NORTHERN STATES POWER CO /MN/ - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

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, 1996

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
Trust Originated Preferred
Securities 7 7/8% 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 requirements for the past 90 days.

Yes X No .
_____ _____

As of March 15, 1997, the aggregate market value of the voting common
stock held by non-affiliates of the Registrant was $3,257,505,248 and
there were 69,063,712 shares of common stock outstanding, $2.50 par
value.

Documents Incorporated by Reference
None

Index
Page No.
PART I
Item 1 - Business 1
PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION 1
UTILITY REGULATION AND REVENUES
General 5
Revenues 6
General Rate Filings 6
Ratemaking Principals in Minnesota and Wisconsin 7
Fuel and Purchased Gas Adjustment Clauses in Effect 8
Resource Adjustment Clauses in Effect 9
Rate Matters by Jurisdiction 9
ELECTRIC UTILITY OPERATIONS
Competition 14
Capability and Demand 17
Energy Sources 20
Fuel Supply and Costs 20
Nuclear Power Plants - Licensing, Operation and Waste Disposal 22
Electric Operating Statistics 26
GAS UTILITY OPERATIONS
Competition 26
Business Standards 27
Customer Growth and Expansion 28
Capability and Demand 28
Gas Supply and Costs 29
Viking Gas Transmission Company 30
Gas Operating Statistics 32
NON-REGULATED SUBSIDIARIES
NRG Energy, Inc. 33
Cenerprise, Inc. 37
Eloigne Company 37
Seren Innovations, Inc. 38
Non-Regulated Business Information 39
ENVIRONMENTAL MATTERS 40
CAPITAL SPENDING AND FINANCING 44
EMPLOYEES AND EMPLOYEE BENEFITS 44
EXECUTIVE OFFICERS 46

Item 2 - Properties 48
Item 3 - Legal Proceedings 49
Item 4 - Submission of Matters to a Vote of Security Holders 50

PART II
Item 5 - Market for Registrant's Common Equity and Related
Stockholder Matters 50
Item 6 - Selected Financial Data 51
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations 52
Item 8 - Financial Statements and Supplementary Data 67
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 98

PART III
Item 10 - Directors and Executive Officers of the Registrant 98
Item 11 - Executive Compensation 101
Item 12 - Security Ownership of Certain Beneficial Owners and Management 108
Item 13 - Certain Relationships and Related Transactions 109

PART IV
Item 14 - Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 109

SIGNATURES 115

Exhibit (Excerpt)
Statement Pursuant to Private Securities Litigation Reform Act of 1995 116
Unaudited Pro Forma Financial Information 118

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., a Delaware
corporation (NRG). The Company also has several other subsidiaries, including
Cenerprise, Inc. (formerly known as Cenergy, Inc.), a Minnesota corporation;
Viking Gas Transmission Company, a Delaware corporation (Viking); and Eloigne
Company, a Minnesota corporation (Eloigne). (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 152 communities within this area.
Viking is a regulated natural gas transmission company that operates a 500-
mile interstate natural gas pipeline. NRG operates several non-regulated
energy businesses and is an equity investor in several non-regulated energy
affiliates throughout the world.

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 1996, about 62 percent of NSP's electric retail revenue
was derived from sales in the Minneapolis-St. Paul metropolitan area and about
56 percent of retail gas revenue came from sales in the St. Paul metropolitan
area. (For business segment information, see Note 15 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 13 and 14 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.)

A significant portion of NSP's earnings comes from non-regulated
operations. The non-regulated projects in which NRG has invested carry a
higher level of risk than NSP's traditional utility businesses. (See
Management's Discussion and Analysis under Item 7 herein, for further
discussion of this matter.)

Except for the historical information contained herein, the matters
discussed in this Form 10-K, including the statements below regarding the
anticipated impact of the proposed merger with Wisconsin Energy Corporation,
are forward looking statements that are subjects to certain risks,
uncertainties and assumptions. Such forward-looking statements are intended
to be identified in this document by the words "anticipate," "estimate,"
"expect," "objective," "possible," "potential" and similar expressions.
Actual results may vary materially. Factors that could cause actual results
to differ materially include, but are not limited to: general economic
conditions, including their impact on capital expenditures; business
conditions in the energy industry; competitive factors; unusual weather,
changes in federal; or state legislation; regulatory decisions regarding the
proposed combination of NSP and WEC, and the other risk factors listed from
time to time by the Company in reports filed with the Securities and Exchange
Commission (SEC), including Exhibit 99.01 to this report on Form 10-K.

PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION

Description of the Merger Transaction

As initially announced in the Company's Current Report on Form 8-K dated
April 28, 1995 and filed on May 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 sub-
sidiary of WEC (WEC Sub), have entered into an Amended and Restated Agreement
and Plan of Merger, dated as of April 28, 1995, as amended and restated as of
July 26, 1995 (the Merger Agreement), which provides for a business
combination of NSP and WEC in a "merger-of-equals" transaction (the Merger
Transaction). On Sept. 13, 1995, the merger plan was approved by more than
95 percent of the respective shareholders of the Company and WEC voting at
their respective shareholder meetings. The agreement to merge is subject to
a number of conditions, including approval by applicable regulatory
authorities. NSP continues to work with WEC to complete the merger. However,
since numerous conditions are beyond its control, NSP cannot predict whether
the merger will occur. 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 17 of Notes to
Financial Statements and pro forma financial statements included in exhibits
listed in Item 14.)

In the Merger Transaction, Primergy Corporation (Primergy), which will
be registered under the Public Utility Holding Company Act of 1935, as amended
(PUHCA), 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 (WEPCO), which will be renamed
"Wisconsin Energy Company". It is anticipated that, at the time of the
Transaction, except for certain gas distribution properties transferred to the
Company, the Wisconsin Company will be merged into Wisconsin Energy Company
and that most of the Company's other subsidiaries will become direct Primergy
subsidiaries.

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), both of which were 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 is to be merged with
and into New NSP and immediately thereafter WEC Sub will be merged with and
into New NSP, with New NSP being the surviving corporation. Each outstanding
share of the 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 have resulted 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 $2.76 per
share annually, and WEC's annual dividend rate is currently $1.52 per share.
Based on the 1.626 stock exchange ratio and the Company's current dividend
rate, the pro forma dividend rate for Primergy Common Stock would be $1.70 per
share as of Dec. 31, 1996. However, the amount, declaration, and timing of
dividends on Primergy Common Stock will be a business decision to be made by
the Primergy Board of Directors from time to time based upon the results of
operations and financial condition of Primergy and its subsidiaries and such
other business considerations as the Primergy Board considers relevant in
accordance with applicable laws.

Merger Consummation Conditions

The Merger Transaction is subject to numerous closing conditions,
including, without limitation, the receipt of all necessary governmental
approvals without materially adverse terms and the making of all necessary
governmental filings, including approvals of state utility regulators in
Wisconsin, Minnesota and certain other states, the approval of the Federal
Energy Regulatory Commission (FERC), the Securities and Exchange Commission
(SEC), the Nuclear Regulatory Commission (NRC), and the filing of the
requisite notification with the Federal Trade Commission and the Department
of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as
amended, and the expiration of the applicable waiting period thereunder. (See
discussion of the utility regulation proceedings under the caption "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 the Company and WEC with the SEC with
respect to the Primergy Common Stock to be issued in the Merger
Transaction and New NSP Preferred Stock became effective.

- 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.

- 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 made the following filings as part of the
regulatory approval process for the Merger Transaction:

- NSP and WEC filed for SEC approval of the registration of Primergy
under PUHCA.

- Notification under the Hart-Scott-Rodino Antitrust Improvements Act of
1976, as amended, was filed with the United States Department of
Justice.

In early 1997, the United States Department of Justice served its second
request for information and documents. NSP and WEC anticipate responding to
the second request in March 1997.

As noted above, completion of the merger is subject to numerous
conditions under the Merger Agreement that, unless waived by the affected
party, must be met, including but not limited to the prior receipt of all
necessary regulatory approvals without imposition of materially adverse terms;
the accuracy of each party's representations and warranties in the Merger
Agreement at closing, other than representations and warranties whose
inaccuracy does not result in a material adverse effect on the business,
assets, financial conditions, results of operations or prospects of such party
and its subsidiaries taken as a whole; and no such material adverse effect
having occurred, or being reasonably likely to occur, with respect to either
party at the time of the closing. NSP continues to work with WEC to complete
the merger. However, since numerous conditions are beyond its control, NSP
cannot state whether all necessary conditions for completion of the merger
will occur.

The Merger Agreement

The Merger Agreement contains certain covenants of the parties pending
the consummation of the Merger Transaction. Generally, the parties must carry
on their businesses in the ordinary course consistent with past practice, may
not increase dividends on common stock beyond specified levels, and may not
issue capital stock beyond certain limits. The Merger Agreement also contains
restrictions on, among other things, charter and bylaw amendments, capital
expenditures, acquisitions, dispositions, incurrence of indebtedness, certain
increases in employee compensation and benefits, and affiliate transactions.

In accordance with the Merger Agreement, upon the consummation of the
Merger Transaction, James J. Howard, Chairman, President, and Chief Executive
Officer of the 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 all regulatory
approvals without any materially adverse terms by any of the parties, have
been or are capable of being fulfilled at 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 made in the Merger Agreement as of the date thereof which
breaches, individually or in the aggregate, would result in a material adverse
effect on the breaching party and which is not cured within 20 days after
notice; (5) by a non-breaching party if there occur breaches of specified
covenants or material breaches of any covenant or agreement which are not
cured within 20 days after notice; (6) by either party if the Board of Direc-
tors 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 Agreement becomes terminable by one party as a
result of the other party's breach or as a result of the other party becoming
the subject of a third-party proposal for a business combination. Any party
whose option becomes exercisable (the Exercising Party) may request the other
party to repurchase from it all or any portion of the Exercising Party's
option at the price specified in the Stock Option Agreements.

Results of the Merger Transaction

Assuming the merger is completed, a transition to a new organization
would begin. At the time that the Merger Agreement was signed, anticipated
cost savings of the new organization (compared with the continued independent
operation of NSP and WEC) were estimated to be approximately $2 billion over
a 10-year period, net of transaction costs (about $30 million) and costs to
achieve the merger savings (about $122 million). The actual realization of
these savings will be dependent on numerous factors. It is anticipated that
the proposed merger will allow the companies to implement a modest reduction
in electric 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. (See "Utility Regulation and
Revenues - Rate Matters by Jurisdictions" herein for a discussion of the
proceedings.)

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. In addition, the companies
agreed to provide a four-year freeze in wholesale electric rates effective
once the merger is completed.

The Company has proposed a freeze through 1998 for retail natural gas
rates in its Minnesota jurisdiction and a 1.25 percent gas rate reduction
along with a four-year freeze in its North Dakota jurisdiction. In addition,
any net purchased gas cost savings 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.

The total savings anticipated 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. The Company also proposes to continue to apply
the resource adjustment clauses to recover conservation program costs, and the
fuel and purchased gas adjustment clauses to recover electric fuel and gas
purchased costs respectively. (See "Utility Regulation and Revenues" for
discussion of these clauses.) 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 state
utility regulators 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. Also,
regulatory authorities may require the use of an independent transmission
system operator (ISO) or divestiture of certain transmission and/or generation
assets. NSP currently cannot determine if such divestitures would be required
by regulators. In addition, Wisconsin state law limits the total assets of
non-utility affiliates of Primergy, which, depending on interpretation of the
law, may limit growth of non-regulated operations.

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 within the state of Minnesota when the asset value is in excess of
$100,000, mergers with other utilities, and
transactions between the regulated Company and its 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. NSP strives 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 1996 utility operating revenues, excluding intersystem non-firm electric
sales to other utilities of $70 million and miscellaneous revenues of $77
million, were subject to regulatory jurisdiction as follows:

Percent of
Authorized Return Total
on Common Equity Revenues
@ Dec. 31, 1996 (Electric
Electric Gas & Gas)

Retail:
Minnesota Public Utilities
Commission 11.47% 11.47% 74.8%
Public Service Commission
of Wisconsin 11.3 11.3 14.4
North Dakota Public
Service Commission 11.5 12.0** 5.5
South Dakota Public
Utilities Commission * 3.0
Michigan Public Service
Commission 12.25 14.5 0.5

Sales for Resale - Wholesale,
Viking Gas and Interstate
Transmission: Federal Energy
Regulatory Commission * * 1.8

Total 100.0%

* Settlement proceeding, based upon revenue levels granted with no specified
return.
** Reflects ROE underlying the August, 1996 rate settlement.

General Rate Filings

General rate increases (other than fuel and resource adjustment rate
changes) requested and granted in the last five years from various
jurisdictions were as follows (note that amounts represent annual increases
(decreases) effective in those years);

Annual Increase/(Decrease)
Year Requested Granted
(Millions of dollars)

1992 ----- ----
1993 166.6 101.5
1994 (1.0) (1.0)
1995 (0.8) (0.8)
1996 2.2 (2.8)

The following table summarizes the status of general rate increases
(decreases) for rates effective in 1996.

Annual Increase/(Decrease)
Requested Granted Status
(Millions of dollars)
Electric:
Wisconsin-Retail No Change ($4.8) Order Issued
October 6, 1995

Gas:
Wisconsin-Retail $2.7 2.5 Order Issued
December 21, 1995
North Dakota-Retail (0.5) (0.5) Order Issued
August 7, 1996

Total 1996 Rate
Programs 2.2 (2.8)

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
common 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.

Minnesota law allows Construction Work in Progress (CWIP) in a utility's
rate base. The MPUC has generally included Allowance for Funds Used During
Construction (AFC) in revenue requirements for rate proceedings. However,
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 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. For the
eight Wisconsin Company customers on the W-1 wholesale rate, the wholesale
electric fuel adjustment factor is calculated for the current month based on
estimated fuel costs for that month. The estimated fuel cost is adjusted to
actual the following month.

In 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 on a continuing
basis. The Company is obligated by legislative mandate to purchase 425 Mw of
wind generated energy and 125 Mw of farm-grown closed-loop biomass generated
energy by 2002. See Note 14 to the Financial Statements under Item 8 for a
discussion of the Company's legislative resource commitments.

