994-2003, 5.69% 24 250* 24 750*
Feb. 1, 2003, 7.40% 3 500* 3 500*
Total 33 450 34 150
Less current maturities (700) (700)
Net $32 750 $33 450
Miscellaneous Long-Term Debt
City of Becker Pollution Control Revenue Bonds---Series due
Dec. 1, 2005, 7.25% $ 9 000* $ 9 000*
April 1, 2007, 6.80% 60 000* 60 000*
March 1, 2019, Variable Rate 27 900* 27 900*
Sept. 1, 2019, Variable Rate 100 000* 100 000*
Anoka County Resource Recovery Bond---Series due
Dec. 1, 1994-2008, 7.06% 24 150** 25 150**
City of La Crosse, Resource Recovery Bond---Series due
Nov. 1, 2011, 7 3/4% 18 600** 18 600**
Viking Gas Transmission Company Senior Notes---Series due
Oct. 31, 2008, 6.4% 27 378 29 511
NRG Energy Center, Inc. (Minneapolis Energy Center)
Senior Secured Notes---Series due June 15, 2013,
7.31% 79 326 81 498
United Power & Land Notes due
March 31, 2000, 7.62% 8 542 9 375
Various Affordable Housing Project Notes due
1994-2024, 1.0%---9.9% 20 696 7 710
Employee Stock Ownership Plan Bank Loans due
1994-2002, Variable Rate 9 874 2 698
Other 8 967 10 736
Total 394 433 382 178
Less variable rate Becker bonds classified as
current (See Note 7) (127 900) (127 900)
Less current maturities (14 960) (11 296)
Net $251 573 $242 982
Unamortized discount on long-term debt-net (6 472) (6 078)
Total long-term debt 1 542 286 1 463 354
Total capitalization $3 810 146 $3 600 790
* Pollution control financing
** Resource recovery financing
See Notes to Financial Statements
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
System of Accounts Northern States Power Company, a Minnesota
corporation (the Company), is predominantly a regulated public
utility serving customers in Minnesota, North Dakota and South
Dakota. Northern States Power Company, a Wisconsin corporation
(the Wisconsin Company), a wholly owned subsidiary of the
Company, is a regulated public utility serving customers in
Wisconsin and Michigan. Another wholly owned subsidiary, Viking
Gas Transmission Company (Viking), is a regulated natural gas
transmission company that operates a 500-mile interstate natural
gas pipeline. Consequently, the Company, the Wisconsin Company
and Viking maintain accounting records in accordance with either
the uniform system of accounts prescribed by the Federal Energy
Regulatory Commission (FERC) or those prescribed by state
regulatory commissions, whose systems are the same in all
material respects.
Principles of Consolidation The consolidated financial
statements include all material companies in which NSP holds a
controlling financial interest, including: the Wisconsin
Company; NRG Energy, Inc. (NRG); Viking; Cenergy, Inc.
(Cenergy), which changed its name to Cenerprise, Inc. effective
Jan. 1, 1996; and Eloigne Company. As discussed in Note 3, NSP
has investments in partnerships, joint ventures and projects for
which the equity method of accounting is applied. Earnings from
equity in international investments are recorded net of foreign
income taxes. 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
Wisconsin Company and Viking, which are allowed in utility
rates. The Company and its subsidiaries collectively are
referred to herein as NSP.
Revenues Revenues are recognized based on products and services
provided to customers each month. Because utility customer
meters are read and billed on a cycle basis, unbilled revenues
(and related energy costs) are estimated and recorded for
services provided from the monthly meter-reading dates to month-
end.
The Company's rate schedules, applicable to substantially
all of its utility customers, include cost-of-energy adjustment
clauses, under which rates are adjusted to reflect changes in
average costs of fuels, purchased energy and gas purchased for
resale. The Company's rate schedules in Minnesota also include
a rate adjustment clause, which is to be adjusted annually, to
reflect changes in recovery of electric and gas deferred
conservation program costs. As ordered by its primary regulator,
Wisconsin Company retail rate schedules include a cost-of-energy
adjustment clause for purchased gas but not for electric fuel
and purchased energy. The biennial retail rate review process
for Wisconsin electric operations considers changes in electric
fuel and purchased energy costs in lieu of a cost-of-energy
adjustment.
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 overhead
costs and allowance for funds used during construction. 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.
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 finance utility
construction activities, to qualified Construction Work in
Progress (CWIP). The AFC rate was 6.0 percent in 1995, 5.0
percent in 1994 and 7.4 percent in 1993. The amount of AFC
capitalized as a construction cost in CWIP is credited to other
income (for equity capital) and interest charges (for debt
capital). AFC amounts capitalized in CWIP are included in rate
base for establishing utility service rates. In addition to
construction-related amounts, AFC is also recorded to reflect
returns on capital used to finance conservation programs.
Depreciation For financial reporting purposes, depreciation is
computed by applying the straight-line method over the estimated
useful lives of various property classes. The Company files with
the Minnesota Public Utilities Commission (MPUC) an annual
review of remaining lives for electric and gas production
properties. The most recent studies, as approved by the MPUC,
recommended a decrease of approximately $0.2 million and an
increase of approximately $0.5 million for the 1995 and 1994
annual depreciation accruals, respectively.
Every five years, the Company also must file an average
service life filing for transmission, distribution and general
properties. The most recent filings approved by the MPUC were in
1994 for general plant and in 1993 for all other facilities.
Depreciation provisions, as a percentage of the average balance
of depreciable utility property in service, were 3.64 percent in
1995, 3.55 percent in 1994 and 3.47 percent in 1993.
Decommissioning As discussed in Note 14, NSP currently is
recording the future costs of decommissioning the Company's
nuclear generating plants through annual depreciation accruals.
The provision for the estimated decommissioning costs has been
calculated using an annuity approach designed to provide for
full expense accrual (with full rate recovery) of the future
decommissioning costs, including reclamation and removal, over
the estimated operating lives of the Company's nuclear plants.
The Financial Accounting Standards Board (FASB) has proposed new
accounting standards expected to go into effect in 1997. The
standards would require the full accrual of nuclear plant
decommissioning and certain other site exit obligations
beginning in 1997. (See Note 14 for more discussion of this
proposed standard.)
Nuclear Fuel Expense The original cost of nuclear fuel is
amortized to fuel expense based on energy expended. Nuclear fuel
expense also includes assessments from the U.S. Department of
Energy (DOE) for costs of future fuel disposal and DOE facility
decommissioning, as discussed in Note 14.
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 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 NSP has been
designated as one of several potentially responsible parties,
the amount accrued represents NSP's estimated share of the cost.
NSP intends to treat any future costs incurred related to
decommissioning and restoration of its non-nuclear 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).
Income Taxes NSP records income taxes in accordance with
Statement of Financial Accounting Standards (SFAS) No. 109---
Accounting for Income Taxes. Under the liability method required
by SFAS No. 109, income taxes are deferred for all temporary
differences between pretax financial and taxable income and
between the book and tax bases of assets and liabilities.
Deferred taxes are recorded using the tax rates scheduled by 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 10. NSP's policy
for income taxes related to international operations is
discussed in Note 9.
Investment tax credits are deferred and amortized over the
estimated lives of the related property.
Foreign Currency Translation The local currencies are generally
the functional currency of NSP's foreign operations. Foreign
currency denominated assets and liabilities are translated at
end-of-period rates of exchange. The resulting currency
translation adjustments are accumulated and reported as a
separate component of stockholders' equity. Income, expense and
cash flows are translated at weighted-average rates of exchange
for the period.
Exchange gains and losses that result from foreign currency
transactions (e.g. converting cash distributions made in one
currency to another) are included in the results of operations
as a component of equity in earnings of unconsolidated
affiliates. Through Dec. 31, 1995, NSP had not experienced any
material translation gains or losses from foreign currency
transactions that have occurred since the respective foreign
investment dates.
Derivative Financial Instruments NSP's policy is to hedge
foreign currency denominated investments as they are made to
preserve their U.S. dollar value, where appropriate hedging
instruments are available. NRG has entered into currency hedging
transactions through the use of forward foreign currency
exchange agreements. Gains and losses on these agreements offset
the effect of foreign currency exchange rate fluctuations on the
valuation of the investments underlying the hedges. Hedging
gains and losses, net of income tax effects, are reported with
other currency translation adjustments as a separate component
of stockholders' equity. NRG is not hedging currency translation
adjustments related to future operating results. NSP does not
speculate in foreign currencies. A second derivative arrangement
is the use of natural gas futures contracts by Cenergy to manage
the risk of gas price fluctuations. The cost or benefit of
natural gas futures contracts is recorded when related sales
commitments are fulfilled as a component of Cenergy's non-
regulated operating expenses. NSP does not speculate in natural
gas futures. A third derivative instrument used by NSP is
interest rate swaps that convert fixed rate debt to variable
rate debt. The cost or benefit of the interest rate swap
agreements is recorded as a component of interest expense. None
of these three derivative financial instruments is reflected on
NSP's balance sheet.
Use of Estimates In recording transactions and balances
resulting from business operations, NSP 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. Also, the depreciable lives of certain
plant assets are reviewed and, if appropriate, revised each
year, as discussed previously. (See Notes 8, 14 and 15 for more
information on the effects of these changes in estimates.)
Cash Equivalents NSP considers investments in certain debt
instruments (primarily commercial paper) with an original
maturity to NSP of three months or less at the time of purchase
to be cash equivalents.
Regulatory Deferrals As regulated utilities, the Company, the
Wisconsin Company and Viking account for certain income and
expense items under the provisions of SFAS No. 71---Accounting
for the Effects of Regulation. In doing so, certain costs that
would otherwise be charged to expense are deferred as regulatory
assets based on expected recovery from customers in future
rates. Likewise, certain credits that otherwise would 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 are generally based on specific ratemaking
decisions or precedent for each item. Regulatory assets and
liabilities are amortized consistent with ratemaking treatment
established by regulators. Note 10 describes the nature and
amounts of these regulatory deferrals.
Other Assets The purchase of various non-regulated entities from
1993-1995 at a price exceeding the underlying fair value of net
assets acquired resulted in recorded goodwill of $20.3 million
($19.0 million net of accumulated amortization) at Dec. 31,
1995. This goodwill and other intangible assets acquired are
being amortized using the straight-line method over periods of
15 to 30 years. NSP periodically evaluates the recovery of
goodwill based on an analysis of estimated undiscounted future
cash flows.
Intangible and other assets also include deferred financing
costs (net of amortization) of approximately $11.8 million at
Dec. 31, 1995. These costs are being amortized over the
remaining maturity period of the related debt.
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. Accounting Changes
Postemployment Benefits Effective Jan. 1, 1994, NSP adopted the
provisions of SFAS No. 112---Employers' Accounting for
Postemployment Benefits. This standard required the accrual of
certain postemployment costs, such as injury compensation and
severance, that are payable in the future. The Company's pre-
1994 liability of approximately $9.4 million (8 cents per share)
was expensed in 1994.
Postretirement Benefits As discussed in Note 8, NSP changed its
accounting for postretirement medical and death benefits in
1993. Due to rate recovery of the expense increases, the change
had an immaterial effect on net income. Of the 1993 cost
increases due to adoption of SFAS No. 106, about $12 million was
deferred to be amortized over rate recovery periods in 1994-
1996. In 1994, administrative and general expenses increased by
approximately $16 million due to the full recognition of accrued
SFAS No. 106 costs, including amounts deferred from 1993.
3. Investments Accounted for by the Equity Method
Through its non-regulated subsidiaries, NSP has investments in
various international and domestic energy projects and domestic
affordable housing and real estate projects. The equity method
of accounting is applied to such investments in affiliates,
which include joint ventures and partnerships, because the
ownership structure prevents NSP from exercising a controlling
influence over operating and financial policies of the projects.