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 demand costs for both sales and purchased power and
transmission wheeling expenses, 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 PGA factors used to bill 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. On September 3, 1996 the MPUC allowed full recovery of gas costs
in response to the filing for the year ended June 30, 1995. The MPUC's
determination regarding the filing for the year ended June 30, 1996 is
pending. Approval is anticipated in the latter half of 1997.

In August 1995, the MPUC initiated an investigation -- an industry-wide
proceeding which was open to participation from any interested party -- to
examine whether the PGA mechanism was 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 filed comments supporting the continued use of the PGA, but urging the
use of performance-based PGA mechanisms. The MPUC issued an order November
18, 1996, concluding its investigation and determining that the PGA mechanism
as currently in effect should be retained at this time.

The PSCW conducted a generic hearing in March 1996 to consider
alternative incentive-based gas cost recovery mechanisms to replace the
current PGA clause. In its November 5, 1996 order, the PSCW issued general
guidelines for incentive based gas cost recovery mechanism as well as
"modified one-for-one" gas cost recovery mechanisms. Under a modified one-
for-one gas recovery mechanism the allowable gas commodity cost recovery would
be based on a benchmark index, which in turn is based on the market price of
gas. The allowable cost recovery of the remaining components of the cost of
gas (for example, interstate pipeline transportation) would be based on actual
costs incurred, as is now the case with the PGA clause. The order required
all major gas utilities in Wisconsin to file a proposal to replace their
current purchased gas adjustment clause, but allowed individual utilities
discretion in choosing which type of gas cost recovery mechanism to file. The
Company plans to file a proposal for a modified one-for-one gas recovery
mechanism by July 1, 1997, according to the schedule established by the PSCW.

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. For 1997
the Gas Cost Recovery Factor is in place; however, due to the pending merger
with WEC, the Wisconsin Company has received approval of a waiver of the Power
Supply Cost Recovery Factor. The waiver has been challenged by the Michigan
Attorney General.

Viking is a transportation-only interstate pipeline and provides no sales
services. Thus, Viking has no need for a PGA mechanism. Natural gas fuel for
Viking's compressor station operations is provided by transportation service
customers.

Resource Adjustment Clauses in Effect

In 1995, the MPUC approved the implementation of an annual recovery
mechanism for deferred electric and gas conservation and energy management
program expenditures, including amortization of program costs, reimbursement
of a portion of electric margins lost due to conservation activity, and
returns on capital used to finance conservation programs. 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. A surcharge
to customer's bills is included as a line item entitled "resource adjustment."
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 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. These conservation cost recovery
changes are intended to avoid a significant delay between the time when costs
are incurred and when they are recovered in rates.

Rate Matters by Jurisdiction

Minnesota Public Utilities Commission (MPUC)

In 1991, the Minnesota legislature 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. The MPUC may approve a utility's use of the rate adjustment clause
for billing customers if certain conservation expenditure levels are met.
During 1994, the Company filed a request with the MPUC 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 1995, as part of a response to 1994 Minnesota legislation related to
spent fuel storage at the Prairie Island nuclear plant, the MPUC approved the
Company's filing for 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. As a result, the
Low Income Discount Rate became effective in 1995 for qualifying customers,
with rate adjustments designed to recover from other customers the costs of
the discount. The ruling also eliminated the Conservation Rate Break and
restructured the rates between customer classes, but did not significantly
change overall revenue levels. See Note 14 to the Financial Statements under
Item 8 for a discussion of the Company's legislative resource commitments.

Approximately 30,000 of the Company's customers received assistance
totaling $5.4 million from federally funded Low Income Home Energy Assistance
Programs (LIHEAP) operated by the State of Minnesota for the 1995-96 heating
season. Other states served by NSP have similar programs. Qualification for
the Company's Low Income Discount Rate is based on eligibility for LIHEAP.
The federal LIHEAP program is facing some opposition and funding could be lost
in the future.

Gas utilities in Minnesota are 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 1996 to increase its demand entitlements due to projected increases
in firm customer count, to decrease the Minnesota jurisdictional allocation
of total demand entitlements, effective Nov. 1, 1996, and to recover the
demand entitlement costs associated with the increase in transportation and
storage levels in its monthly PGAs. In February 1997, the MPUC approved NSP's
1996-97 entitlement levels.

In 1995, the MPUC initiated a rulemaking process to amend, repeal, or
replace existing rules governing customer service standards for gas and
electric utilities. In 1995 the MPUC solicited comments from interested
parties and formed an advisory task force representing interests from electric
and gas utilities, low and fixed-income consumer advocate groups, other
Minnesota State 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
requiring NSP to have a signed contract for service, restricting collection
of past-due bills to only the party(s) named on the bill, and prohibiting 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. The task force currently is not actively meeting.

In response to customer requests and concerns, the Company initiated
several changes and clarifications to its tariff options through miscellaneous
filings in 1996. For Company gas business customers in Minnesota, the Daily
Balancing Service and Telemetering Service Riders were approved along with
modifications to the Company's gas transportation tariffs. Commercial and
industrial electric customers will now be able to participate in the Company's
proposed Real Time Pricing experimental program.

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 subsequent to the merger and a four-year rate
freeze thereafter, except for certain uncontrollable events. The rate plan
was modified in March 1996 to also provide for a freeze in gas rates through
1998. The proposed rate plan included a request for a four-year amortization
of the costs associated with the Merger Transaction.

In June 1996, the MPUC issued an order that established the procedural
framework for the MPUC's considerations of the merger. Contested case
hearings were ordered for the issues of merger-related savings, electric rate
freeze characteristics, NSP's pre-merger revenue requirements, Primergy's
ability to control the transmission interface between the Mid-Continent Area
Power Pool (MAPP) and the Wisconsin and Upper Michigan area, and the impact
of control of this interface on other Minnesota utilities. Evidentiary
hearings were held from Nov. 20 through Dec. 3, 1996. The Minnesota
Department of Public Service recommended a rate reduction of 2.0 percent,
compared with the 1.5 percent reduction the Company proposed. In January and
February 1997, administrative law judges issued their findings and
recommendations in the Minnesota merger applications. Among other items they:
found that NSP's projected merger-related cost savings in general were
reasonable; recommended a four-year rate freeze, with very limited exceptions
for rate changes; concluded that the merger would not provide Primergy with
the ability or incentive to negatively impact competition; and determined the
Company's pre-merger electric rates for Minnesota retail customers may exceed
revenue requirements by $3.5 million, or one-fifth of one percent. The MPUC
will consider the administrative law judges' recommendations along with other
information when it deliberates and decides the case. On March 5, 1997, the
Office of the Attorney General, a participant in the merger case, filed a
brief which expressed for the first time opposition to the merger. On March
20, 1997, the MPUC heard comments from the parties on the need for additional
hearings or other procedures prior to making a decision on the merger. While
NSP believes the case is ready for decision now, the MPUC is considering
what further procedures, if any, it will require. If no further procedures
are undertaken, a decision in the second quarter is expected.

In July 1996, the MPUC, on a motion from a Commissioner, voted to request
an investigation into allegations of improper communications between two
Commissioners and a Company lobbyist. The MPUC in September 1996 determined
in an order that no improper contact had taken place. Upon reconsideration
in December 1996, the MPUC reversed itself and found the communications were
improper. However, in January 1997 prior to issuing an order on its December
decision, the MPUC reconsidered and nullified its December decision. No final
written order has been issued.

The need for general rate filings in 1997 depend upon the outcome of the
merger case.

North Dakota Public Service Commission (NDPSC)

On 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, voted
unanimously to approve the Merger on June 26, 1996, basically on the terms
proposed by NSP.

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 conservation expenses by $1.7 million in 1995. 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 responded 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. This reduction is in addition to the merger-related gas rate
reductions. On August 7, 1996, the NDPSC approved an annual reduction of
$491,000 effective September 1, 1996. In its order, the NDPSC also opened an
investigation to examine gas cost of service methodologies and rate design
criteria for the Company. Results of this investigation are expected to be
revenue neutral.

No other general rate filings are anticipated in North Dakota in 1997.

South Dakota Public Utilities Commission (SDPUC)

In 1995, the SDPUC determined that it did not have jurisdiction to
approve or deny the Merger Transaction with WEC. On September 30, 1996 the
Company filed a 1.5% electric rate reduction ($1.2 million on an annual basis)
to be effective upon closing of the Merger Transaction. After the merger-
related reduction, South Dakota rates would then be frozen through 2000.

Public Service Commission of Wisconsin (PSCW)

In June 1995, the Wisconsin Company filed an application with the PSCW
requesting no change in the electric utility rates for 1996 and a $2.7 million
(3.6%) increase in gas utility rates for 1996. In late 1995, the PSCW ordered
the Wisconsin Company to decrease electric rates by $4.8 million (1.7%) and
ordered a $2.5 million gas rate increase (3.4%). An effective date of January
1, 1996, was authorized for both of these rate changes. In its order, the
PSCW deviated from its normal biennial rate case filing requirements and
directed the Wisconsin Company to file complete electric and gas rate cases
in early 1996 for the test year beginning January 1, 1997, as discussed below.
This special filing was requested by the PSCW to facilitate its review of the
Wisconsin Company's pending application to merge with WEC.

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 $.6 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 a full rate case for the
1997 test year on a stand alone basis as requested by the PSCW. The Wisconsin
Company's filing described revenue deficiencies for both electric and gas
utilities. However, no rate increases were requested. Technical hearings for
the Wisconsin Company's electric and gas rate cases were held before the PSCW
on July 8, 1996. On November 26, 1996, the PSCW issued an order approving the
Wisconsin Company's application for no change in rates. However, certain
classes of customers will experience small changes in rates as a result of
rate design revisions requested by the Wisconsin Company. These changes to
electric rates for certain customers classes have an offsetting effect on
overall revenues. There were no significant changes to gas rates. In its
order, the PSCW approved a capital structure composed of 45% debt and 55%
common equity, and granted an 11.3% return on common equity.

On March 18, 1996, the Wisconsin Company and WEC filed testimony and
exhibits supporting the original Aug. 4, 1995 Merger Transaction filing. On
July 24, 1996 the PSCW held a prehearing conference on the merger proceeding.
At the prehearing conference, the parties agreed upon an extensive issues list
and a schedule for the hearing. At its open meeting on Aug. 8, 1996, the PSCW
revised the schedule and set hearings to begin Oct. 30, 1996. In October
1996, the PSCW staff filed testimony with the PSCW proposing various
conditions, including potential divestiture of certain transmission,
generation and gas assets and a larger reduction in electric rates than
proposed by NSP and WEC. The staff recommendations differ materially from the
merger terms and conditions proposed in the application NSP and WEC originally
filed with the PSCW. In late December 1996, two legislators from Wisconsin
asked the PSCW to delay decisions on all pending utility mergers until the
Wisconsin Legislature rewrites the state's utility merger law. In early
January 1997, the PSCW voted unanimously not to delay its decision. However,
later in January, a Dane County Circuit Court judge ordered the PSCW to delay
its decision on the merger, pending the results of an investigation regarding
alleged prohibited conversations between one of the PSCW commissioners and WEC
officials. The judge further ordered the PSCW to investigate the allegations.
At the request of the PSCW, the matter is under investigation by the District
Attorney's Office of Milwaukee County. NSP cannot predict when the PSCW will
resolve the allegations and proceed with deliberations concerning the proposed
merger. In early 1997, legislation was introduced in the Wisconsin
legislature to revise the statute under which the PSCW reviews utility
mergers. As introduced, the legislation would apply to the Primergy merger
if it is still pending before the PSCW at the time the legislation is signed
into law. In that event, it is highly likely that the PSCW would be required
to hold additional hearings on the merger application.

In September 1996, the PSCW issued an order setting minimum standards for
creating an independent system operator (ISO) for the electric transmission
system of NSP and WEC that differ from NSP's and WEC's ISO proposal filed with
FERC, as discussed later. This order was issued as part of a generic electric
utility restructuring process the PSCW started in 1995. Although the
restructuring process is separate from the merger proceedings, the order is
related because the PSCW staff, in its testimony filed in the merger
proceeding, as discussed above, recommended establishing an ISO that meets the
standards of the PSCW's order as a condition of approving the merger. In
addition, in September 1996, the PSCW submitted its ISO order to the FERC with
a request that the FERC require an ISO satisfying the PSCW minimum standards
as a condition of FERC approval of the NSP/WEC merger application. In October
1996, NSP and WEC filed with the PSCW, as supplemental testimony and exhibits
in the merger proceeding, the same ISO proposal filed with the FERC, as
discussed later.

The Wisconsin Company was originally scheduled to file a general rate
case in June of 1997 for rates effective January 1, 1998 as required by the
PSCW biennial filing schedule. However, because of the PSCW's decision to
deviate from this schedule, it is unlikely the Wisconsin Company will file a
rate case until later in 1997, if at all. If the PSCW approves the NSP/WEC
merger, the Wisconsin Company anticipates the PSCW will waive the biennial
rate case filing requirements and instead will accept the rate reductions and
the four-year freeze as proposed in the merger application.

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. On April 10, 1996, the
MPSC approved the merger application through a settlement agreement containing
terms consistent with the merger application.

There were no changes in the Michigan electric and gas base rates during
1996. The Wisconsin Company does not anticipate the need to file for a change
in Michigan rates in 1997.

Open Access Transmission Proceedings (FERC)

In April 1996, the FERC issued two final rules, Order Nos. 888 and 889,
which may have a significant impact on wholesale markets. Order No. 888,
which was preceded by a Notice of Proposed Rulemaking referred to as the
"Mega-NOPR", concerns rules on non-discriminatory open access transmission
service to promote wholesale competition. Order No. 888, which was effective
on July 9, 1996, requires utilities and other transmission users to abide by
comparable terms, conditions and pricing in transmitting power. Order No.
889, which had its effective date extended to Jan. 3, 1997, requires public
utilities to implement Standards of Conduct and an Open Access Same Time
Information System ("OASIS", formerly known as "Real-Time Information
Networks"). These rules require transmission personnel to provide the same
information about the transmission system to all transmission customers using
the OASIS. A new proposed rule on Capacity Reservation Open Access
Transmission Tariffs also was issued on April 24, 1996. This proposed rule
requested comments on a new proposed tariff to be in effect no later than Dec.
31, 1997. With regard to compliance with the first phase of Order 888, on
July 9, 1996, NSP submitted its transmission tariff compliance filing and an
information filing that unbundled the transmission component of the full
requirements municipal wholesale customers' rates. With regard to the second
phase, in December 1996 NSP submitted its compliance filing which unbundled
the transmission component of its coordination agreements. For transactions
under these agreements, these customers became NSP transmission service
customers. In October 1996, the FERC accepted NSP's information filing. NSP
also is in compliance with Order 889. Steps taken in compliance include the
submission of the requisite Standards of Conduct filing in November 1996 and
the training of employees on these standards in January 1997. NSP continues
to be generally supportive of the FERC's efforts to increase competition.