Under this method, equity in the pretax income or losses of
domestic partnerships and in the net income or losses of
international projects is reflected as Equity in Earnings of
Unconsolidated Affiliates. A summary of NSP's significant
equity-method investments is as follows:
Purchased or
Name Geographic Area Economic Interest Placed in Service
Various Independent Power
Production Facilities U.S.A. 45%-50% July 1991-December 1994
Affordable Housing---Limited
Partnerships U.S.A. 20%-99% April 1993-December 1995
Rosebud SynCoal Partnership U.S.A. 50% August 1993
MIBRAG Mining and Power Generation Europe 33.3% January 1994
Gladstone Power Station Australia 37.5% March 1994
Scudder Latin American Trust
for Independent Power
Energy Projects Latin America 25% June 1993
Schkopau Power Station Europe 20.6% Under construction
Investments in the MIBRAG and Gladstone projects in 1994
resulted in an increase in the equity in earnings from
unconsolidated affiliates of approximately $26 million in 1994.
Summarized Financial Information of Unconsolidated Affiliates
Summarized financial information for these projects, including
interests owned by NSP and other parties, was as follows (as of
and for the years ended Dec. 31, 1995 and 1994):
Financial Position (Millions of dollars)
1995 1994
Current Assets $ 762.1 $ 514.9
Other Assets 2 631.9 1 593.8
Total Assets $3 394.0 $2 108.7
Current Liabilities $ 295.5 $ 159.6
Other Liabilities 2 290.2 1 480.0
Equity 808.3 469.1
Total Liabilities and Equity $3 394.0 $2 108.7
NSP's Equity Investment in
Unconsolidated Affiliates $266.0 $179.1
Results of Operations (Millions of dollars)
1995 1994
Operating Revenues $790.2 $778.4
Operating Income $154.2 $128.8
Net Income $160.2 $117.0
4. Cumulative Preferred Stock
The Company has two series of adjustable rate preferred stock.
The dividend rates are calculated quarterly and are based on
prevailing rates of certain taxable government debt securities
indices. At Dec. 31, 1995, the annualized dividend rates were
$5.50 for both series A and series B.
At Dec. 31, 1995, the various preferred stock series were
callable at prices per share ranging from $102.00 to $103.75,
plus accrued dividends. In 1993, the Company redeemed all
350,000 shares of its $7.84 series Cumulative Preferred Stock at
$103.12 per share.
5. Common Stock and Incentive Stock Plans
The Company's Articles of Incorporation and First Mortgage
Indenture provide for certain restrictions on the payment of
cash dividends on common stock. At Dec. 31, 1995, the Company
could have paid, without restrictions, additional cash dividends
of more than $1 billion on common stock.
NSP has an Executive Long-Term Incentive Award Stock Plan
that permits granting non-qualified stock options. The options
currently granted may be exercised one year from the date of
grant and are exercisable thereafter for up to nine years. The
plan also allows certain employees to receive restricted stock
and other performance awards. Performance awards are valued in
dollars, but paid in shares based on the market price at the
time of payment. Transactions under the various incentive stock
programs, which may result in the issuance of new shares, were
as follows:
Stock Awards (Thousands of shares) 1995 1994 1993
Outstanding Jan. 1 782.4 537.1 528.7
Options granted 278.0 304.0 196.9
Other stock awards .2 9.5
Options and awards exercised (63.8) (42.6) (174.3)
Options and awards forfeited (6.5) (16.1) (22.2)
Other (.1) (.2) (1.5)
Outstanding at Dec. 31 990.0 782.4 537.1
Option price ranges:
Unexercised at Dec. 31 $33.25-$45.50 $33.25-$43.50 $33.25-$43.50
Exercised during the year $33.25-$43.50 $33.25-$43.50 $33.25-$40.94
Using the treasury stock method of accounting for
outstanding stock options, the weighted average number of shares
of common stock outstanding for the calculation of primary
earnings per share includes any dilutive effects of stock
options and other stock awards as common stock equivalents. The
differences between shares used for primary and fully diluted
earnings per share were not material.
6. Short-Term Borrowings
NSP has approximately $282 million of commercial bank credit
lines under commitment fee arrangements. These credit lines make
short-term financing available in the form of bank loans and
support for commercial paper sales. There were no borrowings
against these credit lines at Dec. 31, 1995, and approximately
$3.6 million of such borrowings, with interest payable at 9.75
percent, at Dec. 31, 1994. However, $9.6 million in letters of
credit were outstanding, which reduced the available credit
lines at Dec. 31, 1995.
At Dec. 31, 1995 and 1994, the Company had $215.6 million
and $234.8 million, respectively, in short-term commercial paper
borrowings outstanding. The weighted average interest rates on
all short-term borrowings as of Dec. 31, 1995, and Dec. 31,
1994, were 5.7 percent and 6.1 percent, respectively.
7. Long-Term Debt
The annual sinking-fund requirements of the Company's and the
Wisconsin Company's First Mortgage Indentures are the amounts
necessary to redeem 1 percent of the highest principal amount of
each series of first mortgage bonds at any time outstanding,
excluding those series issued for pollution control and resource
recovery financings, and excluding certain other series totaling
$990 million. The Company may, and has, applied property
additions in lieu of cash payments on all series, as permitted
by its First Mortgage Indenture. The Wisconsin Company also may
apply property additions in lieu of cash on all series as
permitted by its First Mortgage Indenture. Except for minor
exclusions, all real and personal property of the Company and
the Wisconsin Company is subject to the liens of the first
mortgage indentures. Other debt securities are secured by a lien
on the related real or personal property, as indicated on the
Consolidated Statements of Capitalization.
The Company's First Mortgage Bonds Series due March 1,
2011, and the City of Becker Pollution Control Revenue Bonds
Series due March 1, 2019, and Sept. 1, 2019, have variable
interest rates, which currently change at various periods up to
270 days, based on prevailing rates for certain commercial paper
securities or similar issues. The interest rates applicable to
these issues averaged 5.2 percent, 3.7 percent and 3.8 percent,
respectively, at Dec. 31, 1995. The 2011 series bonds are
redeemable upon seven days notice at the option of the
bondholder. The Company also is potentially liable for repayment
of the 2019 Series Becker Bonds when the bonds are tendered,
which occurs each time the variable interest rates change. The
principal amount of all three series of these variable rate
bonds outstanding represents potential short-term obligations
and, therefore, is reported under current liabilities on the
balance sheet.
Maturities and sinking-fund requirements on long-term debt
are: 1996, $25,760,000; 1997, $111,553,000; 1998, $14,457,000;
1999, $210,909,000; and 2000, $115,982,000.
8. Benefit Plans and Other Postretirement Benefits
NSP offers the following benefit plans to its benefit employees,
of whom approximately 43 percent are represented by five local
labor unions under a collective-bargaining agreement, which
expires Dec. 31, 1996.
Pension Benefits NSP has a non-contributory, defined benefit
pension plan that covers substantially all employees. Benefits
are based on a combination of years of service, the employee's
highest average pay for 48 consecutive months and Social
Security benefits.
It is the Company's policy to fully fund the actuarially
determined pension costs recognized for ratemaking purposes,
subject to the limitations under applicable employee benefit and
tax laws. Plan assets principally consist of common stock of
public companies, corporate bonds and U.S. government
securities. The funded status of NSP's pension plan as of Dec.
31 is as follows:
(Thousands of dollars) 1995 1994
Actuarial present value of benefit obligation:
Vested $686 403 $571 254
Non-vested 155 177 120 420
Accumulated benefit obligation $841 580 $691 674
Projected benefit obligation $1 039 981 $836 957
Plan assets at fair value 1 456 530 1 165 584
Plan assets in excess of projected
benefit obligation (416 549) (328 627)
Unrecognized prior service cost (20 805) (21 538)
Unrecognized net actuarial gain 452 699 370 289
Unrecognized net transitional asset 615 691
Net pension liability recorded $15 960 $20 815
For regulatory purposes, the Company's pension expense is
determined and recorded under the aggregate-cost method. As
required by SFAS No. 87---Employers' Accounting for Pensions,
the difference between the pension costs recorded for ratemaking
purposes and the amounts determined under SFAS No. 87 is
recorded as a regulatory liability on the balance sheet. Net
annual periodic pension cost includes the following components:
(Thousands of dollars) 1995 1994 1993
Service cost-benefits earned
during the period $24 499 $27 536 $25 015
Interest cost on projected
benefit obligation 69 742 65 107 71 075
Actual return on assets (344 837) (12 668) (152 019)
Net amortization and deferral 240 458 (82 114) 66 299
Net periodic pension cost determined
under SFAS No. 87 (10 138) (2 139) 10 370
Additional costs recognized due to
actions of regulators 10 454 3 922 5 117
Net periodic pension cost recognized
for ratemaking $316 $1 783 $15 487
The weighted average discount rate used in determining the
actuarial present value of the projected obligation was 7
percent in 1995 and 8 percent in 1994. The rate of increase in
future compensation levels used in determining the actuarial
present value of the projected obligation was 5 percent in 1995
and 1994. The assumed long-term rate of return on assets used
for cost determinations under SFAS No. 87 was 9 percent for 1995
and 8 percent for 1994 and 1993. Assumption changes decreased
1995 pension costs (determined under SFAS No. 87) by
approximately $21.5 million. Assumption changes are expected to
increase 1996 pension costs (determined under SFAS No. 87) by
approximately $13.6 million. Because the Company's pension
expense is determined under the aggregate-cost method (not SFAS
No. 87) for regulatory and financial reporting purposes, the
effects of regulation prevent the majority of these assumption
changes from affecting earnings.
Postretirement Health Care NSP has a contributory health and
welfare benefit plan that provides health care and death
benefits to substantially all employees after their retirement.
The plan is intended to provide for sharing the costs of retiree
health care between NSP and retirees. For employees retiring
after Jan. 1, 1994, a six-year cost-sharing strategy was
implemented with retirees paying 15 percent of the total cost of
health care in 1994, increasing to a total of 40 percent in
1999.
Effective Jan. 1, 1993, NSP adopted the provisions of SFAS
No. 106---Employers' Accounting for Postretirement Benefits
Other Than Pensions. SFAS No. 106 requires the actuarially
determined obligation for postretirement health care and death
benefits to be fully accrued by the date employees attain full
eligibility for such benefits, which is generally when they
reach retirement age. This is a significant change from NSP's
pre-1993 policy of recognizing benefit costs on a cash basis
after retirement. In conjunction with the adoption of SFAS No.
106, NSP elected to amortize on a straight-line basis over 20
years the unrecognized accumulated postretirement benefit
obligation (APBO) of $215.6 million for current and future
retirees. This obligation considered 1994 plan design changes,
including Medicare integration, increased retiree cost sharing
and managed indemnity measures not in effect in 1993.
Before 1993, NSP funded payments for retiree benefits
internally. While NSP generally prefers to continue using
internal funding of benefits paid and accrued, significant
levels of external funding, including the use of tax-advantaged
trusts, have been required by NSP's regulators, as discussed
below. Plan assets held in such trusts as of Dec. 31, 1995,
consisted of investments in equity mutual funds and cash
equivalents. The funded status of NSP's
health care plan as of Dec. 31 is as follows:
(Millions of dollars) 1995 1994
APBO:
Retirees $145.8 $132.2
Fully eligible plan participants 24.4 21.5
Other active plan participants 116.8 79.4
Total APBO 287.0 233.1
Plan assets at fair value 11.6 8.0
APBO in excess of plan assets 275.4 225.1
Unrecognized net actuarial gain (loss) (40.4) 2.3
Unrecognized transition obligation (183.2) (194.0)
Net benefit obligation recorded $51.8 $ 33.4
The assumed health care cost trend rates used in measuring
the APBO at Dec. 31, 1995 and 1994, respectively, were 10.4 and
11.0 percent for those under age 65, and 7.3 and 7.5 percent for
those over age 65. The assumed cost trend rates are expected to
decrease each year until they reach 5.5 percent for both age
groups in the year 2004, after which they are assumed to remain
constant. A 1 percent increase in the assumed health care cost
trend rate for each year would increase the APBO by
approximately 15 percent as of Dec. 31, 1995. Service and
interest cost components of the net periodic postretirement cost
would increase by approximately 17 percent with a similar 1
percent increase in the assumed health care cost trend rate. The
assumed discount rate used in determining the APBO was 7 percent
for Dec. 31, 1995, 8 percent for Dec. 31, 1994, and 7 percent
for Dec. 31, 1993, compounded annually. The assumed long-term
rate of return on assets used for cost determinations under SFAS
No. 106 was 8 percent for 1995 and 1994. Assumption changes
decreased 1994 costs by approximately $2.1 million and decreased
1995 costs by approximately $2.0 million. The effect of the
changes in 1996 is expected to be a cost increase of
approximately $2.1 million.
The net annual periodic postretirement benefit cost
recorded consists of the following components:
(Millions of dollars) 1995 1994 1993
Service cost-benefits earned
during the year $5.2 $5.0 $4.4
Interest cost (on service cost
and APBO) 19.2 16.1 17.5
Actual return on assets (1.0) (.2) (.1)
Amortization of transition obligation 10.8 10.8 10.8
Net amortization and deferral 0.4 (.3) .1
Net periodic postretirement health
care cost under SFAS No. 106 34.6 31.4 32.7
Costs recognized (deferred) due
to actions of regulators 4.0 4.1 (12.1)
Net periodic postretirement
health care cost recognized
for ratemaking $38.6 $35.5 $20.6
Regulators for NSP's retail and wholesale customers in
Minnesota, Wisconsin and North Dakota have allowed full recovery
of increased benefit costs under SFAS No. 106, effective in
1993. Increased 1993 accrual costs for Minnesota retail
customers are being amortized over the years 1994 through 1996,
consistent with approved rate recovery. External funding was
required by Minnesota and Wisconsin retail regulators to the
extent it is tax advantaged; funding began for Wisconsin in 1993
and must begin by the next general rate filing for Minnesota.
For wholesale ratemaking, the FERC has required external funding
for all benefits paid and accrued under SFAS No. 106.
ESOP NSP has a leveraged Employee Stock Ownership Plan (ESOP)
that covers substantially all employees. Employer contributions
to this non-contributory, defined contribution plan are
generally made to the extent NSP realizes a tax savings on its
income statement from dividends paid on certain shares held by
the ESOP. Contributions to the ESOP in 1995, 1994 and 1993,
which represent compensation expense, were $5,059,000,
$5,695,000 and $6,281,000, respectively. ESOP contributions have
no material effect on NSP earnings because the contributions
(net of tax) are essentially offset by the tax savings provided
by the dividends paid on ESOP shares. Leveraged shares held by
the ESOP are allocated to participants when dividends on stock
held by the plan are used to repay ESOP loans. NSP's ESOP held
5.7 million and 5.4 million shares of the Company's common stock
as of Dec. 31, 1995 and 1994, respectively. An average of
221,066 and 111,845 uncommitted leveraged ESOP shares were
excluded from earnings-per-share calculations in 1995 and 1994,
respectively. The fair value of NSP's leveraged ESOP shares
approximated cost at Dec. 31, 1995.
401(k) NSP has a contributory, defined contribution Retirement
Savings Plan, which complies with section 401(k) of the Internal
Revenue Code and covers substantially all employees. Since 1994,
NSP has been matching specified amounts of employee
contributions to this plan. NSP's matching contributions were
$3.7 million in 1995 and $2.6 million in 1994.
9. Income Taxes
Total income tax expense from operations differs from the amount
computed by applying the statutory federal income tax rate to
income before income tax expense. The reasons for the difference
are as follows:
1995 1994 1993
Federal statutory rate 35.0 % 35.0 % 35.0 %
Increases (decreases) in tax from:
State income taxes, net of
federal income tax benefit 5.1 % 5.9 % 6.1 %
Tax credits recognized (3.4)% (3.5)% (2.8)%
Equity income from unconsolidated
international affiliates (2.5)% (2.5)% 0.0 %
Regulatory differences -
utility plant items 1.0 % 0.5 % 1.3 %
Other---net 0.4 % (0.7)% (1.4)%
Effective income tax rate 35.6 % 34.7 % 38.2 %
(Thousands of dollars)
Income taxes are comprised of the
following expense (benefit) items:
Included in utility operating
expenses:
Current federal tax expense $137 011 $108 652 $92 099
Current state tax expense 33 359 34 823 25 787
Deferred federal tax expense (12 019) (3 450) 15 010
Deferred state tax expense (2 396) (1 606) 4 431
Deferred investment tax credits (8 807) (9 191) (8 981)
Total 147 148 129 228 128 346
Included in other income (expense):
Current federal tax expense 5 481 3 959 7 853
Current state tax expense 1 629 923 2 289
Current foreign tax expense 233 219
Current federal tax credits (5 292) (3 548) (321)
Deferred federal tax expense 2 646 (835) (6 736)
Deferred state tax expense 693 (209) (449)
Deferred investment tax credits (310) (310) (242)
Total 5 080 199 2 394
Total income tax expense $152 228 $129 427 $130 740
Income before income taxes includes net foreign equity
income of $32.3 and $25.9 million in 1995 and 1994,
respectively. NSP's management intends to reinvest the earnings
of foreign operations indefinitely. Accordingly, U.S. income
taxes and foreign withholding taxes have not been provided on
the earnings of foreign subsidiary companies. The cumulative
amount of undistributed earnings of foreign subsidiaries upon
which no U.S. income taxes or foreign withholding taxes have
been provided is approximately $61.6 million at Dec. 31, 1995.
The additional U.S. income tax and foreign withholding tax on
the unremitted foreign earnings, if repatriated, would be offset
in whole or in part by foreign tax credits. Thus, it is
impracticable to estimate the amount of tax that might be
payable.
The components of NSP's net deferred tax liability (current and
non-current portions) at Dec. 31 were:
(Thousands of dollars) 1995 1994
Deferred tax liabilities:
Differences between book and tax bases
of property $866 784 $843 872
Regulatory assets 124 910 120 329
Tax benefit transfer leases 59 579 76 775
Other 13 338 7 854
Total deferred tax liabilities $1 064 611 $1 048 830
Deferred tax assets:
Regulatory liabilities $96 935 $80 383
Deferred investment tax credits 61 911 65 812
Deferred compensation, vacation and
other accrued liabilities not
currently deductible 57 209 50 572
Other 22 658 18 110
Total deferred tax assets $238 713 $214 877
Net deferred tax liability $825 898 $833 953
10. Regulatory Assets and Liabilities
The following summarizes the individual components of
unamortized regulatory assets and liabilities shown on the
Consolidated Balance Sheets at Dec. 31:
Amortization
(Thousands of dollars) Period 1995 1994
AFC recorded in plant on a
net-of-tax basis* Plant Lives $146 662 $155 102
Conservation and energy
management programs* Up to 10 Years 98 570 76 902
Losses on reacquired debt Term of New Debt 63 209 52 514
Environmental costs Up to 15 Years 45 018 47 779
Deferred postretirement
benefit costs 3-15 Years 5 568 9 930
Unrecovered purchased gas costs 1-2 Years 5 932 7 601
State commission accounting
adjustments* Plant Lives 7 221 5 544
Other Various 2 032 2 204
Total regulatory assets $374 212 $357 576
Excess deferred income taxes collected
from customers $83 066 $75 277
Investment tax credit deferrals 104 371 110 831
Unrealized gains from decommissioning
investments 26 374 1 412
Pension costs 21 508 11 054
Fuel costs and other 7 468 1 943
Total regulatory liabilities $242 787 $200 517
* Earns a return on investment in the ratemaking process.
11. Financial Instruments
Fair Values The estimated Dec. 31 fair values of NSP's recorded
financial instruments are as follows:
1995 1994
Carrying Fair Carrying Fair
(Thousands of dollars) Amount Value Amount Value
Cash, cash equivalents and
short-term investments $28 943 $28 943 $41 947 $41 947
Long-term decommissioning
investments $203 625 $203 625 $145 467 $145 467
Long-term debt, including
current portion $1 709 646 $1 781 066 $1 621 060 $1 540 595
For cash, cash equivalents and short-term investments, the
carrying amount approximates fair value because of the short
maturity of those instruments. The fair values of the Company's
long-term investments in an external nuclear decommissioning fund
are estimated based on quoted market prices for those or similar
investments. The fair value of NSP's long-term debt is estimated
based on the quoted market prices for the same or similar issues,
or the current rates offered to NSP for debt of the same remaining
maturities.
Derivatives NRG has entered into six forward foreign currency
exchange contracts with counterparties to hedge exposure to
currency fluctuations to the extent permissible by hedge accounting
requirements. Pursuant to these contracts, transactions have been
executed that are designed to protect the economic value in U.S.
dollars of NRG's equity investments and retained earnings,
denominated in Australian dollars and German deutsche marks (DM).
NRG's forward foreign currency exchange contracts, in the notional
amount of $119 million, hedge approximately $123 million of foreign
currency denominated assets, and in the notional amount of $47
million, hedge approximately $64 million of foreign currency
denominated retained earnings at Dec. 31, 1995. Because the effects
of both currency translation adjustments to foreign investments and
currency hedge instrument gains and losses are recorded on a net
basis in stockholders' equity (not earnings), the impact of
significant changes in currency exchange rates on these items would
have an immaterial effect on NSP's financial condition and results
of operations. The contracts required cash collateral balances of
$5.9 million at Dec. 31, 1995, which are reflected as other current
assets on NSP's balance sheet. The contracts terminate in 1998
through 2005 and require foreign currency interest payments by
either party during each year of the contract. If the contracts had
been terminated at Dec. 31, 1995, $5.2 million would have been
payable by NRG for currency exchange rate changes to date.
Management believes NRG's exposure to credit risk due to non-
performance by the counterparties to its forward exchange contracts
is not significant, based on the investment grade rating of the
counterparties.
Cenergy has entered into natural gas futures contracts in the
notional amount of $11.3 million at Dec. 31, 1995. The original
contract terms range from one month to three years. The contracts
are intended to mitigate risk from fluctuations in the price of
natural gas that will be required to satisfy sales commitments for
future deliveries to customers in excess of Cenergy's natural gas
reserves. Cenergy's futures contracts hedge $11.5 million in
anticipated natural gas sales in 1996-1997. Margin balances of $2.3
million at Dec. 31, 1995, were maintained on deposit with brokers
and recorded as cash and cash equivalents on NSP's balance sheet.
The counterparties to the futures contracts are the New York
Mercantile Exchange and major gas pipeline operators. Management
believes that the risk of non-performance by these counterparties
is not significant. If the contracts had been terminated at Dec.
31, 1995, $0.6 million would have been payable to Cenergy for
natural gas price fluctuations to date.
NSP has three interest rate swap agreements with notional
amounts totalling $320 million. These swaps were entered into in
conjunction with first mortgage bonds. As summarized below, these
agreements effectively convert the interest costs of these debt
issues from fixed to variable rates based on six-month London
Interbank Offered Rates (LIBOR), with the rates changing
semiannually.
Net Effective
Notional Amount Term of Interest Cost
Series (millions of dollars) Swap Agreement at Dec. 31, 1995
5 7/8% Series due
Oct. 1, 1997 $100 Maturity 5.94%
5 1/2% Series due
Feb. 1, 1999 $200 Maturity 5.36%
7 1/4% Series due
March 1, 2023 $ 20 March 1, 1998 8.03%
Market risks associated with these agreements 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. 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 swaps. If the interest
rate swaps had been discontinued on Dec. 31, 1995, the present
value benefit to NSP would have been $2.8 million, which is
partially offset by an increase in the present value of the related
debt of $0.9 million above carrying value.
Letters of Credit NSP uses letters of credit to provide financial
guarantees for certain operating obligations, including NSP
workers' compensation benefits and ash disposal site costs, and
Cenergy natural gas purchases. At Dec. 31, 1995, letters of credit
of $46.7 million were outstanding. Generally, the letters of credit
have terms of one year and are automatically renewed, unless prior
written notice of cancellation is provided to NSP and the
beneficiary by the issuing bank. The contract amounts of these
letters of credit approximate their fair value and are subject to
fees competitively determined in the marketplace.