The FERC's Order No. 888 required utilities to offer a transmission
tariff that includes network transmission service (NTS) to transmission
customers. NTS allows transmission service customers to fully integrate load
and resources on an instantaneous basis, in a manner similar to NSP's
historical integration of its load and resources. Customers can elect to
participate in the cost-sharing network by requesting NTS service from NSP.
Under NTS, NSP and participating customers share the total annual transmission
cost for their combined joint-use systems, net of related transmission
revenues, based upon each company's share of the total system load. The
expected annual expense increase to NSP, net of cost-sharing revenues, as a
result of offering NTS is estimated to be approximately $27 million for 1997.
In 1996, NSP incurred $3 million of NTS expenses.

Electric Transmission Tariffs and Settlement (FERC)

NSP has been an industry leader in the area of transmission open access.
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. On Feb. 5, 1996, the FERC
denied NSP's request for rehearing and required NSP to submit a refund
compliance filing. A compliance filing was made on March 29, 1996 and the
amount refunded by both companies in 1996 was $1.4 million. This refund had
been fully accrued as of Dec. 31, 1995.

In March 1994, NSP filed a revised open access transmission tariff with
the FERC. On April 11, 1995, an Offer of Settlement (the Settlement) was
entered into by a majority of the parties involved in this proceeding. The
settlement agreement includes a transmission tariff that complies with the
FERC transmission pricing policy which calls for comparability of service and
pricing, network service, and unbundling of ancillary charges such as
scheduling and load following. The FERC approved the Settlement on Feb. 14,
1996, subject to the outcome of the Final Rule (Open Access Transmission Order
No. 888, as previously discussed). The revenue effect of the settlement on
the Company is expected to be 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. On
October 11, 1996, in response to the Final Rule, NSP filed the Order 888
proforma tariff using the settlement rates from the approved NSP tariff.

Proposed Merger Approval Proceedings (FERC)

In July 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.

In late 1995, various intervenors filed comments with FERC. The issues
raised by intervenors with respect to the merger application at the FERC are
primarily related to two areas: the impact on competition and the nature of
the cost savings. On Jan. 31, 1996, the FERC issued a ruling which put the
merger approval filing on an accelerated schedule. The FERC ordered that only
one of six merger issues raised by intervenors was entitled to
a hearing, provided the applicants agreed to a wholesale rate freeze.
Therefore, the effect of the proposed merger on bulk power competition was the
only issue entitled to a hearing.

In February 1996, the Company and WEC agreed to freeze wholesale rates
for four years subsequent to the Merger Transaction.

WEC and NSP filed testimony with the FERC providing a detailed analysis
of generation "market power" and more specific information about the ISO
proposal included in earlier filings. This additional information was
provided to the FERC in response to concerns raised by intervenors in the
merger proceeding and by the FERC staff. Hearings were held in June 1996.

The FERC administrative law judge (ALJ), in the merger proceeding, issued
an initial decision on Aug. 29, 1996, recommending approval of the merger
application, subject to NSP and WEC meeting eight conditions. A significant
part of the ALJ's initial decision discusses the design of an ISO. The ALJ's
initial decision specifically rejected the need for divestiture of any
generation or transmission facilities as a requirement for ensuring open and
equal access to the transmission system. In October 1996, NSP and WEC filed
a Unilateral Offer of Settlement (UOS) with the FERC. The UOS includes a
transmission system control agreement and articles and bylaws for establishing
an ISO, intended to meet the requirements of the ALJ's decision and FERC
guidelines. In mid-December 1996, the FERC revised and streamlined its 30-
year-old policy for evaluating public utility mergers, with the changes
designed to expedite the processing of merger applications. The new policy
primarily focuses on three factors in reviewing mergers: the effect on
competition, rates, and state and federal regulation. For pending mergers,
the policy will be applied on a case-by-case basis. NSP and WEC believe the
proposed merger is consistent with the FERC's revised merger policy and are
hopeful that the FERC will simultaneously rule on the UOS and the pending
merger application in the first half of 1997.

Other Proceedings (FERC)

In September 1996, NSP filed for FERC approval to "abandon" FERC's
jurisdiction over two liquefied natural gas ("LNG") plants which NSP operates
near St. Paul, Minnesota, and Eau Claire, Wisconsin. FERC asserted
jurisdiction over the plants in the late 1970s, and NSP has provided FERC
regulated LNG services from the two plants since that time. Under the NSP
filings, FERC would abandon jurisdiction under Section 7 (c) of the Natural
Gas Act, but would retain limited jurisdiction under 18 CFR Part 284.224. The
"abandonments" are required to complete the Primergy merger, but would also
allow NSP to modify the LNG plant facilities or provide new LNG services
without prior FERC approval. FERC action is pending.

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 PUHCA and the Federal Power Act.
Among many other provisions, the Energy Act is designed to promote competition
in the development of wholesale power generation in the electric utility
industry. It exempts a new class of independent power producers from
regulation under the PUHCA. The Energy Act also allows the FERC to order
wholesale "wheeling" by public utilities to provide utility and non-utility
generators access to public utility transmission facilities. The provision
allows the FERC to set prices for wheeling, which will allow utilities to
recover certain costs. The costs would be recovered from the companies
receiving the services, rather than the utilities' retail customers. The FERC
Orders No. 888 and 889 (as discussed in "Utility Regulation and Revenues,"
herein) reflect the trend toward increasing transmission access under the
Energy Act.

The continuing trend of increased competition in the wholesale markets
continues to drive wholesale rates lower than previous years. With the
competition, NSP's municipal customers are continually evaluating a variety
of energy sources to provide their power supply. This trend has resulted in
renegotiation of existing municipal contracts, which will continue the current
trend of lower municipal wholesale power supply revenues.

In 1992, nine of the nineteen municipal wholesale customers notified the
Company of their intent to terminate their power supply contracts. Seven
terminated their agreements effective July, 1995 and the other two effective
July, 1996. Of the other ten municipal wholesale customers, one in 1995
became a member of the Central Minnesota Municipal Power Agency (CMMPA). The
Company has supplied the energy requirements to CMMPA since it was formed in
1992, and in March of 1996 CMMPA selected NSP to provide 100% of its energy
requirements through 2001. Responding to changing market competition, the
Company has offered nine municipal wholesale customers with existing supply
agreements some alternatives which more closely reflect the communities' own
circumstances and tolerance for risk versus potential savings. Each wholesale
customer will make their own decision based on what terms and conditions best
fits their needs.

The Wisconsin Company provided power supply to ten municipal wholesale
customers in 1996. The Wisconsin Company has offered discounted rates to
customers in exchange for longer contract terms. In 1996, seven customers
received discounts of three to five percent below the FERC authorized W-1
wholesale rate. Beginning in 1996, two customers began service under five-
year negotiated rate agreements, and at the end of the five year term, the
Wisconsin Company will have no further obligation to serve these two
customers. In late 1996, one of the existing customers renewed its power
supply agreement for an additional five years. With this agreement, all
existing Wisconsin Company municipal wholesale customers have current power
supply agreements ranging from 4 to 10 year terms. Changes in the wholesale
market were anticipated and the Wisconsin Company is providing discounts and
negotiated services to be competitive. Two investor owned utility wholesale
customers renewed their agreements in late 1996 for an additional five years.
They will purchase almost all of their power supply requirements from the
Company. A partial requirements sale is also being made to one additional
municipal customer.

The Company is experiencing a continuing increase in requests for the use
of its transmission system as power marketers continue to enter the electric
industry. In 1996, the Company filed 58 transmission service agreements for
FERC approval.

Many states are currently considering retail competition. The timing of
regulatory actions and their impact on NSP cannot be predicted and may be
significant. Regulators 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 February 1996, the PSCW issued its report to the state legislature on
restructuring the electric industry. The report was the culmination of over
a year of work by representatives from a wide range of interests, including
low income advocates, environmental groups, regulators and the utilities. NSP
played an active role in the efforts. Key elements of the report include:
1) unbundling the vertically-integrated utility functions into generation,
transmission, distribution and energy services; 2) improving competition in
electric generation while insuring consumer access to the low costs associated
with existing power plants; 3) preventing the exercise of market power by
large companies; 4) revising Wisconsin's regulatory processes while protecting
the environment; 5) working to transform the transmission system into a common
carrier: 6) developing distribution and retail service requirements and 7)
developing alternative means for funding and providing social benefits to
customers. The report included a 32 step plan to achieve these elements with
the ultimate goal of opening the retail market to competition by the year
2001. The PSCW began implementing the 32 step plan in 1996. As of the end
of the year, parties have filed plans with the PSCW to unbundle utility
functions; completed hearings on revising the State's Advance Plan and
Certificate of Public Convenience and Necessity processes; developed proposals
regarding the funding and delivery of low income, energy efficiency, renewable
resource and environmental research services; and began to work on initial
distribution and retail service requirements. In addition, the PSCW issued
an order in September 1996 that set minimum standards for creating an ISO, as
discussed previously.

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. As a follow-up to the draft principles, the Minnesota Commission
convened a group, including NSP, referred to as the Electric Competition
Workgroup, to examine various aspects of possible changes. The workgroup
released a report examining options for increasing competition in Minnesota
and encouraging more efficient administrative oversight of regulated retail
services. The report called for the introduction of flexible rates for large
electric customers and quicker review of electric service contracts and non-
controversial filings.

Minnesota's Governor and legislative leadership have indicated that
electric utility restructuring will not be a priority until the 1998 session.
Nevertheless, legislative hearings on the issue are expected to begin in 1997.
NSP supports industry restructuring in Minnesota, as long as, among other
things, it is preceded by property tax reform. Currently, NSP's property
taxes in Minnesota are two to three times higher than they would be in our
neighboring states, and investor-owned utilities also pay higher taxes than
other types of utilities within Minnesota. NSP is advocating a tax reform
proposal that would eliminate the severe interstate and intrastate disparities
in the way different types of utilities are taxed and would position NSP to
compete more fairly in a restructured energy environment.

On February 20, 1996, the NDPSC opened an electric industry restructuring
investigation, Case No. PU439-96-54. Several parties, including NSP, filed
comments and appeared at two hearings in May and December, 1996. The NDPSC
particularly sought commentary on the National Association of Regulatory
Utility Commissioners (NARUC) Principles to Guide the Restructuring of the
Electric Industry. On February 19, 1997, the NDPSC issued an order adopting
the NARUC principles for use in North Dakota. The principles generally
suggest that industry changes should only occur when they result in economic
efficiency and serve the broader public interest. Specific principles address
areas of network reliability, customer choice, sharing of benefits, protecting
the environment, stranded costs, and state commission responsibility for
determining restructuring policies. The principles were previously adopted
by NARUC in the summer of 1996. The impact of this NDPSC action is not
expected to be material for NSP within the foreseeable future. Long term
implications, as markets become more competitive, cannot be predicted.

In Michigan, the MPSC Staff recently released a report setting out their
proposal for instituting retail access. In their report, MPSC endorsed two
fundamental principles: (1) all customers should be eligible to participate
in the emerging competitive market, and (2) rates should not be increased for
any customers and should be reduced where possible. Staff's plan calls for
utilities to open up 2 1/2% of their loads each year beginning in 1997, with
full retail access in effect by the year 2007. Also, the plan calls for:
recovery of stranded costs through the use of rate reduction bonds; the
institution of performance based rates for transmission and distribution
service; the requirement that originating suppliers in any retail access
transaction provide reciprocal rights to the utility providing the retail
direct access service; provision of distribution utility service to customers
who do not choose to participate or who cannot participate in the program; and
unbundling of rates into separate functions. Comments were filed January 21,
1997.

In July 1996, NSP executed a long term electric service contract with one
of its largest electric customers, Koch Refining Company. Previously, Koch
had planned to construct a 180 Mw cogeneration plant, leave the NSP retail
system, and make sales of excess electricity in the wholesale market in
competition with NSP. Under the agreement, Koch will remain an NSP retail
customer, and will participate in NSP's electric supply bidding process before
constructing any new generating plant. The agreement complies with a new
Minnesota law enacted in 1996. NSP filed for MPUC approval of the agreement
in September 1996. The MPUC ruled the agreement is consistent with the
statute but deferred action on cost recovery until the next electric rate
case.

In June 1996, the City Council for the City of St. Paul, Minnesota (the
City), approved new ten year electric and natural gas franchise agreements
between NSP and the City. Under Minnesota law, utilities are required to
obtain franchises from the municipalities where they serve. The franchise
fees collected from customers in St. Paul total approximately $14 million
annually. Under the new agreements, NSP and the City agreed to a substantial
change in the way NSP collects and pays franchise fees. Previously, NSP
collected a surcharge based on a percentage (5 or 8%) of the customer's bill
only for energy supplied by NSP. This fee structure would have placed NSP's
electric supply sales at a significant price disadvantage in a retail wheeling
environment, because a customer could avoid the fee by purchasing electric
supplies from a third party supplier, who cannot be assessed franchise fees.
In the new agreements, NSP and the City agreed to a "unit charge" mechanism
where the franchise fee is collected on the units of energy (Kw, Kwh or CCF)
of electricity or gas delivered by NSP regardless of the supplier. The new
fee structure will generate about the same total fee revenue for the City each
year, but are "supplier neutral" and will not create uneconomic price
incentives for customers to leave the NSP system. In October 1996, the MPUC
approved NSP tariff changes required to collect the new fee structure on
retail bills. To NSP's knowledge, the new St. Paul franchise agreements are
the first in the United States where all utility franchise fees are collected
on a unit of delivery basis.

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
and NSP's own Generation business unit to bid in response to Company
solicitations for proposals.

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.
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 per 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; metering automation; 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 Cenerprise subsidiary.