12. Detail of Certain Income and Expense Items
Administrative and general (A&G) expense for utility operations consists of
the following:
(Thousands of dollars) 1995 1994 1993
A&G salaries and wages $48 437 $49 726 $51 601
Postretirement medical and injury
compensation benefits 34 112 41 901 14 995
Other benefits---all
utility employees 47 167 38 792 51 860
Information technology, facilities
and administrative support 31 863 29 751 30 504
Insurance and claims 13 969 16 771 16 165
Other 10 599 11 055 11 492
Total $186 147 $187 996 $176 617
Other income (deductions)---net consist of the following:
(Thousands of dollars) 1995 1994 1993
Non-regulated operations:
Operating revenues and sales $313 082 $241 827 $90 531
Operating expenses 327 894* 241 480* 81 480
Pretax operating income** (14 812) 347 9 051
Interest and investment income 11 953 10 839 4 522
Charitable contributions (5 314) (5 037) (4 752)
Environmental and regulatory
contingencies 1 027 (4 568) (100)
Other---net (excluding
income taxes) (829) (5 267) (739)
Total---net income (expense) $ (7 975) $ (3 686) $ 7 982
*Includes non-regulated energy project write-downs of $5.0 million
in 1995 and $5.0 million in 1994.
**See Non-Regulated Subsidiaries-Non-Regulated Business Information
under Item 1.
13. Joint Plant Ownership
The Company is a participant in a jointly owned 855-megawatt coal-
fired electric generating unit, Sherburne County generating station
unit No. 3 (Sherco 3), which began commercial operation Nov. 1,
1987. Undivided interests in Sherco 3 have been financed and are
owned by the Company (59 percent) and Southern Minnesota Municipal
Power Agency (41 percent). The Company is the operating agent under
the joint ownership agreement. The Company's share of related
expenses for Sherco 3 since commercial operations began are
included in Utility Operating Expenses. The Company's share of the
gross cost recorded in Utility Plant at Dec. 31, 1995 and 1994, was
$585,625,000 and $585,783,000, respectively. The corresponding
accumulated provisions for depreciation were $150,022,000 and
$132,092,000.
14. Nuclear Obligations
Fuel Disposal NSP is responsible for the temporary storage of used
nuclear fuel from the Company's nuclear generating plants. Under a
contract with the Company, the DOE is obligated to assume the
responsibility for permanent storage or disposal of NSP's used
nuclear fuel. The Company has been funding its portion of the DOE's
permanent disposal program since 1981. Funding took place through
an internal sinking fund until 1983, when the DOE began assessing
fuel disposal fees under the Nuclear Waste Policy Act of 1982 based
on a charge of 0.1 cent per kilowatt-hour sold to customers from
nuclear generation. The cumulative amount of such assessments from
the DOE to NSP through Dec. 31, 1995, is $230.8 million. Currently,
it is not determinable if the amount and method of the DOE's
assessments to all utilities will be sufficient to fully fund the
DOE's permanent storage or disposal facility.
The DOE has stated in statute and by contract that a permanent
storage or disposal facility would be ready to accept used nuclear
fuel by 1998. Accordingly, NSP has been providing, with regulatory
and legislative approval, its own temporary on-site storage
facilities at its Monticello and Prairie Island nuclear plants,
with a capacity sufficient for used fuel from the plants until at
least that date. Recent indications from the DOE are that a
permanent federal facility will not be ready to accept used fuel
from utilities until approximately 2010. In 1994, the Company and
13 other major utilities filed a lawsuit against the DOE in an
attempt to clarify the DOE's obligation to accept spent nuclear
fuel beginning in 1998. The primary purpose of the lawsuit is to
insure the Company and its customers receive timely storage of used
nuclear fuel. The lawsuit was argued before the United States
Circuit Court of Appeals for the District of Columbia on Jan. 17,
1996 and a decision is expected in three to six months from the
time of argument. In 1995, the DOE published its "Final
Interpretations of Nuclear Waste Acceptance Issues" in the Federal
Register. In this notice, the DOE concluded that it has neither an
unconditional obligation to accept spent nuclear fuel by 1998 nor
any authority to provide interim storage. Because of the DOE's
inadequate progress to provide a permanent repository and its
disavowal of its obligation, the Minnesota Department of Public
Service is investigating whether continued payments to fund the
DOE's permanent disposal program is prudent use of ratepayer money.
The outcome of this investigation is unknown at this time. In the
meantime, NSP is investigating all of its alternatives for used
fuel storage until a DOE facility is available. When on-site
temporary storage at NSP's nuclear plants reaches approved
capacity, the Company could seek interim storage at a contracted
private facility. The Company received Minnesota legislative
approval in 1994 for additional on-site storage facilities at its
Prairie Island plant, provided the Company satisfies certain
requirements. Seventeen dry cask containers, each of which can
store approximately one-half year's used fuel, can become available
as follows: five immediately in 1994; four more in 1996 if an
application for an alternative storage site is filed, an effort to
locate such a site is made and 100 megawatts of wind generation is
available or contracted for construction; and the final eight in
1999, unless the specified alternative site is not operational or
under construction, certain resource commitments are not met, or
the Minnesota Legislature revokes its approval. (See additional
discussion of legislative commitments in Note 15.) NSP has loaded
used fuel into three of the dry cask containers as of Dec. 31,
1995. With the dry cask storage facilities approved in 1994 for the
Prairie Island nuclear generating plant, the Company believes it
has adequate storage capacity to continue operation of its nuclear
plants until at least 2002 and 2003 for Prairie Island Units 1 and
2, respectively. The Monticello nuclear plant has storage capacity
to continue operations until 2010. Storage availability to permit
operation beyond these dates is not assured at this time.
Two alternatives to on-site storage of used fuel are currently
under consideration. As discussed in Note 15, the Company is
investigating alternative sites in Goodhue County, Minnesota, for
interim used nuclear fuel storage. Also, the Company is leading a
consortium working with the Mescalero Apache Tribe to establish a
private facility for interim storage of used nuclear fuel on the
Tribe's reservation in New Mexico. A core group of more than 20
United States nuclear utilities has agreed to support the
construction and operation of the Mescalaro interim storage site.
Work on the project is under way in several areas, including
environmental assessment, facility design and drafting the detailed
contracts that will govern the construction and operation of the
site. An architect engineering firm and an environmental contractor
have been retained to perform the environmental and licensing
activities. The consortium is currently scheduled to submit a
license application for the facility to the Nuclear Regulatory
Commission (NRC) in December 1996. The spent fuel storage facility
is expected to be operational and able to accept the first shipment
of used nuclear fuel by mid-2002. However, due to pending
regulatory and governmental approval uncertainty, it is possible
that this interim storage may be delayed or not available.
Fuel expense includes DOE fuel disposal assessments of $12.3
million, $10.6 million and $8.7 million for 1995, 1994 and 1993,
respectively. Disposal expenses reflect reductions of $0.7 million
in 1994 and $2.6 million in 1993 due to a change in the DOE's basis
of charging customers, retroactive to 1983. Nuclear fuel expenses
in 1995, 1994 and 1993 also include about $5 million, $5 million
and $1 million, respectively, for payments to the DOE for the
decommissioning and decontamination of the DOE's uranium enrichment
facilities. The DOE's initial assessment of $46 million to the
Company was recorded in 1993. This assessment will be payable in
annual installments from 1993-2008 and each installment is being
amortized to expense on a monthly basis in the 12 months following
each payment. The most recent installment paid in 1995 was $3.7
million; future installments are subject to inflation adjustments
under DOE rules. The Company is obtaining rate recovery of these
DOE assessments through the cost-of-energy adjustment clause as the
assessments are amortized. Accordingly, the unamortized assessment
of $44 million at Dec. 31, 1995, has been deferred as a regulatory
asset and is reported under the caption Environmental Costs in Note
10.
Plant Decommissioning Decommissioning of all Company nuclear
facilities is planned for the years 2010-2022, using the prompt
dismantlement method. The Company is currently following industry
practice by ratably accruing the costs for decommissioning over the
approved cost recovery period and including the accruals in Utility
Plant---Accumulated Depreciation, as discussed in Note 1.
Consequently, the total decommissioning cost obligation and
corresponding asset currently are not recorded in NSP's financial
statements. The FASB has proposed new accounting standards which,
if approved as expected in 1996, would require the full accrual of
nuclear plant decommissioning and certain other site exit
obligations beginning in 1997. If NSP were to adopt the proposed
accounting, beginning in 1997 an estimated total discounted
decommissioning obligation of $610 million would be recorded as a
liability, with the corresponding costs capitalized as a plant
asset and depreciated over the operating life of the plant. The
obligation calculation methodology proposed by the FASB is slightly
different from the ratemaking methodology that derives the
decommissioning accruals currently being recovered in rates (as
discussed below). The Company has not yet determined the potential
impact of the FASB's proposed changes in the accounting for site
exit obligations other than nuclear decommissioning (such as costs
of removal). However, the ultimate decommissioning and site exit
costs to be accrued are the same under both methods and,
accordingly, the effects of regulation are expected to minimize or
eliminate any impact on operating expenses and results of
operations from this future accounting change.
Consistent with cost recovery in utility customer rates, the
Company records annual decommissioning accruals based on periodic
site-specific cost studies and a presumed level of dedicated
funding. Cost studies quantify decommissioning costs in current
dollars. Since the costs are expected to be paid in 2010-2022,
funding presumes that current costs will escalate in the future at
a rate of 4.5 percent per year. The total estimated decommissioning
costs that will ultimately be paid, net of income earned by
external trust funds, is currently being accrued using an annuity
approach over the approved plant recovery period. This annuity
approach uses the assumed rate of return on funding, which is
currently 6 percent (net of tax) for external funding and
approximately 8 percent (net of tax) for internal funding.
The total obligation for decommissioning currently is expected
to be funded approximately 82 percent by external funds and 18
percent by internal funds, as approved by the MPUC. Rate recovery
of internal funding began in 1971 through depreciation rates for
removal expense, and was changed to a sinking fund recovery in
1981. Contributions to the external fund started in 1990 and are
expected to continue until plant decommissioning begins. Costs not
funded by external trust contributions and related earnings will be
funded through internally generated funds and issuance of Company
debt or stock. The assets held in trusts as of Dec. 31, 1995,
primarily consisted of investments in tax-exempt municipal bonds,
common stock of public companies and U.S. government securities.
The following table summarizes the funded status of the
decommissioning obligation at Dec. 31, 1995, under the method
currently in use.
(Millions of dollars) 1995
Decommissioning cost estimate from most
recent study (1993 dollars) $750.8
Effect of escalating costs to payment date
(at 4.5% per year) 1 094.0
Estimated future decommissioning costs
(undiscounted) $1 844.8
Estimated decommissioning cost obligation
escalated to current dollars $ 819.9
External trust fund assets at fair value 203.6
Decommissioning obligation in excess of
assets currently held in external trust $ 616.3
Decommissioning expenses recognized include the following components:
(Millions of dollars) 1995 1994 1993
Annual decommissioning cost accrual
reported as depreciation expense:
Externally funded $33.2 $33.2 $28.4
Internally funded (including
interest costs) 1.2 1.1 14.5
Interest cost on externally funded
decommissioning obligation 6.0 3.5 3.7
Earnings from external trust
funds---net (6.0) (3.5) (3.7)
Current year decommissioning
accruals---net $34.4 $34.3 $42.9
At Dec. 31, 1995, the Company has recorded and recovered in
rates cumulative decommissioning accruals of $381 million; $177
million has been deposited into external trust funds for such
accruals. The Company believes future decommissioning cost accruals
will continue to be recovered in customer rates. Decommissioning
and interest accruals are included with the accumulated provision
for depreciation on the balance sheet. Interest costs and trust
earnings associated with externally funded obligations are reported
in Other Income and Expense on the income statement.
A revision to NSP's 1993 nuclear decommissioning study and
nuclear plant depreciation capital recovery request was filed with
the MPUC and approved in 1994. Although management expects to
operate the Prairie Island units through the end of their licensed
lives, the approved capital recovery would allow for the plant to
be fully depreciated, including the accrual and recovery of
decommissioning costs in 2008, about six years earlier than the end
of its licensed life. The approved recovery period for Prairie
Island has been reduced because of the uncertainty regarding used
fuel storage. The updated nuclear decommissioning study resulted in
a decrease in annual cost accruals for decommissioning due to a
reduction in decommissioning cost estimates as well as the
shortened recovery period. The combined impact of the request as
approved, including the shorter depreciation period and lower
decommissioning costs, was a net decrease of about $800,000 in
annual depreciation and decommissioning expenses, beginning in
1994.
15. Commitments and Contingent Liabilities
Legislative Resource Commitments In 1994, the Minnesota Legislature
established several energy resource and other commitments for NSP
to fulfill to obtain the Prairie Island temporary nuclear fuel
storage facility approval, as discussed in Note 14. The additional
resource commitments, which can be built, purchased or (in the case
of biomass generation) converted, can be summarized as follows:
Power Type Megawatts Deadline
Wind 100 (1) (Additional) 12/31/96 (3)
Wind 225 (Cumulative) 12/31/98 (4)
Biomass 50 (Additional) 12/31/98 (5)
Wind 200 (Additional) 12/31/02
Biomass 75 (Additional) 12/31/02
Wind 400 (2) (Additional) 12/31/02
(1) In addition to 25 megawatts of wind generation currently
installed
(2) If required by least-cost planning and resource planning
(3) Power purchase contract awarded to Zond Systems, Inc.
(4) Power purchase bids to be received mid-1996
(5) Power purchase bid decision expected in March 1996
The Company has taken steps to comply with the requirements of
these resource commitments. Twenty-five megawatts of third party
wind generation has been fully operational since May 1, 1994. With
respect to the additional 100 megawatts of wind energy to be under
contract by the end of 1996, the Company has obtained a site
designation from the Minnesota Environmental Quality Board (MEQB),
and selected Zond Systems, Inc. to supply the wind energy. The
Company must now secure wind rights for the site from an
unsuccessful bidder, which has indicated it will not voluntarily
transfer the wind rights. The Company has commenced litigation to
expedite resolution of the wind rights dispute. Siting and design
activities are proceeding while wind rights acquisition efforts
continue. An independent evaluator also reviewed proposals from
bidders regarding 50 megawatts of farm-grown closed-loop biomass
generation and made a recommendation to the Company in January
1996, with a final decision to be made in early 1996. On Jan. 22,
1996, the Company notified the MPUC that due to the price of the
various bids and other factors, the Company intended to reject each
of the bids. Since legislation may be proposed to change various
elements of the biomass mandate, the Company proposed to delay its
report detailing the Company's decision and its proposal to meet
the statutory mandate until later in 1996.
Other commitments established by the Legislature include
applying for, locating and licensing an alternative used fuel
storage site, a low-income discount for electric customers,
additional required conservation improvement expenditures and
various study and reporting requirements to a legislative electric
energy task force formed in 1994. In January 1995, the MPUC
approved the Company's low-income discount programs in accordance
with the statute. In July 1995, the Company filed documents with
the MEQB outlining two alternative Goodhue County sites to be
considered for the development of an interim used nuclear fuel
storage facility, as the Minnesota Legislature required. The MEQB
has begun a 12- to 18-month public process to examine these sites
and any others that may be proposed. The Company has implemented
programs to begin meeting the other legislative commitments. The
Company's capital commitments disclosed below include the known
effects of the 1994 Prairie Island legislation. The impact of the
legislation on power purchase commitments and other operating
expenses is not yet determinable.
Capital Commitments NSP estimates utility capital expenditures,
including acquisitions of nuclear fuel, will be $410 million in
1996 and $1.9 billion for 1996-2000. There also are contractual
commitments for the disposal of used nuclear fuel. (See Note 14.)
NRG is contractually committed to additional equity
investments in an existing German energy project. Such commitments
are for approximately DM 33 million in 1996. The 1996 commitment
would be approximately $23 million, based on exchange rates in
effect at Dec. 31, 1995. In addition, NRG is contractually
committed to additional equity investments of $17 million in the
Scudder Latin American Trust for Independent Power Energy Projects,
as of Dec. 31, 1995.
NRG is in the final stages of purchasing a 42 percent interest
in O'Brien Environmental Energy, Inc. (O'Brien) from bankruptcy. In
connection with its bid for O'Brien, on Jan. 3, 1996, NRG obtained
a $100 million letter of credit from a bank, which is secured by a
pledge of various NRG assets. NRG delivered the letter of credit to
O'Brien on Jan. 18, 1996, to secure its obligation to complete its
proposed investment in O'Brien. In January 1996, the United States
Bankruptcy Court for the District of New Jersey confirmed the
Chapter 11 Plan of Reorganization for O'Brien proposed by NRG and
other interested parties. O'Brien has interests in eight domestic
operating power generation facilities with aggregate capacity of
approximately 230 megawatts, and in one 150-megawatt facility in
the contract stage of development. As a result of the purchase,
approximately $107 million would be made available to O'Brien's
creditors by NRG. At least $81 million of the total made available
to the creditors would be provided by NRG as follows: (i) a $28
million equity investment by NRG for its 42 percent interest in
O'Brien; (ii) a $7.5 million investment by NRG for all of O'Brien's
interest in certain biogas projects; and (iii) a $45 million
unsecured loan from NRG to O'Brien. NRG currently is negotiating
with an unaffiliated lender to refinance O'Brien's Newark Boxboard
project in the amount of $56 million, of which approximately $26
million would be applied for distribution to O'Brien's creditors in
reduction of NRG's approximately $107 million obligation. If this
financing is not obtained concurrently with the closing of the
O'Brien transaction, NRG would be obligated to make a $26 million
loan to O'Brien after its reorganization.
Leases Rentals under operating leases were approximately $26.9
million, $24.0 million and $27.5 million for 1995, 1994 and 1993,
respectively. Future commitments under these leases generally
decline from current levels.
Fuel Contracts NSP has contracts providing for the purchase and
delivery of a significant portion of its current coal, nuclear fuel
and natural gas requirements. These contracts, which expire in
various years between 1996 and 2013, require minimum contractual
purchases and deliveries of fuel, and additional payments for the
rights to purchase coal in the future. In total, NSP is committed
to the minimum purchase of approximately $529 million of coal, $26
million of nuclear fuel and $512 million of natural gas and related
transportation, or to make payments in lieu thereof, under these
contracts. In addition, NSP is required to pay additional amounts
depending on actual quantities shipped under these agreements. As
a result of FERC Order 636, NSP has been very active in developing
a mix of gas supply, transportation and storage contracts designed
to meet its needs for retail gas sales. The contracts are with
several suppliers and for various periods of time. Because NSP has
other sources of fuel available and suppliers are expected to
continue to provide reliable fuel supplies, risk of loss from non-
performance under these contracts is not considered significant. In
addition, NSP's risk of loss (in the form of increased costs) from
market price changes in fuel is mitigated through the cost-of-
energy adjustment provision of the ratemaking process, which
provides for recovery of nearly all fuel costs.
Power Agreements The Company has executed several agreements with
the Manitoba Hydro-Electric Board (MH) for hydroelectricity. A
summary of the agreements is as follows:
Years Megawatts
Participation Power Purchase 1996-2005 500
Seasonal Participation
Power Purchase 1996 250
Seasonal Peaking Power Purchase 1996 200
Seasonal Diversity Exchanges:
Summer exchanges from MH 1996-2014 150
1997-2016 200
Winter exchanges to MH 1996-2014 150
1996-2015 200
2015-2017 400
2018 200
The cost of the 500-megawatt participation power purchase
commitment is based on 80 percent of the costs of owning and
operating the Company's Sherco 3 generating plant (adjusted to 1993
dollars). The total estimated future annual capacity costs for all
MH agreements is projected to be approximately $65 million.
However, the Company and MH have consented to arbitration to
finalize interpretations of specific contractual factors relating
to the 500-megawatt participation agreement. These commitments to
MH, which represent about 22 percent of MH's output capability in
1996, account for approximately 13 percent of NSP's 1996 electric
system capability. The risk of loss from non-performance by MH is
not considered significant, and the risk of loss from market price
changes is mitigated through cost-of-energy rate adjustments.
The Company has an agreement with Minnkota Power Cooperative
(MPC) for the purchase of summer season capacity and energy. From
1996 through 2001, the Company will buy 150 megawatts of summer
season capacity for $12.4 million annually. From 2002 through 2015,
the Company will purchase 100 megawatts of capacity for $10.0
million annually. Under the agreement, energy will be priced
against the cost of fuel consumed per megawatt-hour at the Coyote
Generating Station in North Dakota. The Company also has three
seasonal (summer) purchase power agreements with MPC, Minnesota
Power and Mid American Energy Company for the purchase of 388
megawatts in 1996, including reserves. The annual cost of this
capacity will be approximately $4 million.
The Company has agreements with several non-regulated power
producers to purchase electric capacity and associated energy. The
1996 cost of these commitments for non-regulated installed capacity
is approximately $20 million for 115 megawatts. This annual cost
will increase to approximately $37 million-$44 million for 1997-
2018 and then decrease to approximately $25 million-$29 million for
2019-2027 due to the expiration of existing agreements and an
additional agreement for the purchase of 245 to 262 megawatts.
Nuclear Insurance The Company's public liability for claims
resulting from any nuclear incident is limited to $8.9 billion
under the 1988 Price-Anderson amendment to the Atomic Energy Act of
1954. The Company has secured $200 million of coverage for its
public liability exposure with a pool of insurance companies. The
remaining $8.7 billion of exposure is funded by the Secondary
Financial Protection Program, available from assessments by the
federal government in case of a nuclear accident. The Company is
subject to assessments of up to $79.3 million for each of its three
licensed reactors to be applied for public liability arising from
a nuclear incident at any licensed nuclear facility in the United
States. The maximum funding requirement is $10 million per reactor
during any one year.
The Company purchases insurance for property damage and site
decontamination cleanup costs with coverage limits of $2.0 billion
for each of the Company's two nuclear plant sites. The coverage
consists of $500 million from Nuclear Mutual Limited (NML) and $1.5
billion from Nuclear Electric Insurance Limited (NEIL).
NEIL also provides business interruption insurance coverage,
including the cost of replacement power obtained during certain
prolonged accidental outages of nuclear generating units. Premiums
billed to NSP from NML and NEIL are expensed over the policy term.
All companies insured with NML and NEIL are subject to
retrospective premium adjustments if losses exceed accumulated
reserve funds. Capital has been accumulated in the reserve funds of
NML and NEIL to the extent that the Company would have no exposure
for retrospective premium assessments in case of a single incident
under the business interruption and the property damage insurance
coverages. However, in each calendar year, the Company could be
subject to maximum assessments of approximately $4.9 million (five
times the amount of its annual premium) and $36.8 million
(generally 7.5 times the amount of its annual premium) if losses
exceed accumulated reserve funds under the business interruption
and property damage coverages, respectively.
Environmental Contingencies Other long-term liabilities include an
accrual of $42 million, and other current liabilities include an
accrual of $6 million at Dec. 31, 1995, for estimated costs
associated with environmental remediation. Approximately $37
million of the long-term liability and $4 million of the current
liability relate to a DOE assessment for decommissioning of a
federal uranium enrichment facility, as discussed in Note 14. Other
estimates have been recorded for expected environmental costs
associated with manufactured gas plant sites formerly used by the
Company and other waste disposal sites, as discussed below.
These environmental liabilities do not include accruals
recorded (and collected from customers in rates) for future nuclear
fuel disposal costs or decommissioning costs related to the
Company's nuclear generating plants. (See Note 14 for further
discussion.)