Capability and Demand

Assuming normal weather, NSP expects its 1997 summer peak demand to be
7,468 Mw. NSP's 1997 summer capability is estimated to be 8,826 Mw, (net of
contract sales) including 903 Mw (including reserves) of contracted purchases
from the Manitoba Hydro-Electric Board, a Canadian Crown Corporation (Manitoba
Hydro) and 1,012 Mw of other contracted purchases. The estimate assumes 7,828
Mw of thermal generating capability and 1,183 Mw of hydro and wind generating
capability. Of the total summer capability, NSP has committed 185 Mw for
sales to other utilities.

NSP's 1996 maximum demand of 7,487 Mw occurred on August 6, 1996.
Resources available at that time included 7,109 Mw of Company-owned capability
and 1,698 Mw of purchased capability net of contracted sales. Due to the Mid-
Continent Area Power Pool's (MAPP) penalty for reserve margin shortfalls and
to be prepared for weather uncertainty at the lowest potential cost, NSP
carried a reserve margin for 1996 of 17.6 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). As a result of this
approval, a restated agreement "Restated Mid-Continent Area Power Pool
Agreement Jan. 12, 1996" was approved by the FERC in Docket No. ER96-1447,
effective Nov. 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 14 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 1996, the reliability program resulted in a 14% reduction in the
total number of outages to the Company's feeders, from 2,342 in 1995 to 2,014
in 1996. In addition, outages to critical customers sites decreased by 30%.
Reliability goals for 1997 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 with a non-
regulated power producer 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 in July 1995
and received approval February 20, 1997. 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 30 Mw by 1998.

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 1994 Minnesota legislative mandate (discussed later) 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 proposed to satisfy the above resource needs through
a combination of the following energy source options:

- 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 operational by December 31, 2002.
- Acquisition of competitively priced resources to meet changing
needs, i.e. competitive bidding.

The Company is in the process of updating its current competitive bid
schedule and plans to file it with the MPUC in May 1997. NSP plans to
contract in 1997 for 100 Mw of peaking energy for 1999 in-service.

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 14
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 MEQB, and selected Zond Systems, Inc. to supply the
wind energy. The Company is in the evaluation process for the third phase of
wind generation (another 100 Mw) to be contracted in 1997. The Company is now
finalizing contract negotiations with Minnesota Valley Alfalfa Producers for
75 Mw of farm-grown closed-loop biomass generation to be operational in 2001.
The Company is now bidding Phase II of farm-grown closed-loop biomass
generation (50 Mw) to be operational in 2002. 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 a 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, participated in a proceeding initiated by the MPUC to establish
such values. The MPUC issued its order in January 1997. The high end of the
range of externality values ordered by the MPUC add about 0.55 cents per kwh
to a typical new coal plant and about 0.15 cents per kwh to a natural gas
fired plant. The carbon dioxide value comprises about 60 percent to 80
percent of these amounts. NSP and several other parties have requested the
MPUC reconsider its decision. The MPUC will deliberate reconsideration
requests in early 1997.

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 energy efficient and competitive. During 1996,
NSP's programs reduced system peak demand by approximately 159 Mw. Since
1982, NSP's DSM programs have achieved 1,383 Mw of summer peak demand
reduction, which is equivalent to 18 percent of its 1996 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. The MPUC in February 1997 postponed its decision on the
long term energy savings goals to the next Resource Plan, to be filed in
January 1998.

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 $14 million in 1996 and $7 million in
1995. In addition, in April 1997 the Company will file for approval of
approximately $6 million of DSM investment returns and $2 million of
performance bonuses for 1996, through an incentive program that rewards the
attainment of specified conservation goals. The MPUC approved DSM investment
returns of $7 million for 1995.

In late 1996 and early 1997, NSP received inquiries for wholesale sales
of dedicated renewable resources using a "green pricing" approach. Green
prices, if approved by regulators, will allow customers to purchase dedicated
renewable resources, such as wind, biomass, and hydro power to meet a portion
of their energy needs. Customers would pay for energy from renewable
resources through a rate premium above standard rates. Efforts are underway
to develop and obtain approval for such prices in both the wholesale and
retail markets. If approved, sales using "green prices" could begin in 1997.
Initially, the revenue impact is not expected to be material.

Energy Sources

For the year ended Dec. 31, 1996, 47 percent of NSP's Kwh requirements
was obtained from coal generation and 28 percent was obtained from nuclear
generation. Purchased and interchange energy provided 21 percent, including
14 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 (59 percent), nuclear (36 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:

1996 1995 1994
Thermal plants 32,657 33,802 32,710
Hydro plants 1,194 1,049 922
Purchased and interchange 9,065 9,189 9,054
Total 42,916 44,040 42,686

Many of NSP's power purchases from other utilities are coordinated
through the regional power organization MAPP, pursuant to a restated agreement
dated January 12, 1996. NSP is one of 53 members, 27 associate members and
6 regulatory participants in MAPP. The MAPP agreement provides for the
members to coordinate the installation and operation of generating plants and
transmission line facilities. The terms and conditions of the MAPP agreement
and transactions between MAPP members are subject to the jurisdiction of the
FERC. The MAPP restated agreement converting MAPP to a RTG, as discussed
previously, was approved by the FERC effective November 1, 1996.

Fuel Supply and Costs

Coal and nuclear fuel will continue to dominate NSP's regulated utility
fuel requirements for generating electricity by NSP owned generating capacity.
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 1996
and the estimated fuel mix for 1997 and 1998 are as follows:

Fuel Use on Btu Basis
(Est) (Est)
1996 1997 1998

Coal 59.7% 60.3% 59.3%
Nuclear 37.2% 36.5% 37.5%
Other 3.1% 3.2% 3.2%

The Company normally maintains between 20 and 40 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 1997 coal requirements. Coal
delivery may be subject to short-term interruptions or reductions due to
transportation problems, weather and availability of equipment.

Based on existing coal contracts, the Company expects that more than 98
percent of the coal it burns in 1997 will have a sulfur content of less than
1 percent. The Company has contracts with two Montana coal suppliers
(Westmoreland Resources and Big Sky Coal Company) and three Wyoming suppliers
(Rochelle Coal Company, Antelope Coal Company and Black Thunder Coal Company)
for a maximum total of 45 million tons of low-sulfur coal for the next 4
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
Approx- Emission
imate Limit
Maximum Amount Contract Sulfur Pounds
Annual Covered by Expiration Content Per MBTU*
Demand Contract Date (%)(2) Input
Plant (Tons) (Tons)

Black Dog 1,000,000 1,000,000 (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 1,200,000 1,200,000 (1) 0.7 2.5(4)
Sherco 7,500,000 7,500,000 (1) 0.5 0.9(5)
12,500,000 12,500,000(6)

*MBTU = Million British Thermal Units

Notes:

(1) Contract expiration dates vary between 1997 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 12.5 million.

The Company's current fuel oil inventory is adequate to meet anticipated
1997 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
1994 1995 1996

Coal** $ 1.13 $ 1.11 $1.02
Nuclear*** .47 .48 .47
Composite All Fuels .89 .87 .83

* 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, 543
Mw Monticello Nuclear Generating Plant and the Prairie Island Nuclear
Generating Plant with two units totaling 1,028 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. In addition, INPO has awarded both of the plants the INPO
Excellence Award, which is a rigorous peer review process that recognizes
plants with the highest levels of excellence in operational safety and
reliability and which have no significant weaknesses.

The Company previously operated the Pathfinder Plant near Sioux Falls,
South Dakota 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 at the
operating plant site.

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. All states
have passed the compact amendments. 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. Barnwell is expected to remain
available until the Ohio facility is completed.

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 at a permanent storage or disposal facility by
1998. The Company has contracted with the DOE for the future disposal of used
nuclear fuel. The DOE is currently charging a 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 electric 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. Further, the DOE
has indicated that a permanent federal facility will not be ready to accept
used nuclear fuel from utilities until approximately 2010. The Company, along
with a group of other utilities and state agencies, won a lawsuit initiated
against the DOE. The primary purpose of the lawsuit was to insure that the
Company and its customers receive timely storage and disposal of used nuclear
fuel in accordance with the terms of the Company's contract with the DOE. On
July 23, 1996, the United States Court of Appeals for the District of Columbia
affirmed the federal government's, and specifically the DOE's obligation to
begin disposing of the nation's high level used nuclear fuel in 1998. On
January 31, 1997, this group of over 30 utilities (led by NSP) and 45 state
agencies, including the Minnesota Department of Public Service, now called the
Nuclear Waste Strategy Coalition, announced the filing of another lawsuit
against the DOE. This suit requests authority to withhold payments to the DOE
for the permanent disposal program. (See Item 3 - Legal Proceedings.)
Recently, the Nuclear Waste Strategy Coalition, states and utilities party to
the DOE lawsuit, and the National Association of Regulatory and Utility
Commissioners wrote to the DOE requesting a plan of action be developed to
meet the January 31, 1998 deadline to take the used fuel from utility sites.

NSP, with regulatory and legislative approval, has been providing on-site
storage 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 used 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 used fuel
assemblies (approximately two-thirds of a 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.
The second increment of four casks were authorized on October 2, 1996 by the
MEQB certifying that by Dec. 31, 1996: (i) the Company had applied to the NRC
for an alternative site license for an off-site temporary used nuclear fuel
storage facility in Goodhue County (but not on the Prairie Island nuclear
generating site), (ii) the Company had 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. As of
January 31, 1997, seven storage casks were loaded and stored on the Prairie
Island site.

As part of fulfilling the commitments required to secure the use of
additional casks, in August 1996, the Company filed the application for the
Goodhue County facility. The Company has taken steps to fulfill these
requirements and has been authorized by the MEQB to load casks six through
nine. The MEQB authorized casks six through nine, but terminated an
alternative siting process which was one of the legislative requirements. The
Company's certification by the MEQB for the use of casks six through nine, is
being legally challenged by the Prairie Island Tribe. In response to this
legal challenge, the Company has suspended the license application with the
NRC, which will remain in effect until the Minnesota Court of Appeals rules,
which is expected in mid-1997. In 1996, 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 13 and 14 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 various private parties to establish a
private facility for interim storage of used nuclear fuel. Originally, this
private effort was focused with the Mescalero Apache Tribe of New Mexico.
Negotiations with the Mescaleros have ceased, but are continuing with the
Skull Valley Band of the Goshute Indian Tribe in Utah. Work is continuing on
the NRC license application preparation. Submittal is planned for June, 1997.
Storage cask certification efforts are continuing with the two vendors on
track to meet the project goals. The interim used fuel storage facility could
be operational and able to accept the first shipment of used nuclear fuel by
mid-2002. However, due to uncertainty regarding pending regulatory and
governmental approvals, it is possible that this interim storage may be
delayed or not available at all.

On January 23, 1997, the NRC issued Prairie Island a Severity Level III
violation and a $50,000 civil penalty stemming from design issues with the
Cooling Water Emergency Intake Line. The Cooling Water Emergency Intake Line
is the dedicated safety-related water source for the Cooling Water Pumps in
the event of a seismic occurrence rendering the normal intake bay inoperable.
Recent self-assessment and tests revealed the line may not perform to its full
design capacity. Prairie Island performed a safety evaluation to justify
continued operation at degraded flow conditions. The analysis utilized a
combination of operator action to reduce pump flow and the reliance on the
non-seismic canal to not completely block flow during a plant seismic event.
The NRC determined that a violation of the safety evaluation process occurred
because an unreviewed safety question existed, due to these changed
assumptions on the non-seismic canal and operator action. The NRC contends
NSP's response to this regulatory issue was not promptly and adequately
addressed.

In January, 1997, the NRC issued a notice of an apparent violation for
the Company's Monticello plant. The notice was regarding whether the
Monticello plant should have submitted to the NRC issues about safety
questions when it approved a reduction in the number of safety-related pumps
used for containment cooling. On March 5, 1997, the Company presented to the
NRC the facts and history of the case, and further discussions centered on
corrective actions. As this time the Company does not know the outcome of
this apparent violation and whether a civil penalty will be incurred.

The Company filed its triennial nuclear decommissioning study in 1996,
and the MPUC approved it in February 1997. The filing requested continuance
of the accruals, funding and other parameters approved in the last
decommissioning study filed in 1993. Although the Company 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, including approximately $1
million in 1996 and 1995 and $6 million in 1994 under such requirements. 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 13 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 14 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:

1996 1995 1994 1993 1992

Revenues (thousands)
Residential
With space heating $67 260 $67 332 $66 962 $68 222 $63 376
Without space heating 659 885 668 411 616 821 583 371 534 676
Small commercial and
industrial 376 797 362 521 351 287 327 888 312 581
Medium commercial and
industrial 401 137 399 259 * * *
Large commercial and
industrial 450 811 448 226 824 195 780 444 718 712
Street lighting and
other 30 033 29 162 28 936 29 214 29 764
Total retail 1 985 923 1 974 911 1 888 201 1 789 139 1 659 109
Sales for resale 98 961 133 961 146 239 159 498 137 962
Miscellaneous 42 529 33 898 32 204 26 279 26 245
Total $2 127 413 $ 2 142 770 $ 2 066 644 $1 974 916 $1 823 316

Sales (millions of kilowatt-hours)
Residential
With space heating 1 112 1 111 1 076 1 094 1 041
Without space heating 8 735 8 845 8 227 7 998 7 640
Small commercial and
industrial 6 091 5 763 5 585 5 307 5 224
Medium commercial and
industrial 7 470 7 511 * * *
Large commercial and
industrial 11 089 10 941 17 874 17 117 16 365
Street lighting and
other 336 329 334 344 372
Total retail 34 833 34 500 33 096 31 860 30 642
Sales for resale 4 929 6 500 6 733 8 044 6 530
Total 39 762 41 000 39 829 39 904 37 172

Customer accounts (at Dec. 31) **
Residential
With space heating 77 201 76 344 76 050 75 644 74 939
Without space heating 1 175 275 1 162 232 1 146 578 1 131 928 1 119 354
Small commercial and
industrial 149 134 144 774 142 858 141 446 140 768
Medium commercial and
industrial 7 962 7 906 * * *
Large commercial and
industrial 669 652 8 172 8 114 7 904
Street lighting and
other 5 030 4 883 4 836 4 813 4 627
Total retail 1 415 271 1 396 791 1 378 494 1 361 945 1 347 592
Sales for resale 54 67 70 71 74
Total 1 415 325 1 396 858 1 378 564 1 362 016 1 347 666

* 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.