The Environmental Protection Agency (EPA) or state
environmental agencies have designated the Company as a
"potentially responsible party" (PRP) for 12 waste disposal sites
to which the Company allegedly sent hazardous materials. Under
applicable law, the Company, along with each PRP, could be held
jointly and severally liable for the total remediation costs of all
12 sites, which are currently estimated between $123 million and
$126 million. If additional remediation is necessary or unexpected
costs are incurred, the amount could be in excess of $126 million.
The Company is not aware of the other parties' inability to pay,
nor does it know if responsibility for any of the sites is disputed
by any party. The Company's share of the costs associated with
these 12 sites is approximately $2.5 million. Of this amount, about
$1.5 million already has been paid in connection with eight of the
12 sites for which the Company has settled with the EPA and other
PRPs. For the remaining four sites, neither the amount of
remediation costs nor the final method of their allocation among
all designated PRPs has been determined. However, the Company has
recorded an estimate of approximately $1 million for future costs
for all four sites, with the estimated payment dates not
determinable at this time. While it is not feasible to determine
the outcome of these matters, amounts accrued represent the best
current estimate of the Company's future liability for the
remediation costs of these sites. It is the Company's practice to
vigorously pursue and, if necessary, litigate with insurers to
recover incurred remediation costs whenever possible. Through
litigation, the Company has recovered from other PRPs a portion of
the remediation costs paid to date. Management believes costs
incurred in connection with the sites, which are not recovered from
insurance carriers or other parties, should be allowed recovery in
future ratemaking. Until the Company is identified as a PRP, it is
not possible for the Company to predict the timing or amount of any
costs associated with cleanup sites other than those discussed
above.
The Wisconsin Company potentially may be involved in the
cleanup and remediation at three sites. One site is a solid and
hazardous waste landfill site in Eau Claire, Wis. The Wisconsin
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 PRPs has been determined, it is not
feasible to predict the outcome of this matter at this time. The
second site, in Ashland, Wis., contains creosote/coal tar
contamination. In 1995, the Wisconsin Department of Natural
Resources (WDNR) notified the Wisconsin Company that it is a PRP at
this site. At this time, the WDNR has determined that the
Wisconsin Company is the only PRP at this site. The site has three
distinct portions - the Wisconsin Company portion of the site, the
Kreher Park portion of the site and the Chequamegon Bay (of Lake
Superior) portion of the site. The Wisconsin Company portion of the
site, formerly a coal gas plant site, is Wisconsin Company
property. The Kreher Park portion of the site is adjacent to the
Wisconsin Company site and is not owned by the Wisconsin Company.
The Chequamegon Bay portion of the site is adjacent to the Kreher
Park portion of the site and is not owned by the Wisconsin Company.
The Wisconsin Company is discussing its potential involvement in
the Kreher Park and Chequamegon Bay portions of the site with the
WDNR and the City of Ashland. At Dec. 31, 1995, the Wisconsin
Company had recorded an estimated liability of $900,000 for future
remediation costs at the Ashland site and had incurred
approximately $400,000 in actual expenditures. Investigations are
under way to determine the Wisconsin Company's responsibility as
well as that of predecessor companies contributing to the
contamination existing at the Ashland site. The investigation also
should determine the extent and source of the contamination and
potential methods for remediation. (See subsequent event section
below.) An estimate of cleanup and remediation costs at the Eau
Claire site and any further costs at the Ashland site and the
extent of the Wisconsin Company's responsibility, if any, for
sharing such costs are not known at this time. The third site is a
landfill site in Hudson, Wis., which is one of the 12 waste
disposal sites discussed previously.
The Company also is continuing to investigate 15 properties,
either presently or previously owned by the Company, which were at
one time sites of gas manufacturing, gas storage plants or gas
pipelines. The purpose of this investigation is to determine if
waste materials are present, if such materials constitute an
environmental or health risk, if the Company has any responsibility
for remedial action and if recovery under the Company's insurance
policies can contribute to any remediation costs. Of the 15 gas
sites under investigation, the Company already has remediated one
site and is actively taking remedial action at four of the sites.
In addition, the Company has been notified that two other sites
eventually will require remediation, and a study will be initiated
in 1996 to determine the cost and method of cleanup. Cleanup is
expected to begin in 1997. The Company has paid $6.7 million to
date on these seven active sites. The one remediated site continues
to be monitored. The Company has recorded an estimated liability
for future costs at the other six active sites of approximately
$6.1 million, with payment expected over the next 10 years. This
estimate is based on prior experience and includes investigation,
remediation and litigation costs. As for the eight inactive sites,
no liability has been recorded for remediation or investigation
because the present land use at each of these sites does not
warrant a response action. While it is not feasible to determine
the precise outcome of all of these matters, the accruals recorded
represent the current best estimate of the costs of any required
cleanup or remedial actions at these former gas operating sites.
Management also believes that incurred costs, which are not
recovered from insurance carriers or other parties, should be
allowed recovery in future ratemaking. During 1994, the Company's
gas utility received approval for deferred accounting for certain
gas remediation costs incurred at four active sites, with final
rate treatment of such costs to be determined in future general gas
rate cases.
The Clean Air Act, including the Amendments of 1990 (the Clean
Air Act), calls for reductions in emissions of sulfur dioxide and
nitrogen oxides from electric generating plants. These reductions,
which will be phased in, began in 1995. The majority of the rules
implementing this complex legislation have been finalized. No
additional capital expenditures are anticipated to comply with the
sulfur dioxide emission limits of the Clean Air Act. NSP has
expended significant amounts over the years to reduce sulfur
dioxide emissions at its plants. Based on revisions to the sulfur
dioxide portion of the program, NSP's emission allowance
allocations for the years 1995-1999 were dramatically reduced. The
Company's capital expenditures include some costs for ensuring
compliance with the Clean Air Act's other emission requirements;
other expenditures may be necessary upon EPA's finalization of
remaining rules. Because NSP is only beginning to implement some
provisions of the Clean Air Act, its overall financial impact is
unknown at this time. Capital expenditures for opacity compliance,
which began in 1995 at certain facilities, are considered in the
capital expenditure commitments disclosed previously. NSP plans to
seek recovery of these expenditures in future rate proceedings.
Several of NSP's operating facilities have asbestos-containing
material, which represents a potential health hazard to people who
come in contact with it. Governmental regulations specify the
required timing and nature of disposal of asbestos-containing
materials. Under such requirements, asbestos not readily accessible
to the environment need not be removed until the facilities
containing the material are demolished. NSP estimates its future
asbestos removal costs will approximate $43 million. Most of these
costs will not need to be incurred until current operating
facilities are demolished, and will be included in the costs of
removal for the facilities.
Environmental liabilities are subject to considerable
uncertainties that affect NSP's ability to estimate its share of
the ultimate costs of remediation and pollution control efforts.
Such uncertainties involve the nature and extent of site
contamination, the extent of required cleanup efforts, varying
costs of alternative cleanup methods and pollution control
technologies, changes in environmental remediation and pollution
control requirements, the potential effect of technological
improvements, the number and financial strength of other
potentially responsible parties at multi-party sites and the
identification of new environmental cleanup sites. NSP has recorded
and/or disclosed its best estimate of expected future environmental
costs and obligations, as discussed previously.
Legal Claims In the normal course of business, NSP is a party to
routine claims and litigation arising from prior and current
operations. NSP is actively defending these matters and has
recorded an estimate of the probable cost of settlement or other
disposition. In July 1993, a natural gas explosion occurred on the
Company's distribution system in St. Paul, Minn. Total damages are
estimated to exceed $1 million. The Company has a self-insured
retention deductible of $1 million, with general liability coverage
of $150 million, which includes coverage for all injuries and
damages. Seventeen lawsuits have been filed, including one suit
with multiple plaintiffs. In April 1995, the National
Transportation Safety Board found little, if any, fault with the
Company's actions or conduct. A trial to decide civil liability and
the parties responsible for the explosion has been scheduled for
February 1997, with the damages portion of the trial scheduled for
six months thereafter. The ultimate costs to the Company are
unknown at this time.
Subsequent Event (Unaudited) On Feb. 19, 1996, the Wisconsin
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 discussed previously. 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 some
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 Wisconsin
Company that it will not choose or proceed with any remediation
options on any portion of the Ashland site until 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
Wisconsin Company's responsibility, if any, for sharing the costs,
the ultimate cost to the Wisconsin Company and the expected timing
of any payments related to the Ashland site is not determinable.
16. Segment Information
Year Ended Dec. 31
(Thousands of dollars) 1995 1994 1993
Utility operating income before
income taxes
Electric $444 687 $399 185 $393 758
Gas 48 340 38 361 38 474
Total operating income before
income taxes $493 027 $437 546 $432 232
Utility depreciation and amortization
Electric $266 231 $252 322 $245 200
Gas 23 953 21 479 19 317
Total depreciation and
amortization $290 184 $273 801 $264 517
Utility capital expenditures
Electric utility $317 750 $303 896 $284 239
Gas utility 37 215 60 183 36 312
Common utility 31 057 22 947 36 285
Total utility capital expenditures $386 022 $387 026 $356 836
Identifiable assets
Electric utility $4 751 650 $4 634 511 $4 543 286
Gas utility 600 738 556 975 521 595
Total identifiable assets 5 352 388 5 191 486 5 064 881
Other corporate assets * 876 197 758 246 522 837
Total assets $6 228 585 $5 949 732 $5 587 718
* Includes equity investments of $185 million in 1995 and $134
million in 1994 in non-regulated energy projects outside of the
United States.
17. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended
(Thousands of dollars) March 31, 1995 June 30, 1995 Sept. 30, 1995 Dec. 31, 1995
Utility operating revenues $661 167 $589 673 $664 976 $652 768
Utility operating income 87 698 68 162 111 592 78 427
Net income 68 190 59 811 88 803 58 991
Earnings available for common stock 64 989 56 686 85 742 55 929
Earnings per average common share $.97 $.84 $1.27 $.82
Dividends declared per common share $.660 $.675 $.675 $.675
Stock prices---high $46 3/4 $47 3/8 $46 7/8 $49 1/2
---low $42 1/2 $42 7/8 $42 1/2 $45 1/8
Quarter Ended
(Thousands of dollars) March 31, 1994 June 30, 1994 Sept. 30, 1994 Dec. 31, 1994
Utility operating revenues $683 462 $581 963 $612 328 $608 794
Utility operating income 85 795 65 526 88 932 68 065*
Net income 65 794 52 808 76 065 48 808*
Earnings available for common stock 62 737 49 751 72 968 45 655*
Earnings per average common share $.94 $.74 $1.09 $.68*
Dividends declared per common share $.645 $.660 $.660 $.660
Stock prices---high $43 7/8 $43 5/8 $43 7/8 $47
---low $40 1/8 $38 3/4 $40 3/8 $41 7/8
* An expense of $8.7 million ($5.1 million net of tax), or 8 cents
per share, was recognized to write off the unamortized deferred
costs associated with adopting SFAS No. 112 (See Note 2.) Such
costs had initially been deferred based on a preliminary decision
to request amortization through rates over future periods.
18. Merger Agreement with Wisconsin Energy Corporation
As previously reported in the Company's Current Report on Form 8-K,
dated April 28, 1995, and filed on May 3, 1995, and Quarterly
Reports on Form 10-Q, the Company and Wisconsin Energy Corporation
(WEC) have entered into an Agreement and Plan of Merger (Merger
Agreement), which provides for a strategic business combination
involving the Company and WEC in a "merger-of-equals" transaction
(the Transaction). See further discussion of the transaction in the
Management's Discussion and Analysis, Factors Affecting Results of
Operations-Proposed Merger section.
Primergy Corporation (Primergy), which will be registered
under the Public Utility Holding Company Act of 1935, as amended,
will be the parent company of both the Company (which, for
regulatory reasons, will reincorporate in Wisconsin) and WEC's
current principal utility subsidiary, Wisconsin Electric Power
Company, which will be renamed "Wisconsin Energy Company." It is
anticipated that, following the Transaction, except for certain gas
distribution properties transferred to the Company, the Wisconsin
Company will be merged into Wisconsin Energy Company and that some
of the Company's other subsidiaries will become direct Primergy
subsidiaries.