** Customers accounts for 1996 may not be fully comparable to prior years due
to differences in meter accumulation in a new billing system implemented
in 1996.

GAS UTILITY OPERATIONS

Competition

NSP provides retail gas service in the eastern portions of the Twin
Cities metropolitan area, portions of eastern North Dakota and northwestern
Minnesota, and other regional centers in Minnesota (Mankato, St. Cloud and
Winona) and Wisconsin (Eau Claire, LaCrosse 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 81 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" (also known
as 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). In February
1997, the FERC upheld this decision after appeals of Order 636 were remanded
by the United States Court of Appeals for the District of Columbia Circuit.

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 by Northern 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 approximately $12 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 and the formation of an energy
services business as a new NSP subsidiary, Cenerprise, Inc. See the Non-
Regulated Subsidiaries section herein for further discussion of Cenerprise.
See further discussion of Viking below.

Business Standards

In July 1996, FERC adopted new rules (in its Order No. 587) which adopt
by reference 140 standard natural gas business practices approved by the Gas
Industry Standards Board ("GISB"). GISB is the independent standards
organization of the natural gas industry. The new rules and standards apply
to interstate gas pipelines like Viking, and are intended to simplify
transportation of natural gas across the interstate gas pipeline "grid".
However, NSP's retail natural gas operations must change their information
systems and operations to comply with the pipeline changes. The new FERC
rules go into effect in the second quarter 1997. Viking estimates that its
total compliance cost will be approximately $1 million. Viking plans to seek
rate recovery of the rule compliance costs in future rate proceedings.

In January 1997, the PSCW adopted "Standards of Conduct" for retail
natural gas utilities ("LDCs") serving Wisconsin consumers. The standards
would apply to the Wisconsin Company's existing gas operations, and the retail
gas operations of New NSP and Wisconsin Energy Company after the proposed
Merger Transaction. The standards are similar to, but much more extensive
than, the standards of conduct FERC has imposed on Viking under Order 497 and
on NSP's wholesale electric transmission functions under Order 889. The PSCW
standards require separation of the LDC delivery function from any affiliate
which engages in "gas functions" and impose extensive reporting and other
administrative requirements. The Wisconsin Company filed its compliance plan
in February, 1997. The PSCW approval is pending.

The SDPUC and NDPSC also initiated dockets in 1996 to examine whether to
adopt standards of conduct for natural gas LDCs serving the two states. (NSP
provides retail gas service in North Dakota but not South Dakota.) The
rulemaking in Wisconsin, South Dakota and North Dakota could create precedent
for future rules affecting NSP's retail electric operations in those states.

Customer Growth and Expansion

In 1996, NSP's retail gas utility operations were faced with the threat
of physical bypass by large industrial customers. Previously, NSP had used
its flexible gas rate discounting authority to compete to retain these
customers. However, reductions in natural gas pipeline construction costs
(which benefit NSP when it constructs its own facilities) made it economical
for some customers to consider bypassing NSP. In response, NSP filed a new
Negotiated Transportation Service Tariff with the MPUC. The MPUC voted to
approve the tariff on March 6, 1997. The new tariff provides additional
flexibility in gas rates discounting for potential bypass customers.

NSP's gas utility again took advantage of opportunities to extend service
to approximately 14,000 new customers during 1996. 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 20,000 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. Construction occurred in 1994
and the project's net capitalized investment cost was approximately $23
million. The MPUC approved a "new area" 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 maintains a non-utility service which sells
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. This service is offered to individuals within
the Company'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 737,258 MMBtu for 1996 occurred on Feb. 1, 1996, when NSP
experienced the coldest 24-hour period since 1977. The average temperature
for the day was -23 degrees in the Twin Cities.

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 582,494 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 248,300
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.
NSP experienced no significant disruption of gas service to firm retail
customers during January-February 1996, when NSP's service area experienced
record peak demand periods due to the extreme cold.

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. 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
1997 through 2013.

Northern Northern Border Pipeline Company
Williston ANR Pipeline Company
Viking TransCanada Gas Pipeline Ltd.
Great Lakes

The agreements with Great Lakes, Northern Border, ANR and TransCanada
provide for firm transportation service upstream of Northern and Viking,
allowing competition among suppliers at supply pooling points, and 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 $16.0 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, 1996, NSP was committed to
approximately $385.2 million in such obligations under these contracts, over
the remaining contract terms, which range from the years 1997-2013. 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 cost of gas supply, transportation service and storage service is
recovered through the PGA cost recovery adjustment mechanism discussed
previously under "Utility Regulation and Revenues". 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.

In July 1995, the FERC issued an order on remand in the 1991 and 1992
general rate cases filed by Great Lakes, 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 rate
adjustment mechanism described previously under "Utility Regulation and
Revenues." However, the FERC also ruled Great Lakes could collect the higher
rates from non-expansion customers retroactive to Nov. 1, 1991. On August 2,
1996, the FERC issued an Order denying rehearing and reconsiderations. On
August 19, 1996, Great Lakes began billing for collection of the surcharge.
NSP elected a 12-month amortization for repayment of its portion of the
surcharge amount (expected to be $2.8 million) and is currently recovering
these costs in the PGA. NSP and several parties to the proceedings, however,
are in the process of seeking rehearing at the District of Columbia Circuit
Court of Appeals.

On March 15, 1996, Northern Natural Gas filed a settlement of its 1995
general rate case. Final FERC approval was received on September 26, 1996.
The Company received $3.3 million in refunds, including interest
from Northern for the period January 1996 through August 1996. Effective
September 1, 1996, Northern reduced its rates to the level in effect prior to
the requested increase. These refunds and lower gas costs have been passed
through to NSP's gas customers through the PGA rate adjustment mechanism.

Purchases of gas supply or services by the Company from the Wisconsin
Company, its Viking pipeline affiliate and its Cenerprise 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 Cenerprise. In November 1996, the MPUC approved a capacity
release agreement between the Company and the Wisconsin Company, which allowed
pipeline capacity sales between the two companies for the 1996-97 heating
season.

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 Cenerprise:

The Company Wisconsin Company

1992 $2.71 $2.80
1993 $3.11 $3.02
1994 $2.59 $3.13
1995 $2.29 $2.78
1996 $2.88 $2.93

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 420 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 NSP's consolidated 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 currently 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 1996, Viking placed two expansion projects in service. The
projects expanded Viking's mainline capacity by 19,400 MMBtu/day (about 5%),
the first major Viking expansion since the 1960's, and constructed a second
pipeline lateral to increase capacity to serve NSP's growing retail gas
operations in the Grand Forks area. The two projects, which were not related
but constructed at the same time, cost approximately $8 million. Viking
expects to recover the project costs through additional long term
transportation service revenues.

In November 1996, Viking filed for FERC approval to install an additional
61,000 MMBtu/day of mainline capacity in 1997 by adding both additional
pipeline and compression. If approved by FERC, the 1997 Viking expansion
project is expected to cost $29 million and could increase Viking revenues by
about $6 million per year. The proposed in service date is November 1, 1997.
Viking would recover the cost of the project through the increased revenues.

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.

As a natural gas pipeline, Viking is subject to FERC standards of conduct
in its transactions with the Company, the Wisconsin Company and Cenerprise,
pursuant to FERC Order 497. Viking must transact with Cenerprise on a non-
discriminatory basis, and certain restrictions are imposed on the retail gas
operations of the Company and the Wisconsin Company. The Order 497
restrictions on Viking are similar to the Order 889 restrictions on NSP's
wholesale electric transmission operations.

In January 1997, NSP entered into a non-binding letter of intent with
TransCanada regarding a potential natural gas pipeline expansion and extension
project to serve the upper midwest U.S. gas market, and the potential purchase
by TransCanada of a 50 percent interest in Viking. The proposed project would
involve installing a new pipeline parallel to the existing Viking pipeline,
and extending the new pipeline to the Chicago area. If constructed, the new
pipeline could transport approximately 1.0 to 1.2 billion cubic feet of
natural gas per day to markets in Minnesota, Wisconsin, North Dakota and
Illinois. The anticipated project cost is approximately $800-900 million
(U.S. currency), and the new pipeline would be placed in service in late 1999
or 2000. The project would be constructed only if sufficient market demand
exists, and would be subject to extensive pre-construction regulatory and
environmental reviews by the FERC and other appropriate government agencies.
If the project proceeds, the letter of intent provides that NSP and
TransCanada would jointly own and operate the expanded pipeline entity. No
definitive agreements exist between NSP, Viking and TransCanada at this time.
Any agreements would be subject to approval by the boards of directors of the
respective companies. Due to the early stages of this matter, the capital
expenditure projections discussed later do no include investments for this
project.

Gas Operating Statistics

The following table summarizes the revenue, sales and customers from
NSP's regulated gas businesses:

Revenues (thousands) 1996 1995 1994 1993 1992

Residential
With space heating $263 391 $212 853 $204 668 $220 828 $178 164
Without space heating 3 739 2 690 2 838 2 715 2 523
Commercial and industrial
Firm 146 145 119 863 120 912 131 431 105 829
Interruptible 63 585 48 646 49 384 52 216 41 612
Other 153 1 686 3 688 630 386
Total retail 477 013 385 738 381 490 407 820 328 514
Interstate transmission
(Viking) 17 553 16 328 16 307 10 247
Agency, transportation and
off-system sales 34 662 26 122 24 338 12 237 7 692
Elimination of Viking sales
to NSP (2 435) (2 374) (2 232) (1 228)
Total $526 793 $425 814 $419 903 $429 076 $336 206

Sales (thousands of mcf)
Residential
With space heating 47 698 41 993 38 427 40 946 35 136
Without space heating 451 301 323 331 323
Commercial and industrial
Firm 31 748 28 275 27 342 28 622 24 273
Interruptible 23 210 22 408 19 373 18 559 15 823
Other 394 772 212 186 108
Total retail 103 501 93 749 85 677 88 644 75 663

Other gas delivered (thousands of mcf)
Interstate transmission
(Viking) 161 972 152 952 147 919 83 613
Agency, transportation
and off-system sales 17 535 19 679 13 466 8 128 7 332
Elimination of Viking
sales to NSP (19 311) (20 440) (16 845) (8 425)
Total other gas
delivered 160 196 152 191 144 540 83 316 7 332

Customer accounts (at Dec. 31) *
Residential
With space heating 379 834 367 811 351 773 337 868 326 439
Without space heating 18 889 18 196 18 961 19 408 19 841
Commercial and
industrial 40 244 38 575 37 140 36 185 35 458
Total retail 438 967 424 582 407 874 393 461 381 738
Other gas delivered 30 62 18 40 30
Total 438 997 424 644 407 892 393 501 381 768

* Customers accounts for 1996 may not be fully comparable to prior years due
to differences in meter accumulation in a new billing system implemented
in 1996.

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 1996 operating revenues of $70 million and equity income of $35
million, and had assets of $680 million at Dec. 31, 1996.

NRG conducts business through various subsidiaries, including: NRG
International, Inc.; NEO Corporation; NRG Energy Center, Inc; NRG Sunnyside
Inc.; NRG Operating Services, Inc.; and other businesses and affiliates, the
more significant of which are discussed below.

Operating Businesses - International

In 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, 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 1996,
each of the investor partners purchased one third of the remaining one percent
interest held by the German government.

In 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 (60 Mw of which is sold directly
to an independent railroad) located 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), the
builder of the Schkopau plant, owns the remaining 58.9 percent interest and
operates the plant. The plant is 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 operation in January of 1996, and the second unit came on line in July
of 1996.

In 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. Through a joint venture with ACT and another party,
NRG has acquired a 26.5 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 250 Mw of coal-fired generation and 74
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.

On December 19, 1996 NRG and Nordic Power Invest AB (NPI), a wholly-owned
subsidiary of Vattenfall AB, purchased 96.6% (4,060,732 shares) of the common
stock of Bolivian Power Company Limited for $43 per share through Tosli
Investment BV, the holding company jointly owned by NRG and NPI. Bolivian
Power is the second largest generator of electricity in Bolivia with 162
megawatts (Mw) of capacity, which includes 136 Mw of hydro capacity and a 17
Mw gas-fired peaking unit. Bolivian Power is incorporated in Canada, with a
local office in La Paz, Bolivia and a headquarters located in Minneapolis,
Minnesota. Bolivia Power is in the process of expanding its hydroelectric
facilities in the Zongo Valley by 56.6 Mw. Upon completion of this expansion
in 1998, Bolivia Power's total generating capacity will be 218.8 Mw. Although
NRG currently owns a 62% interest in this project (which has been previously
referred to in media releases as COBEE), NRG intends to reduce its holding to
50% or less.

In 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 Corporcion Andina de Fomento (CAF) formed the
Scudder Latin American Trust for Independent Power (the Trust), 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 Trust retained Scudder Stevens & Clark, Inc. as its investment manager and
commenced investment development efforts in 1993. In June 1995, the Trust was
liquidated and assets were transferred to two new trusts, Scudder Latin
American Power 1P-LDC and Scudder Latin American Power 1C-LDC, together
referred to as Scudder, to permit the efficient allocation of foreign source
income. Each of the four investors has committed to invest up to $25 million
during the period 1994-1998. Scudder currently holds investments in two power
generation facilities in Latin America and two in the Caribbean.

In March 1996, a joint venture between NRG and Transfield, an Australian
facilities 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 180 Mw Collinsville coal-fired
power generation facility in Queensland, Australia. NRG owns a 50 percent
interest in the facility and serves as operator in conjunction with
Transfield. Transfield is performing the facility refurbishment and
environmental remediation under a fixed price turnkey contract. Refurbishment
is expected to be completed in March of 1998.

On February 6, 1997, NRG signed a subscription agreement with Energy
Developments Limited (EDL) to acquire up to 20% of its common stock, and an
additional 15% of its preference shares at $2.20 per share (Australian
currency). EDL is an Australian company engaged exclusively in independent
power generation from landfill gas, coal seam methane, and natural gas
(including the latest technology combined cycle projects). EDL is the largest
generator of power from coal seam methane in the world. The company currently
operates over 200 Mw of generation across five states and territories of
Australia and has commenced the development of new projects in the United
Kingdom, Asia and New Zealand. The current equity megawatt ownership held by
EDL is approximately 170 Mw. EDL is a publicly traded company with its
securities listed on the Australian Stock Exchange. On February 11, 1997 NRG
made an initial purchase of 7.2% (4,500,000 shares) of EDL's common stock.

Operating Businesses - Domestic

In April 1996, NRG purchased a 41.86 percent interest in O'Brien
Environmental Energy, Inc. (O'Brien). O'Brien has been renamed NRG Generating
(U.S.) Inc. (NRGG). The former shareholders of O'Brien own the remaining
58.14 percent of NRGG, which is traded on the NASDAQ small capital market
under the ticker symbol NRGG. NRGG is the 100% owner of power cogeneration
facilities in Newark and Parlin, New Jersey. These two facilities have an
aggregate operating capacity of approximately 180 megawatts. NRGG also has
a 33.3% interest in a 150 Mw facility currently under construction in
Philadelphia, Pennsylvania. In addition to an equity interest in NRGG, in the
purchase NRG also acquired certain biogas projects which were transferred to
its subsidiary, NEO Corporation (NEO, as discussed later), and also made loans
to NRGG and entered into project commitments. (See Note 14 of the Financial
Statements Under Item 8 for further discussion of NRG's capital commitments
related to NRGG.)

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 pays NRG a fee to manage its RDF facility under an operation and
maintenance agreement approved by the MPUC. In 1996, the RDF plants processed
approximately 808,544 tons of municipal solid waste into approximately 634,901
tons of RDF that was burned at two NSP power plants and at a power plant owned
by United Power Association.

In 1994, NRG, through a wholly owned subsidiary, purchased a 50 percent
ownership interest in Sunnyside Cogeneration Associates, a Utah joint venture,
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.

NRG participates in several energy businesses which are managed as a
thermal business group. The largest thermal business of NRG is Minneapolis
Energy Center (MEC), a downtown Minneapolis district heating and cooling
system which utilizes steam and chilled water generating facilities to heat
and cool buildings for over 100 heating and cooling customers. The primary
assets of MEC include the main plant, with 800,000 pounds per hour of steam
capacity and 22,000 tons per hour of chilled water capacity, two satellite
plants, two standby plants, six miles of steam lines and two miles of chilled
water distribution lines. NRG also owns 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. Current steam
sales volume of the San Francisco thermal system is approximately 700 million
pounds. The San Francisco thermal system provides service to more than 200
buildings. The Pittsburgh thermal system provides annual steam sales volume
of 300 million pounds, and chilled water sales volumes of 21 million ton-hours
to 24 customers. In addition, NRG 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.

Another NRG wholly owned subsidiary, NEO, was formed in 1993 to develop
small power generation facilities in the United States. NEO owns a 50 percent
interest in Minnesota Methane LLC. Minnesota Methane LLC is developing small
scale waste to energy facilities utilizing methane gas. In 1996 Minnesota
Methane LLC acquired a 12 Mw waste to energy project in West Covina,
California. In 1996 NEO and Minnesota Methane LLC also acquired six waste to
energy projects as part of the acquisition of NRGG (as previously discussed).
Of the projects acquired, four were operating facilities and two were projects
under development and construction. In 1994, NEO acquired a 50 percent
interest in Northbrook Energy LLC, an independent power producer with 21 Mw
of hydroelectric facilities throughout the United States. In 1996, Northbrook
acquired seven additional hydroelectric plants totaling 15.5 Mw from Duke
Power Company.

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 14, 1996, NRG together with its partners, Ansaldo Energia
SpA, Italy, and P.T. Kiana Metra Tujuhdua, Indonesia, signed a power contract
with PT Perusahaan Listrik Negara (PLN), the state-owned Indonesian Electric
Company, to build, own and operate a 400 Mw, coal-fired power station in
Cilegon, West Java, Indonesia. NRG Energy plans to have a 45% equity interest
in the project. NRG would operate and maintain the power plant for the 30
year life of the project. Construction of the new power plant is due to begin
in mid-1997 and is anticipated to be fully operational by the year 2000.
Ansaldo will have responsibility for construction. The coal-fired power plant
will sell its entire output to the local Java-Bali grid. NRG expects to
invest approximately $65 million in this project.

On December 9, 1996, NRG reached agreement with Indeck Energy Services
(Europe) to purchase a 50% equity interest in the Enfield Energy Centre, a 350
Mw power project located in the North London Borough of Enfield, England in
the United Kingdom (UK). The power station is planned to begin commercial
operations in 1999 and would be jointly developed by NRG and Indeck. The
power station will sell its output to the UK grid. Natural gas will fuel the
plant, which will use an air-cooled condensing system to eliminate any visible
water vapor plume. Because of its proximity to London, local underground
cables will be used to distribute the electricity rather than large overhead
transmission lines. NRG expects to invest approximately $60 million in this
project. Financial close is scheduled for the summer of 1997.

On December 20, 1996, representatives of the Estonian Government, the
state-owned Eesti Energia (EE), and NRG signed a Development and Cooperation
Agreement creating the start of an extensive joint project. The agreement
established the terms on which the joint project to develop and restructure
Estonian power plants (totaling more than 3,000 Mw) will be based. According
to the agreement, the joint project effort of NRG and EE will be completed by
July 1, 1997. The scope of the joint project will be established by several
documents, the most important of which is the business plan of the joint
venture between NRG and EE. The business plan will include an analysis of the
technical and economic potential of the power plants, and an estimation of the
production capacity necessary for meeting the energy needs of Estonia as well
as the financial terms of the joint project. After the joint venture is
created, NRG intends to invest up to $250 million ($50 million in equity and
$200 million of project level financing) to refurbish the Estonian power
generation plants.

NRG, together with two other parties, has filed a plan with the Federal
Bankruptcy Court to acquire the fossil generating assets of Cajun Electric
Power Cooperative (Cajun) of Baton Rouge, Louisiana for approximately $1.1
billion. The Court has also received two other bids for Cajun's assets.
All three bids will be voted upon by Cajun's creditors, with the final
decision subject to confirmation by the Court. NRG expects the bid review
and confirmation process to conclude later in 1997. Under the plan filed
with the Court, NRG would hold a 30% equity interest in Cajun. Pending the
outcome of the bid review process, the specific amounts of project debt, and
equity contributions from NRG and its partners, to fund the proposed
acquisition are subject to change.

On September 29, 1996, a new wholly owned subsidiary of NRG purchased the
senior debt of Mid-Continent Power Company of Pryor, Oklahoma. Mid-Continent
Power Company owns a 120 Mw cogeneration facility in the Mid-America
Industrial Plant in Pryor, Oklahoma. Mid-Continent Power Company supported
the transaction and views NRG's acquisition of its senior debt as a first step
in what it hopes will be successful restructuring of its finances.

Projects With Non-Recurring Earnings Effects

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. The
plant previously operated under long-term Standard Offer 4 (SO4) power sales
contracts with Pacific Gas and Electric (PG&E) which expire in 2017. In early
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 evaluating opportunities
to market power without the prior costs incurred for plant depreciation and
interest on debt, or to sell the assets. 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).
Settlement distributions were paid to NRG from SJVEP in 1995 and 1996.
SJVEP's 10 Mw facility was sold to NEO in late 1996.

In 1994, Michigan Cogeneration Partners Limited Partnership (MCP), a
partnership between subsidiaries of NRG and Cogentrix Energy, Inc., reached
an agreement with Consumers Power Company (Consumers), an electric utility
headquartered in Jackson, Michigan, to terminate the power sales contract
related to a 65 megawatt cogeneration facility being developed by MCP in
Parchment, Michigan. The agreement to terminate the contract required
Consumers to make a payment to MCP of $29.8 million. As a result, NRG
recorded a net pretax gain from the termination of this contract of $9.7
million, which increased NSP's earnings by approximately nine cents per share
in the third quarter of 1994.

NRG's subsidiary, 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, $5
million in 1995 and $1.5 million in 1996 to reflect reductions in the expected
future operating cash flows from the project. NRG has no remaining investment
to recover in the Scoria project.

NRG's subsidiary Graystone Corporation, with several other companies was
formed to build the first privately owned uranium enrichment plant in the
United States. Because of the uncertainty surrounding the ultimate successful
operation of this plant, NRG wrote off its $1.5 million investment in
Graystone during 1994.

Cenerprise, Inc.

NSP's non-regulated wholly owned subsidiary, Cenerprise, Inc. commenced
operations in October 1993 through the acquisition from bankruptcy of selected
assets of Centran Corporation, a natural gas marketing company. Cenerprise,
in addition to marketing natural gas and electricity to end-use customers,
provides customized value-added energy services to customers, both inside NSP
service territory and on a national basis. Cenerprise 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 Cenerprise 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 Cenerprise'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. Cenerprise was one of the first utility
affiliates to obtain this approval from the FERC. Since NSP will be allowing
open access by other electric power providers throughout North America to its
electric transmission lines, Cenerprise's initiative to buy and sell
deregulated electricity will be part of NSP's plan to participate in a more
competitive energy marketplace.

In 1995, Cenerprise and Atlantic Energy Enterprises (AEE) established
Enerval LLC (formerly known as Atlantic CNRG Services LLC). Cenerprise and
AEE each own 50 percent of the venture, which develops new and expanded
natural gas and electric energy products and services, primarily in the
northeast United States. On Feb. 1, 1996, Enerval 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.

In 1995, Cenerprise acquired an 80 percent ownership interest in Kansas
City-based Energy Masters Corporation (EMC). Cenerprise 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. EMC
continues to operate as a separate legal entity, as a subsidiary of
Cenerprise.

On December 9, 1996, Cenerprise acquired an option to purchase Energy
Solutions International (ESI) in 1998. ESI, based in St. Paul, Minnesota, is
a full-service energy management firm operating in 15 states nationwide.

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, 1996, approximately $48 million had
been invested in Eloigne projects, including $15 million in wholly owned
properties (at net book value) and $33 million in equity interests in jointly-
owned projects. These investments and related working capital requirements
have been financed with $36 million of equity capital (including undistributed
earnings) and $25 million of long-term debt (including current maturities).

Completed Eloigne projects as of Dec. 31, 1996, are expected to generate
tax credits of $61.6 million over the 10-year period 1997-2006. Tax credits
recognized in 1996 as a result of these investments were approximately $5.7
million. A proposed "phase-out" of these tax credits was passed by the United
States Congress but vetoed by the President in 1995. The legislation would
have sunset the low-income housing tax credit allocation after Dec. 31, 1997.
Under the vetoed proposal, projects with credits allocated prior to that date
would continue to generate tax credits over the remainder of the 10-year
credit period allowed. No legislation was reintroduced into Congress during
1996 to phase-out low income tax credits.

Seren Innovations, Inc.

A new non-regulated subsidiary of the Company, Seren Innovations, Inc.
(Seren) will offer customers high speed access to information for homes,
businesses and utilities through automated communications systems. Seren will
provide energy management, security control, and business information services
over a variety of communication networks. Seren will also provide utility
companies with high-speed access to individualized information through
automated meter reading and billing services.

In 1997, Seren is contractually obligated to make license payments of
approximately $6 million. In addition, Seren is negotiating network
development contracts with potential equity investments in 1997-99 of
approximately $40 million per year.

Non-Regulated Business Information

(Thousands of dollars,
except per share data) 1996 1995 1994 1993

Operating Results
Operating Revenues $303 903 $313 082 $241 827 $90 531
Operating Expenses (1) (326 332) (327 894) (241 480) (81 480)
Equity in earnings of Unconsolidated affiliates:
Earnings from operations 30 668 28 055 31 595 2 695
Gains from contract terminations 29 850 9 685
Investment and other income---net 10 304 6 518 1 843 1 040
Interest expense (18 834) (9 879) (7 975) (3 146)
Income tax (expense) benefit 16 576 (6 119) (2 591) (3 548)
Net income $ 16 285 $ 33 613 $ 32 904 $ 6 092

Contribution of Non-regulated Businesses to NSP Earnings per Share
NRG Energy, Inc.:
Ongoing operations $0.29 $0.24 $0.40 $0.04
Non-recurring items 0.00 0.22 0.04 0.00
Eloigne Company 0.05 0.02 0.02 0.00
Cenerprise, Inc. (0.12) (0.02) 0.00 0.00
Other (2) 0.02 0.04 0.03 0.05
Total $0.24 $0.50 $0.49 $0.09

(Thousands of dollars) 1996 1995 1994

Equity Investment by Non-regulated Businesses in Unconsolidated Projects at Dec. 31
(Including undistributed earnings and capitalized development costs)

Australian projects $91 350 $81 885 $75 108
German projects 94 806 87 699 55 337
South American and
Latin American projects 92 257 8 140 4 013
Other international projects 16 601 6 780
Affordable housing projects (U.S.) 32 034 25 211 7 148
Other U.S. projects 80 536 54 276 36 152
Total Equity Investment in
Unconsolidated Non-regulated
Projects $407 584 $263 991 $177 758

Additional Equity Invested in
Consolidated Non-regulated
Businesses 79 522 115 276 104 011

Total Net Assets of
Non-regulated Businesses $487 106 $379 267 $281 769

Significant Unconsolidated Non-Regulated Projects at Dec. 31, 1996

Total NRG Mw-
Generation Projects Operating Location Mw Ownership Equity Operator

Gladstone Power Station Australia 1680 37.5% 630 NRG
Schkopau Power Station Germany 960 20.6% 200 Veba Kraftwerke Ruhr A.G.
COBEE Bolivia 162 62% 100 COBEE
NRG Generating (U.S.) Inc. New Jersey, USA 196 42% 82 NRG
MIBRAG mbh Germany 200 33.3% 66 MIBRAG
Sunnyside Cogeneration
Associates Utah, USA 58 50.0% 29 Joint Venture-NRG/Babcock & Wilcox
Scudder Latin American
Power Projects Latin America 254 6.4%-8.8% 19 Stewart & Stevenson/Wartsila
Energy Center Kladno Czech Republic 28 26.5% 7 Energy Center Kladno

Generation Projects Total NRG Mw-
Under Development (3) Location Mw Ownership Equity Operator

Estonia Privatization Estonia 3300 50% 1650 Joint Venture-NRG/Other
Cajun Louisiana, USA 1700 33% 567 NRG
West Java Indonesia 400 45% 180 NRG
Enfield United Kingdom 350 50% 175 Joint Venture/NRG/Other
Collinsville Australia 180 50% 90 NRG

(1) Includes project write-downs of $1.5 million in 1996 and $5.0 million in 1995 and $5.0 million in 1994.
(2) Includes NSP-owned refuse-derived fuel operations managed by NRG.
(3) 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 to take timely corrective actions where past practices have had
a negative impact on the environment. Significant resources are dedicated to
environmental training, monitoring and compliance matters. 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 $708 million on capitalized environmental
improvements to new and existing facilities since 1968. NSP expects to incur
approximately $14 million in capital expenditures and approximately $32
million in operating expenses for compliance with environmental regulations
in 1997. 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 14 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 13 and 14 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.