As noted above, pursuant to the Transaction, NSP will
reincorporate in Wisconsin. This reincorporation will be
accomplished by the merger of the Company into a new company,
Northern Power Wisconsin Corporation (New NSP), with New NSP being
the surviving corporation and succeeding to the business of the
Company as an operating public utility. Following such merger, a
new WEC subsidiary, WEC Sub Corporation (WEC Sub), will be merged
with and into New NSP, with New NSP being the surviving corporation
and becoming a subsidiary of Primergy. Both New NSP and WEC Sub
were created to effect the Transaction and will not have any
significant operations, assets or liabilities prior to such
mergers. After the Transaction is completed, current common
stockholders of the Company will own shares of Primergy common
stock, and current bondholders and preferred stockholders of the
Company will become investors in New NSP.
SUMMARIZED PRO FORMA FINANCIAL INFORMATION (UNAUDITED)
The following summary of unaudited pro forma financial information
reflects the adjustment of the historical consolidated balance
sheets and statements of income of NSP and WEC to give effect to
the Transaction to form Primergy and a new subsidiary structure.
The unaudited pro forma balance sheet information gives effect to
the Transaction as if it had occurred on Dec. 31, 1995. The
unaudited pro forma income statement information gives effect to
the Transaction as if it had occurred on Jan. 1, 1995. This pro
forma information was prepared from the historical consolidated
financial statements of NSP and WEC on the basis of accounting for
the Transaction as a pooling of interests and should be read in
conjunction with such historical consolidated financial statements
and related notes thereto of NSP and WEC. The following information
is not necessarily indicative of the financial position or
operating results that would have occurred had the Transaction been
consummated on the dates, for which the Transaction is being given
effect, nor is it necessarily indicative of future Primergy
operating results or financial position.
Primergy Information The following summarized Primergy pro forma
financial information reflects the combination of the historical
financial statements of NSP and WEC after giving effect to the
Transaction to form Primergy. A $141 million pro forma adjustment
has been made to conform the presentations of noncurrent deferred
income taxes in the summarized pro forma combined balance sheet
information as a net liability. The pro forma combined earnings per
common share reflect pro forma adjustments to average common shares
outstanding in accordance with the stock conversion provisions of
the Merger Agreement.
Pro Forma
Primergy Pro Forma Financial Information NSP WEC Combined
(Millions of dollars, except per
share amounts)
As of Dec. 31, 1995:
Utility Plant---Net $4 310 $2 911 $7 221
Current Assets 705 531 1 236
Other Assets 1 214 1 119 2 192
Total Assets $6 229 $4 561 $10 649
Common Stockholders' Equity $2 028 $1 871 $3 899
Preferred Stockholders' Equity 240 30 270
Long-Term Debt 1 542 1 368 2 910
Total Capitalization 3 810 3 269 7 079
Current Liabilities 992 436 1 428
Other Liabilities 1 427 856 2 142
Total Equity & Liabilities $6 229 $4 561 $10 649
For the Year Ended Dec. 31, 1995:
Utility Operating Revenues $2 569 $1 770 $4 339
Utility Operating Income $346 $329 $675
Net Income, after Preferred
Dividend Requirements $263 $234 $497
Earnings per Common Share:
As reported $3.91 $2.13
Using NSP Equivalent Shares* $3.69
Using Primergy Shares $2.27
* Represents the pro forma equivalent of one share of NSP Common
Stock calculated by multiplying the pro forma information by the
conversion ratio of 1.626 shares of Primergy Common Stock for each
share of NSP Common Stock.
New NSP Information The following summarized New NSP pro forma
financial information reflects the adjustment of the historical
financial statements of NSP to give effect to the Transaction,
including the merger of the Wisconsin Company into Wisconsin Energy
Company and the transfer of ownership of all of the other current
NSP subsidiaries to Primergy. The transfer of certain Wisconsin
Company gas distribution properties to New NSP, which is
anticipated as part of the merger, has not been reflected in the
pro forma amounts due to immateriality.
Merger
Divestitures, Pro Forma
New NSP Pro Forma Financial Information NSP Net New NSP
(Millions of dollars)
As of Dec. 31, 1995:
Utility Plant---Net $4 310 ($692) $3 618
Current Assets 705 (170) 535
Other Assets 1 214 (531) 683
Total Assets $6 229 ($1 393) $4 836
Common Stockholders' Equity $2 028 ($706) $1 322
Preferred Stockholders' Equity 240 240
Long-Term Debt 1 542 (356) 1 186
Total Capitalization 3 810 (1 062) 2 748
Current Liabilities 992 (139) 853
Other Liabilities 1 427 (192) 1 235
Total Equity & Liabilities $6 229 ($1 393) $4 836
For the Year Ended Dec. 31, 1995:
Utility Operating Revenues $2 569 ($213) $2 356
Utility Operating Income $346 ($62) $284
Net Income, after Preferred
Dividend Requirements $263 ($73) $190
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
During 1995 there were no disagreements with the Company's
independent public accountants on accounting procedures or
accounting and financial disclosures. As discussed in the
Company's Current Report on Form 8-K filed Dec. 16, 1994, on
Dec. 14, 1994, the Company's Board of Directors approved the
appointment of the accounting firm of Price Waterhouse LLP as
independent accountants for the Registrant beginning in fiscal
year 1995, subject to ratification by the shareholders. On
Sept. 13, 1995, the Company's shareholders ratified the
appointment of Price Waterhouse LLP as the Company's independent
accountants for 1995.
PART III
Item 10 - Directors and Executive Officers of the Registrant
Information required under this Item with respect to
directors is set forth in the Registrant's 1996 Proxy Statement
for its Annual Meeting of Shareholders to be held April 24,
1996, on pages 3 through 6 under the caption "Election of
Directors," which is incorporated herein by reference.
Information with respect to Executive Officers is included under
the caption "Executive Officers" in Item 1 of this report, and
is incorporated herein by reference.
Item 11 - Executive Compensation
Information required under this Item is set forth in the
Registrant's 1996 Proxy Statement for its Annual Meeting of
Shareholders to be held April 24, 1996, on pages 7 through 17
under the caption "Compensation of Executive Officers," which is
incorporated herein by reference.
Item 12 - Security Ownership of Certain Beneficial Owners and
Management
Information required under this item is set forth in the
Registrant's 1996 Proxy Statement for its Annual Meeting of
Shareholders to be held April 24, 1996, on page 6 under the
caption "Share Ownership of Directors, Nominees and Named
Executive Officers," which is incorporated herein by reference.
Item 13 - Certain Relationships and Related Transactions
Information required under this Item is set forth in the
Registrant's 1996 Proxy Statement for its Annual Meeting of
Shareholders to be held April 24, 1996, on pages 3 through 4
under the captions "Class I - Nominees for Terms expiring in
1999," "Class II - Nominee for Term expiring in 1997," "Class II
- - Directors Whose Terms Expire in 1997," "Class III - Directors
Whose Terms Expire in 1998," which is incorporated herein by
reference.
PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports on
Form 8-K
(a) 1. Financial Statements
Included in Part II of this report:
Page
Report of Independent Accountants for the year ended
Dec. 31, 1995. 62
Independent Auditors' Report for the years
ended Dec. 31, 1994 and 1993. 63
Consolidated Statements of Income for the three years
ended Dec. 31, 1995. 64
Consolidated Statements of Cash Flows for the three
years ended Dec. 31, 1995. 65
Consolidated Balance Sheets, Dec. 31, 1995
and 1994. 66
Consolidated Statements of Changes in Common
Stockholders' Equity for the three years
ended Dec. 31, 1995. 67
Consolidated Statements of Capitalization,
Dec. 31, 1995 and 1994. 68
Notes to Financial Statements. 70
(a) 2. Financial Statement Schedules
Schedules are omitted because of the absence of the
conditions under which they are required or because the
information required is included in the financial
statements or the notes.
(a) 3. Exhibits
* Indicates incorporation by reference
2.01* Amended and Restated Agreement and Plan of
Merger, dated as of April 28, 1995, as amended
and restated as of July 26, 1995, by and among
Northern States Power Company, Wisconsin Energy
Corporation, Northern Power Wisconsin Corp. and
WEC Sub. Corp. (Exhibit (2)-1 to Northern Power
Wisconsin Corp.'s Registration Statement
on Form S-4 filed on Aug. 7, 1995, File No. 33-
61619-01).
2.02* WEC Stock Option Agreement, dated as of April
28, 1995, by and among Northern States Power
Company and Wisconsin Energy Corporation
(Exhibit (2)-2 to Form 8-K dated April 28,
1995, File No. 1- 3034).
2.03* NSP Stock Option Agreement, dated as of April
28, 1995, by and among Wisconsin Energy
Corporation and Northern States Power Company
(Exhibit (2)-3 to Form 8-K dated April 28, 1995,
File No. 1-3034).
2.04* Committees of the Board of Directors of Primergy
Corporation, Exhibit 7.13 to the Agreement and
Plan of Merger (Exhibit (2)-4 to Form 8-K dated
April 28, 1995, File No. 1-3034).
2.05* Form of Employment Agreement of James J. Howard,
Exhibit 7.15.1 to the Agreement and Plan of
Merger (Exhibit (2)-5 to Form 8-K dated April
28, 1995, File No. 1-3034).
2.06* Form of Employment Agreement with Richard A.
Abdoo, Exhibit 7.15.2 to the Agreement and Plan
of Merger (Exhibit (2)-6 to Form 8-K dated April
28, 1995, File No. 1-3034).
2.07* Form of Amended and Restated Articles of
Incorporation of Northern Power Wisconsin Corp.,
Exhibit 7.20 (b) to the Agreement and Plan of
Merger (Exhibit (2)-7 to Form 8-K dated April
28, 1995, File No. 1-3034).
2.08* Form of NSP Senior Executive Severance Policy,
Exhibit 7.10 (a) to the Amended and Restated
Agreement and Plan of Merger, dated as of April
28, 1995, as amended and restated as of July 26,
1995, by and among Northern States Power
Company, Wisconsin Energy Corporation, Northern
Power Wisconsin Corp. and WEC Sub. Corp.
(Exhibit (2) - 1 to Northern Power Wisconsin
Corp.'s Registration on Form S-4 filed
Aug. 7, 1995, File No. 33-61619-01).
3.01* Restated Articles of Incorporation of the
Company and Amendments, effective as of April 2,
1992. (Exhibit 3.01 to Form 10-Q for the
quarter ended March 31, 1992, File No. 1-3034).
3.02* Bylaws of the Company as amended Jan. 22, 1992.
(Exhibit 3.02 to Form 10-K for the year 1991,
File No. 1-3034).
4.01* Trust Indenture, dated Feb. 1, 1937, from the
Company to Harris Trust and Savings Bank, as
Trustee. (Exhibit B-7 to File No. 2-5290).
4.02* Supplemental and Restated Trust Indenture, dated
May 1, 1988, from the Company to Harris Trust
and Savings Bank, as Trustee. (Exhibit 4.02 to
Form 10-K for the year 1988, File No. 1-3034).
Supplemental Indenture between the Company and
said Trustee, supplemental to Exhibit 4.01,
dated as follows:
4.03* Jun. 1, 1942 (Exhibit B-8 to File No. 2-97667).
4.04* Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290).
4.05* Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924).
4.06* Jul. 1, 1948 (Exhibit 7.05 to File No. 2-7549).
4.07* Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047).
4.08* Jun. 1, 1952 (Exhibit 4.08 to File No. 2-9631).
4.09* Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216).
4.10* Sep. 1, 1956 (Exhibit 2.09 to File No. 2-13463).
4.11* Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156).
4.12* Jul. 1, 1958 (Exhibit 4.12 to File No. 2-15220).
4.13* Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355).
4.14* Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282).
4.15* Jun. 1, 1962 (Exhibit 2.14 to File No. 2-21601).
4.16* Sep. 1, 1963 (Exhibit 4.16 to File No. 2-22476).
4.17* Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338).
4.18* Jun. 1, 1967 (Exhibit 2.17 to File No. 2-27117).