Several of NSP's operating facilities have asbestos-containing materials,
which represents a potential health hazard to people who come in contact with
it. Governmental regulations specify the 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. Although the ultimate cost and timing
of asbestos removal is not yet known, it is estimated that removal under
current regulations would cost $47 million in 1996 dollars. Depending on the
timing of asbestos removal, such costs would be recorded as incurred as
operating expenses for maintenance projects, capital expenditures for
construction projects or removal costs for demolition projects.

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
$4 million and $12 million.

The Clean Air Act, including 1990 Amendments, (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. Burners at the Company's Sherburne County
Generating Plant (Sherco) unit 2 were upgraded in 1994 to further reduce
emissions of nitrogen oxides. Other expenditures will be necessary on the NSP
system for compliance in the year 2000. Evaluations are currently underway
to determine if changing operating procedures could reduce or eliminate future
capital expenditures.

As part of its Clean Air Act compliance effort, testing of a full scale
prototype wet electrostatic precipitator (Wet ESP) was completed at Sherco in
1996. The Wet ESP equipment was installed in 1995 into one of the plant's
existing scrubber modules to determine its effectiveness in reducing
particulate emissions and lowering opacity. Based on operating test results,
the Company has chosen to convert multiple scrubber modules on Units 1 & 2
to the Wet ESP design. Capital investment to date for the prototype has been
$3 million. The Company estimates total capital expenditures for this project
of $46 million over the period 1996-2000.

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 1998. 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 and October 7, 1996, the Wisconsin Company received Notices
of Violation from the Wisconsin Department of Natural Resources (WDNR) stating
that emissions from unit 2 at the Wisconsin Company's French Island generating
facility had exceeded allowable levels for dioxin. The Company responded by
providing a written response to the WDNR setting forth the Wisconsin Company's
plans for bringing the emission levels back into compliance. The Wisconsin
Company is currently investigating this matter to determine the cause of these
unexpected events. At this time, the Wisconsin Company is unable to predict
whether any fines will be imposed by the WDNR against the Wisconsin 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 the NSP's financial condition or results of
operations.

On February 12, 1996, the Wisconsin Company received a Letter of Non-
compliance (LON) from the WDNR for failing to meet the emission guidelines for
carbon monoxide (CO) at its Bay Front generating facility. The Wisconsin
Company has worked with the WDNR throughout 1996 to establish mutually agreed
upon CO emission limits for the Bay Front facility. As a result, no fines
were assessed from this LON.

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

The EPA or state environmental agencies have designated the Company as
a "potentially responsible party" (PRP) for 13 waste disposal sites to which
the Company allegedly sent hazardous materials. Nine of these 13 sites have
been remediated and, consistent with settlements reached with the EPA and
other PRPs, the Company has paid $1.7 million for its share of the remediation
costs. While these remediated sites will continue to be monitored, the
Company expects that future remediation costs, if any, will be immaterial.
Under applicable law, the Company, along with each PRP, could be held jointly
and severally liable for the total remediation costs of PRP sites. Of the
four unremediated sites, the total remediation costs are currently estimated
to be approximately $18 million. If additional remediation is necessary or
unexpected costs are incurred, the amount could be more than $18 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 in dispute. For these 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 $1.4 million for its share
of future costs for these four sites, including $0.6 million, which is
expected to be paid in 1997. While it is not feasible to determine impact of
PRP site remediation at this time, the amounts accrued represent the best
current estimate of the Company's future liability. 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 remediation costs incurred, but 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 to
predict the timing or amount of any costs associated with sites, other than
those discussed above.

The Wisconsin Company may be involved in the cleanup and remediation at
four sites. Two sites are solid and hazardous waste landfill sites in Eau
Claire and Amery, Wis. The Wisconsin Company contends that it did not dispose
of hazardous wastes in these landfills 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 these matters at this time. The third site is a
landfill in Hudson, Wis., which is one of the PRP waste disposal sites
discussed as part of the Company's sites. The fourth site in Ashland,
Wisconsin adjacent to Lake Superior, contains creosote/coal tar contamination.
In 1995, the WDNR notified the Wisconsin Company that it is a PRP at this
site. At this time, the WDNR has determined that the Company is the only PRP
at this site. The site has three distinct portions - the Company portion of
the site, the Kreher Park portion of the site and the Chequamegon Bay (of Lake
Superior) portion of the site. The 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 portion of the
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 WDNR and the City of Ashland. In February 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. The draft report contains several remediation options that
were scored by the consultant across a variety of parameters. Two options
scored the most technologically and economically feasible, and one of those
is the lowest-cost option for remediation at the Kreher Park portion of the
site. The draft report estimates that this option, which would involve
capping the property and some limited groundwater treatment, would cost
approximately $6 million. In 1996, the WDNR completed a sediment
contamination investigation of the impacted area of the Chequamegon Bay
portion of the site to determine the extent and nature of contamination.
Contamination of the near shore area has been confirmed by the study.

WDNR's consultant is preparing a remedial option study for the entire
Ashland site, including the Wisconsin Company's portion and the two other
adjacent portions. Until this study is completed and more information is
known concerning the extent of the final remediation required by the WDNR, the
remediation method selected, the related costs, the various parties involved,
and the extent of the Wisconsin Company's responsibility, if any, for sharing
the costs, the ultimate cost to the Wisconsin Company and timing of any
payments related to the Ashland site are not determinable. As of December 31,
1996, the Wisconsin Company had recorded an estimated liability of $880,000
for future remediation costs for the Wisconsin Company owned portion of the
site. Actual costs incurred through 1996 were $525,000. The PSCW authorized
recovery of $353,000 over a two year period beginning in 1997, which
represents recovery of actual expenditures through 1995. Based on this PSCW
decision to allow recovery of remediation costs incurred, the Company has
recorded a regulatory asset for the accrued and actual expenditures related
to the Ashland site. The ultimate cleanup and remediation 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, but may be significant.

The Company is continuing to investigate various properties, which it
presently owns or previously owned. The properties were formerly sites of gas
manufacturing, gas storage plants or gas pipelines. The purpose of this
investigation is to determine if waste materials are present, if they are 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 already remediated one
site, which continues to be monitored. The Company has paid $2.5 million to
remediate this site and expects to incur in the future only immaterial
monitoring costs related to this remediated site. Another 14 gas sites remain
under investigation, and the Company 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 was initiated in 1996
to determine the cost and method of cleanup, which is expected to begin in
1997. As of Dec. 31, 1996, the Company has paid $5.4 million on these six
active sites and has recorded an estimated liability of approximately $4.8
million for future costs, 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 at this time the ultimate costs of gas site remediation, the
amounts accrued represent the best current estimate of the Company's future
liability for 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.

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).

Electromagnetic Fields

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 $100 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 material claims asserted against NSP for
adverse health effects or diminution of property values due to EMF.

Contingencies

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, transmission 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 $412 million in 1996, compared to $401 million
in 1995 and $409 million in 1994. These capital expenditures include gross
additions to utility property of $387 million, $386 million and $387 million
for the years ended 1996, 1995 and 1994, respectively. Internally generated
funds could have provided approximately 75 percent of all capital expenditures
for 1996, 85 percent for 1995 and 69 percent for 1994.

NSP's utility capital expenditures (including allowance for funds used
during construction) are estimated to be $420 million for 1997 and $2.0
billion for the five years ended Dec. 31, 2001. Included in NSP's projected
utility capital expenditures is $50 million in 1997 and $280 million during
the five years ended Dec. 31, 2001, for nuclear fuel for NSP's three existing
nuclear units. The remaining capital expenditures through 2001 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 95 percent of the 1997 utility
capital expenditures and approximately 95 percent of the 1997-2001 utility
capital expenditures. Internally generated funds from all operations are
expected to equal approximately 60 percent and 80 percent respectively, of
NSP's total capital requirements (including equity investments in non-
regulated projects as discussed below) anticipated for 1997 and the five-year
period 1997-2001. 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 $157 million in 1996,
$54 million in 1995 and $137 million in 1994 for interests in existing and
additional non-regulated businesses. (See "Non-Regulated Subsidiaries"
herein.) NSP and its subsidiaries continue to evaluate opportunities to
enhance their competitive position and shareholder returns through strategic
acquisitions of existing businesses. Long-term non-regulated 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 $310 million in 1997 and $940 million
for the five-year period 1997-2001. 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 14 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 non-regulated
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 1996 the total number of full- and part-time employees of NSP
was approximately 7,147 and the total number of benefit employees was 6,470.
Of this number approximately 2,800 employees are represented by five local
IBEW labor unions under a three year collective bargaining agreement which
expired Dec. 31, 1996, but was extended to April 30, 1997. Management and
union representatives have reached a tentative agreement on the terms of a new
collective bargaining agreement, subject to approval by the union membership
on April 10, 1997. NSP is not able to predict the outcome at this time.

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.

401(k) changes: NSP currently offers eligible employees a 401(k)
Retirement Savings Plan. In 1994, NSP began matching employees' pre-tax
401(k) contributions. NSP's matching contributions were $4.3 million in 1996,
based on matching up to $900 for each nonbargaining employee and up to $600
for each bargaining employee.

Wage increases: Under a market-based pay structure implemented for
nonbargaining employees in 1994, NSP uses salary surveys that indicate how
other relevant companies pay their employees for comparable positions. In
January 1996, nonbargaining employees received an average wage scale increase
of 4 percent, and bargaining employees received a 4 percent base wage
increase. In January 1997, nonbargaining employees received an average wage
scale increase of 3.9 percent. Wage increases for bargaining employees in
1997 will be determined by the new collective bargaining agreement which is
not yet final, as discussed previously.

EXECUTIVE OFFICERS *
Present Positions and Business Experience
Name Age During the Past Five Years

James J Howard 61 Chairman of the Board, President and Chief
Executive Officer since 12/1/94; and prior thereto
Chairman of the Board and Chief Executive Officer.

Loren L Taylor 50 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.

Edward L Watzl 57 President - NSP Generation since 02/03/97; Vice
President - Nuclear Generation from 09/07/94 to
02/02/97; and prior thereto Prairie Island Site
General Manager.

Keith H Wietecki 47 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 64 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.

Gary R Johnson 50 Vice President & General Counsel since 11/01/91.

Cynthia L Lesher 48 Vice President - Human Resources since 3/01/92; and
prior thereto Director - Power Supply Human
Resources from 8/15/91 to 2/29/92.

Edward J McIntyre 46 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 50 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 51 Vice President, Controller and Chief Information
Officer since 4/22/92; and prior thereto Vice
President and Controller.

Michael D Wadley 40 Vice President - Nuclear Generation since 02/03/97;
Nuclear Plant Manager - Prairie Island from
10/26/95 to 02/02/97; Plant Manager - Prairie
Island from 02/01/93 to 10/25/95; and prior thereto
General Superintendent of Operations - Prairie
Island.

* As of 3/01/97

Item 2 - Properties

The Company's major electric generating facilities consist of the
following:

1996 Output
Station Capability (Millions
and Unit Fuel Installed (Mw) of Kwh)

Sherburne
Unit 1 Coal 1976 712 4 313.8
Unit 2 Coal 1977 712 4 291.6
Unit 3 Coal 1987 514 3 707.3
Prairie Island
Unit 1 Nuclear 1973 514 3 737.9
Unit 2 Nuclear 1974 514 4 485.2
Monticello Nuclear 1971 543 3 872.9
King Coal 1968 567 3 420.5
Black Dog
4 Units Coal/Natural 1952-1960 461 1 235.3
Gas
High Bridge
2 Units Coal 1956-1959 262 1 067.4
Riverside
2 Units Coal 1964-1987 357 1 913.9
Other Various Various 1,954 1 805.1

NSP's electric generating facilities provided 79 percent of its Kwh
requirements in 1996. 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.

At Dec. 31, 1996, NSP had transmission and distribution lines as follows:

Voltage Length (Pole Miles)

500Kv 265
345Kv 734
230Kv 283
161Kv 339
115Kv 1,681
Less than
115 Kv 31,803

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 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
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. (See Note 14 of Notes to
Financial Statements under Item 8 for further discussion of power purchase
commitments.)

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 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 8,505 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 8,389 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.

In 1993, a natural gas explosion occurred on the Company's distribution
system in St. Paul, Minn. In 1995, the National Transportation Safety Board
found little, if any, fault with the Company's actions or conduct. Total
damages related to the explosion 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. Eighteen lawsuits have been filed, including one suit with
multiple plaintiffs. In February 1997, NSP settled six of the lawsuits,
including all of the death and serious burn cases. Most, if not all, of the
settlement will be paid by NSP's insurer. Additional mediation is scheduled
for early 1997. A trial to decide any additional civil liability and the
parties responsible for the explosion is still scheduled for May 1997, with
the damages portion of the trial scheduled for six months thereafter. The
cost incurred by NSP for this matter is the $1 million insurance deductible,
which was accrued in a prior year.

On June 20, 1994, the Company along with other major utilities filed a
lawsuit against the DOE in an attempt to clarify the DOE's obligation to
dispose of spent nuclear fuel beginning not later than January 31, 1998. The
suit was filed in the U.S. Court of Appeals, Washington, D.C. The primary
purpose of the lawsuit was to insure that the Company and its customers
receive timely storage and disposal of spent nuclear fuel in accordance with
the terms of the Company's contract with the DOE. On July 23, 1996, the U.S.
Court of Appeals for the District of Columbia Circuit, affirmed the federal
government's obligation. The court unanimously ruled that the Nuclear Waste
Policy Act creates an unconditional obligation for the DOE to begin acceptance
of spent nuclear fuel by January 31, 1998. The DOE did not seek U.S. Supreme
Court review. On January 31, 1997, the Company, along with 30 other electric
utilities and 45 state agencies, filed another lawsuit against the DOE
requesting authority to withhold payments to the DOE for the permanent
disposal program.