4.19* Oct. 1, 1967 (Exhibit 2.01R to File No.
2-28447).
4.20* May 1, 1968 (Exhibit 2.01S to File No. 2-34250).
4.21* Oct. 1, 1969 (Exhibit 2.01T to File No.
2-36693).
4.22* Feb. 1, 1971 (Exhibit 2.01U to File No.
2-39144).
4.23* May 1, 1971 (Exhibit 2.01V to File No. 2-39815).
4.24* Feb. 1, 1972 (Exhibit 2.01W to File No.
2-42598).
4.25* Jan. 1, 1973 (Exhibit 2.01X to File No.
2-46434).
4.26* Jan. 1, 1974 (Exhibit 2.01Y to File No.
2-53235).
4.27* Sep. 1, 1974 (Exhibit 2.01Z to File No.
2-53235).
4.28* Apr. 1, 1975 (Exhibit 4.01AA to File No.
2-71259).
4.29* May 1, 1975 (Exhibit 4.01BB to File No.
2-71259).
4.30* Mar. 1, 1976 (Exhibit 4.01CC to File No.
2-71259).
4.31* Jun. 1, 1981 (Exhibit 4.01DD to File No.
2-71259).
4.32* Dec. 1, 1981 (Exhibit 4.01EE to File No.
2-83364).
4.33* May 1, 1983 (Exhibit 4.01FF to File No.
2-97667).
4.34* Dec. 1, 1983 (Exhibit 4.01GG to File No.
2-97667).
4.35* Sep. 1, 1984 (Exhibit 4.01HH to File No.
2-97667).
4.36* Dec. 1, 1984 (Exhibit 4.01II to File No.
2-97667).
4.37* May 1, 1985 (Exhibit 4.36 to Form 10-K for
the year 1985, File No. 1-3034).
4.38* Sep. 1, 1985 (Exhibit 4.37 to Form 10-K for
the year 1985, File No. 1-3034).
4.39* Jul. 1, 1989 (Exhibit 4.01 to Form 8-K
dated July 7, 1989, File No. 1-3034).
4.40* Jun. 1, 1990 (Exhibit 4.01 to Form 8-K
dated June 1, 1990, File No. 1-3034).
4.41* Oct. 1, 1992 (Exhibit 4.01 to Form 8-K
dated Oct. 13, 1992, File No. 1-3034).
4.42* April 1, 1993 (Exhibit 4.01 to Form 8-K dated
March 30, 1993, File No. 1-3034).
4.43* Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated
Dec. 7, 1993, File No. 1-3034).
4.44* Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated
Feb. 10, 1994, File No. 1-3034).
4.45* Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated
Oct. 5, 1994, File No. 1-3034).
4.46* Jun. 1, 1995 (Exhibit 4.01 to Form 8-K dated
June 28, 1995, File No. 1-3034).
4.47* Trust Indenture, dated April 1, 1947, from the
Wisconsin Company to Firstar Trust Company
(formerly First Wisconsin Trust Company), as
Trustee. (Exhibit 7.01 to File No. 2-6982).
Supplemental Indentures between the Wisconsin
Company and said Trustee, supplemental to
Exhibit 4.45 dated as follows:
4.48* Mar. 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.49* Jun. 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.50* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.51* Dec. 1, 1969 (Exhibit 2.03E to File No.
2-36693).
4.52* Sep. 1, 1973 (Exhibit 2.01F to File No.
2-48805).
4.53* Feb. 1, 1982 (Exhibit 4.01G to File No.
2-76146).
4.54* Mar. 1, 1982 (Exhibit 4.39 to Form 10-K for the
year 1982, File No. 10-3140).
4.55* Jun. 1, 1986 (Exhibit 4.01I to File No.
33-6269).
4.56* Mar. 1, 1988 (Exhibit 4.01J to File No.
33-20415).
4.57* Supplemental and Restated Trust Indenture dated
March 1, 1991, from the Wisconsin Company to
Firstar Trust Company (formerly First Wisconsin
Trust Company), as Trustee. (Exhibit 4.01K to
File No. 33-39831)
4.58* Apr. 1, 1991 (Exhibit 4.01L to File No.
33-39831).
4.59* Mar. 1, 1993 (Exhibit 4.01 to Form 8-K dated
March 4, 1993, File No. 10-3140).
4.60* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated
September 21, 1993, File No. 10-3140).
4.61* NSP Employee Stock Ownership Plan. (Exhibit
4.60 to Form 10-K for the year 1994, File No.
1-3034).
10.01* Mid-continent Area Power Pool (MAPP) Agreement,
dated March 31, 1972, with amendments in 1994,
between the local power suppliers in the North
Central States area. (Exhibit 10.01 to Form
10-K for the year 1994, File No. 1-3034).
10.02* Facilities agreement, dated July 21, 1976,
between the Company and the Manitoba Hydro-
Electric Board relating to the interconnection
of the 500 Kv Line. (Exhibit 5.06I to File No.
2-54310).
10.03* Transactions agreement, dated July 21, 1976,
between the Company and the Manitoba Hydro-
Electric Board relating to the interconnection
of the 500 Kv Line. (Exhibit 5.06J to File No.
2-54310).
10.04* Coordinating agreement, dated July 21, 1976,
between the Company and the Manitoba Hydro-
Electric Board relating to the interconnection
of the 500 Kv Line. (Exhibit 5.06K to File No.
2-54310).
10.05* Ownership and Operating Agreement, dated March
11, 1982, between the Company, Southern
Minnesota Municipal Power Agency and United
Minnesota Municipal Power Agency concerning
Sherburne County Generating Unit No. 3.
(Exhibit 10.01 to Form 10-Q for the quarter
ended Sept. 30, 1994, File No. 1-3034).
10.06* Transmission agreement, dated April 27, 1982,
and Supplement No. 1, dated July 20, 1982,
between the Company and Southern Minnesota
Municipal Power Agency. (Exhibit 10.02 to Form
10-Q for the quarter ended Sept. 30, 1994, File
No. 1-3034).
10.07* Power agreement, dated June 14, 1984, between
the Company and the Manitoba Hydro-Electric
Board, extending the agreement scheduled to
terminate on April 30, 1993, to April 30, 2005.
(Exhibit 10.03 to Form 10-Q for the quarter
ended Sept. 30, 1994, File No. 1-3034).
10.08* Power Agreement, dated August 1988, between the
Company and Minnkota Power Company. (Exhibit
10.08 to Form 10-K for the year 1988, File No.
1-3034).
10.09* Energy Supply Agreement, dated Oct. 26, 1993,
between the Company and Liberty Paper, Inc.
(LPI), relating to the supply of steam and
electricity to the LPI container-board facility
in Becker, MN. (Exhibit 10.09 to Form 10-K for
the year 1993, File No. 1-3034).
Executive Compensation Arrangements and Benefit Plans
Covering Executive Officers
10.10* Executive Long-Term Incentive Award Stock Plan.
(Exhibit 10.10 to Form 10-K for 1988, File No.
1-3034).
10.11* Terms and Conditions of Employment - James J
Howard, President and Chief Executive Officer,
effective Feb. 1, 1987, as amended. (Agreement
filed as Exhibit 10.11 to Form 10-K for the year
1986, File No. 1-3034, Acknowledgement of
Amendment to Terms and Conditions of Employment
of James J. Howard filed as Exhibit 10.01 to
Form 10-Q for the quarter ended June 30, 1995,
File No. 1-3034).
10.12* NSP Severance Plan. (Exhibit 10.12 to Form
10-K for the year 1994, File No. 1-3034).
10.13* NSP Deferred Compensation Plan amended effective
Jan. 1, 1993. (Exhibit 10.16 to Form 10-K for
the year 1993, File No. 1-3034).
10.14 Annual Executive Incentive Plan for 1996.
12.01 Statement of Computation of Ratio of Earnings to
Fixed Charges.
16.01* Independent Auditors' Letter re: Change in
Certifying Accountant (Exhibit 16.01 to Form 8-K
dated Dec. 13, 1994, File No. 1-3034).
21.01 Subsidiaries of the Registrant.
23.01 Consent of Independent Accountants - Price
Waterhouse LLP, Minneapolis, MN.
23.02 Independent Auditor's Consent - Deloitte
& Touche LLP.
23.03 Consent of Independent Accountants - Price
Waterhouse LLP, Milwaukee, WI.
27.01 Financial Data Schedule.
99.01* Press Release, dated May 1, 1995, of NSP
(Exhibit (99)-1 to Form 8-K dated April 28,
1995, File No. 1-3034).
99.02 Unaudited Pro Forma Combined Condensed Balance
Sheets for Primergy Corporation at Dec. 31, 1995
and Unaudited Pro Forma Combined Condensed
Statements of Income for the three years ended
Dec. 31, 1995.
99.03 Unaudited Pro Forma Condensed Balance Sheet for
New NSP at Dec. 31, 1995 and Unaudited Pro Forma
Condensed Statements of Income for the three
years ended Dec. 31, 1995.
99.04* Audited Financial Statements of Wisconsin Energy
Corporation. (Item 8 of Wisconsin Energy
Corporation's Annual Report on Form 10-K for the
fiscal year ended Dec. 31, 1995, File No. 1-
9057).
(b) Reports on Form 8-K. The following reports on Form 8-K
were filed either during the three months ended Dec. 31,
1995, or between Dec. 31, 1995 and the date of this report.
Jan. 18, 1996 (Filed Jan. 18, 1996) - Item 5. Other
Events. Re: Release of 1995 financial results of NRG
Energy, Inc., a wholly owned subsidiary of the Company.
March 1, 1996 (Filed March 1, 1996) - Item 5. Other
Events. Re: Disclosure of new category of electric
commercial and industrial customers, and electric and gas
operating statistics for 1995.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this annual report to be signed on its behalf by the
undersigned, thereunto duly authorized.
NORTHERN STATES POWER COMPANY
March 27, 1996
(E J McIntyre)
E J McIntyre
Vice President and Chief
Financial Officer
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report signed below by the following persons on
behalf of the registrant and in the capacities and on the date
indicated.
(James J Howard) (E J McIntyre)
James J Howard E J McIntyre
Chairman of the Board, President Vice President and Chief
and Chief Executive Officer Financial Officer (Principal
(Principal Executive Officer) Financial Officer
(Roger D Sandeen) (H Lyman Bretting)
Roger D Sandeen H Lyman Bretting
Vice President, Controller and Chief Director
Information Officer
(Principal Accounting Officer)
(David A Christensen) (W John Driscoll)
David A Christensen W John Driscoll
Director Director
(Dale L Haakenstad) (Allen F Jacobson)
Dale L Haakenstad Allen F Jacobson
Director Director
(Richard M Kovacevich) (Douglas W Leatherdale)
Richard M Kovacevich Douglas W Leatherdale
Director Director
(John E Pearson) (G M Pieschel)
John E Pearson G M Pieschel
Director Director
(Margaret R Preska) (A Patricia Sampson)
Margaret R Preska A Patricia Sampson
Director Director
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
DT 10.14 Annual Executive Incentive Plan for 1996
DT 12.01 Statement of Computation of
Ratio of Earnings to Fixed
Charges
DT 21.01 Subsidiaries of the Registrant
DT 23.01 Consent of Independent Accountants -
Price Waterhouse LLP, Minneapolis, MN
DT 23.02 Independent Auditor's Consent -
Deloitte & Touche LLP
DT 23.03 Consent of Independent Accountants -
Price Waterhouse LLP, Milwaukee, WI
DT 27.01 Financial Data Schedule
DT 99.02 Unaudited Pro Forma Combined Condensed
Balance Sheets for Primergy Corporation
at Dec. 31, 1995 and Unaudited Pro
Forma Combined Condensed Statements
of Income for the three years ended
Dec. 31, 1995
DT 99.03 Unaudited Pro Forma Condensed Balance
Sheet for New NSP at Dec. 31, 1995 and
Unaudited Pro Forma Condensed
Statements of Income for the three
years ended Dec. 31, 1995
DT = Filed electronically with this direct transmission.