In October 1996, the Hennepin County District Court (the Court) granted,
in part, plaintiffs' motion for class action certification in Hamline Park
Plaza Partnership, et al v, Northern States Power Company. This lawsuit was
commenced by two NSP commercial customers who participated in NSP's Lighting
Efficiency Program (LEP) and now claim that NSP misrepresented the expected
energy savings from this program. The Court limited the class to commercial
and industrial customers who have participated in the LEP since February 1993.
This decision only addresses the procedural issue concerning who may
participate in the lawsuit, and does not constitute a determination about the
merits of plaintiffs' claims. NSP, which is required to participate in the
LEP by virtue of a Minnesota statute, denies all liability with respect to
plaintiffs' claims. Plaintiffs seek damages in excess of $50,000 for their
claims.

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 during the fourth quarter of 1996.

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 1996 and 1995 and the dividends
declared per share during those quarters:

1996 1995
High Low Dividends High Low Dividends

First Quarter $53 3/8 $47 5/8 $.675 $46 3/4 $42 1/2 $.660
Second Quarter 49 5/8 45 1/2 .690 47 3/8 42 7/8 .675
Third Quarter 49 3/4 44 1/2 .690 46 7/8 42 1/2 .675
Fourth Quarter 49 1/8 45 1/2 .690 49 1/2 45 1/8 .675

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, 1996, the payment of cash dividends
on common stock was not restricted except as described in Note 4 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.

1996 1995 1994 1993 1992
Shareholders of record
at year-end 86 337 83 902 85 263 86 404 72 525

Book value per share
at year-end $30.93 $29.74 $28.35 $27.32 $25.91

Shareholders of record as of March 15, 1997 were 86,171.

Item 6 - Selected Financial Data

1996 1995 1994 1993 1992
(Dollars in millions except per share data)

Utility operating
revenues $2 654 $2 569 $2 487 $2 404 $2 160

Utility operating
expenses $2 288 $2 223 $2 178 $2 100 $1 904

Income from continuing
operations before
accounting
change (1) $275 $276 $243 $212 $161

Net income (2) $275 $276 $243 $212 $206

Earnings available
for common stock $262 $263 $231 $197 $190

Average number of
common and equivalent
shares outstanding
(000's) 68 679 67 416 66 845 65 211 62 641

Earnings per average common share:
Continuing operations
before accounting
change (1) $3.82 $3.91 $3.46 $3.02 $2.31
Total (2) $3.82 $3.91 $3.46 $3.02 $3.04

Dividends declared
per share $2.745 $2.685 $2.625 $2.565 $2.495

Total assets $6 637 $6 229 $5 950 $5 588 $5 143

Long-term debt $1 593 $1 542 $1 463 $1 292 $1 300

Ratio of earnings
(from continuing
operations before
accounting change,
excluding undistributed
equity income and
including AFC) to
fixed charges 3.8 3.9 4.0 4.0 3.2

Notes:

(1) Income and earnings from continuing operations exclude an accounting
change in 1992 as discussed below. They include non-recurring items in
1994 and 1995, as discussed in Management's Discussion and Analysis
under Item 7.

(2) 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), Cenerprise, Inc. (Cenerprise) and
Eloigne Company (Eloigne). The Company and its subsidiaries collectively are
referred to herein as NSP.

FINANCIAL OBJECTIVES AND RESULTS

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 1996 was 12.8 percent. Based
on a three-year average, this return places NSP in the top one-fourth of
the industry, which was approximately 12.75 percent. The median three-year
industry average was approximately 11.5 percent. Using total return to
investors (measured by dividends plus stock price appreciation) the total
return on NSP common stock for the most recent five-year period averaged
7.4 percent per year. For the same period, the total return for the
electric industry averaged 7.0 percent. Utility stock prices were adversely
affected by higher interest rates in 1996. The average stock price for the
20 utilities with a AA bond rating declined 4.8 percent. NSP's price
decline was a comparable 6.6 percent. Nine of the AA rated companies had
stock price declines greater than NSP.

- - To increase dividends on a regular basis and maintain a long-term average
payout ratio in the range of 65 to 75 percent. NSP has increased its
dividend for 22 consecutive years. In June 1996, NSP's annualized common
dividend rate was increased by 6 cents per share, or 2.2 percent, from
$2.70 to $2.76. The objective payout ratio is based on long-term earnings
expectations. The dividend payout ratio was 71.5 percent in 1996, within
the objective range.

- - To maintain continued financial strength with a AA bond rating. The
Company's first mortgage bonds continued to be rated AA- by Standard &
Poor's (S&P), AA- by Duff & Phelps, Inc., and AA by Fitch Investors
Service, Inc. Since 1994, Moody's Investors Services (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 excluding Allowance for Funds Used During
Construction (AFC), was 3.7 in 1996. A capital structure consisting of 46.5
percent common equity at year-end 1996 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 the growing profitability
of existing businesses and the addition of new businesses. Businesses owned
by NRG provided 29 cents, or 7.6 percent of NSP's earnings per share from
ongoing operations in 1996, and 24 cents, or 6.5 percent of NSP's earnings
per share from ongoing operations in 1995.

- - To maintain long-term average annual earnings per share 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 3.5 percent in 1996 over 1995 and an
average annual growth rate of 8.1 percent since 1993.

1996 1995 1994 1993
Total earnings
per share $3.82 $3.91 $3.46 $3.02
Less earnings from
non-recurring items 0.22 0.01
Earnings from ongoing
operations $3.82 $3.69 $3.45 $3.02

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. Completion of the merger is subject to
regulatory approvals and other conditions. In addition to this merger
strategy, management's business strategies include:

- - Focusing on the core energy business. The electric and natural gas utility
industries are 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
nonregulated 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 customers and NSP.

- - Increasing nonregulated investments and earnings. Nonregulated businesses
will be an important part of NSP's future. Deregulation of certain aspects
of the utility industry is expected to provide new investment opportunities
in nonregulated businesses. Participation in these opportunities is
expected to improve NSP's total profitability.

FINANCIAL REVIEW

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 1996 and 1995. 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 17 to the Financial Statements and except where specific reference is
made to the proposed merger.

Except for the historical information contained herein, the matters discussed
in the following discussion and analysis, including the statements regarding
the anticipated impact of the proposed merger, are forward-looking statements
that are subject to certain risks, uncertainties and assumptions. Such
forward-looking statements are intended to be identified in this document by
the words "anticipate," "estimate," "expect," "objective," "possible,"
"potential" and similar expressions. Actual results may vary materially.
Factors that could cause actual results to differ materially include, but are
not limited to: general economic conditions, including their impact on
capital expenditures; business conditions in the energy industry; competitive
factors; unusual weather; changes in federal or state legislation; regulatory
decisions regarding the proposed combination of NSP and WEC; the items set
forth below under "Factors Affecting Results of Operations;" and the other
risk factors listed from time to time by the Company in reports filed with the
Securities and Exchange Commission (SEC), including Exhibit 99.01 to the
Company's 1996 report on Form 10-K.

RESULTS OF OPERATIONS

1996 Compared with 1995 and 1994

NSP's 1996 earnings per share from ongoing operations were $3.82, up 13 cents,
or 3.5 percent, from the $3.69 earned in 1995 and up 37 cents, or 10.7
percent, from the $3.45 earned in 1994. Regulated utility businesses generated
earnings of $3.58 per share from ongoing operations in 1996, $3.41 in 1995 and
$3.00 in 1994. Earnings from regulated operations were higher in 1996
primarily due to growth in electric and gas sales and reduced administrative
costs. Partially offsetting these earnings increases were the impacts of less
favorable weather, higher utility operating and depreciation expenses, and
dilutive effects of stock issuances. Nonregulated businesses generated
earnings of 24 cents per share from ongoing operations in 1996, 28 cents in
1995 and 45 cents in 1994. Despite higher NRG earnings from new projects,
nonregulated earnings declined because the price volatility for natural gas
supply had an adverse impact on financial results of Cenerprise. NSP's total
earnings per share, including non-recurring transactions in 1995 and 1994 (as
discussed later), were $3.82 in 1996, $3.91 in 1995 and $3.46 in 1994.

Utility Operating Results

Electric Revenues - Sales to retail customers, which account for more than 90
percent of NSP's electric revenue, increased 1.0 percent in 1996 and 4.2
percent in 1995. Sales in both 1996 and 1995 included net favorable weather
impacts compared with normal average temperatures, but the retail sales impact
for 1996 was less favorable than it was in 1995. Total sales of electricity
decreased 3.0 percent in 1996 and increased 2.9 percent in 1995. Lower sales
to other utilities in 1996 and the loss of several wholesale customers in 1995
and 1996, as discussed later, contributed to the 1996 decrease. Warmer-than-
normal summer weather in 1995 contributed to sales growth compared with
results in 1994, when the summer was cooler than normal.

On a weather-adjusted basis, sales to retail customers are estimated to have
increased 1.5 percent in 1996 and 2.4 percent in 1995. Retail sales growth for
1997 is projected to be 1.8 percent over 1996, or 2.3 percent on a weather-
adjusted basis.

Sales to other utilities decreased 21.6 percent in 1996 after increasing 1.0
percent in 1995. Market conditions and regional transmission system
constraints contributed to the sales decrease in 1996.

The table below summarizes the principal reasons for the electric revenue
changes during the past two years:

(Millions of dollars) 1996 vs. 1995 1995 vs. 1994
Retail sales growth
(excluding weather impacts) $ 29 $ 46
Estimated impact of weather
on retail sales volume (15) 42
Sales to other utilities (20) 1
Wholesale sales (15) (13)
Conservation cost recovery 13 19
Fuel adjustment clause recovery (10) (7)
Other rate changes (5) (2)
Other electric revenue 8 (10)
Total revenue increase (decrease) $(15) $ 76

Electric Production Expenses - Fuel expense for electric generation in 1996
decreased $24.5 million, or 7.5 percent, compared with an increase of $4.5
million, or 1.4 percent, in 1995. The 1996 decrease was primarily due to lower
average fuel costs resulting from a new coal transportation contract in July
1995, and lower plant output caused by decreased electric sales and planned
outages for maintenance and conversion of two plants to peaking status. The
1995 increase primarily was attributable to an increase in output from NSP's
generating plants, resulting from increased sales and fewer scheduled plant
maintenance outages.

Purchased power costs decreased $4.5 million, or 1.9 percent, in 1996 after
decreasing $5.2 million, or 2.1 percent, in 1995. The 1996 decrease primarily
was due to lower demand expenses. The 1995 decrease primarily was due to lower
average market prices and less energy purchased. The level of purchases
declined due to fewer scheduled plant maintenance outages in 1995.

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 1996 increased 13.2
percent compared with 1995 sales, while firm sales in 1995 increased 6.8
percent compared with 1994 sales. The increases in 1996 and 1995 primarily
were due to strong sales growth and favorable impacts of weather. Increased
sales of natural gas resulted in part from the addition of 14,381 new firm gas
customers in 1996, a 3.4 percent increase, and 16,680 new firm gas customers
in 1995, a 4.1 percent increase.

On a weather-adjusted basis, firm gas sales are estimated to have increased
5.1 percent in 1996 and increased 4.6 percent in 1995. Firm gas sales in 1997
are projected to be 6.5 percent lower compared with 1996 sales, which reflect
favorable weather. Firm gas sales in 1997, compared with 1996 sales on a
weather-adjusted basis, are projected to increase by 1.6 percent.

Interruptible sales of gas increased 3.6 percent in 1996 and 15.7 percent in
1995. The increases in both years are the result of favorable gas market
prices that caused large interruptible customers with alternate fuel sources
to use more natural gas. Other gas deliveries, including Viking sales,
increased 5.3 percent in both 1996 and 1995. Viking wholesale gas transmission
deliveries to parties other than NSP increased 7.7 percent in 1996 and 1.1
percent in 1995.

The table below summarizes the principal reasons for the gas revenue changes
during the past two years.

(Millions of dollars) 1996 vs 1995 1995 vs 1994
Sales growth (excluding
weather impacts) $ 25 $ 26
Estimated impact of weather
on firm sales volume 13 7
Purchased gas adjustment
clause recovery 52 (26)
Conservation cost recovery
and other rate changes 6 1
Other 5 (2)

Total revenue increase $101 $ 6

Cost of Gas Purchased and Transported - The cost of gas purchased and
transported increased $78.7 million (30.6 percent) in 1996, primarily due to
a 20.5 percent increase in the per unit cost of purchased gas and higher gas
sendout. The increase in gas sendout reflects increased gas sales, while the
increase in cost per unit of purchased gas reflects changes in market
conditions. The cost of gas purchased and transported decreased $7.1 million
(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 favorable market pricing, while the higher gas sendout reflects sales
growth in 1995 and higher gas sales to off-system customers.

Other Operation, Maintenance and Administrative and General - These expenses,
in total, decreased by $24.5 million (3.7 percent) in 1996, compared with a
decrease of $9.1 million (1.4 percent) in 1995. The lower costs in 1996
largely are due to lower administrative and general costs, partly offset by
higher scheduled plant maintenance outage expenses and provisions for
uncollectible accounts. Administrative and general expenses reflect fewer
employees and decreases in insurance and claims, employee benefit and other
corporate costs. Planned maintenance outages occurred at three major plants
in 1996, compared with only two major plants in 1995. Of the $13 million
increase in Other Operation and Maintenance expenses for 1996, approximately
$9 million is due to additional costs related to the timing of planned outages
at generating plants. The 1995 decrease in total expenses largely is 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 in 1995 were higher employee benefit
costs and higher electric line maintenance costs, mostly for tree trimming and
heat-related repairs. (See Note 8 to the Financial Statements for a summary
of administrative and general expenses.)

Conservation and Energy Management - Expenses increased in both 1996 and 1995
mainly due to higher amortization levels of deferred electric and gas
conservation and energy management program costs. Higher cost levels in 1996
also include the effects of expensing currently (rather than amortizing over
a period of time) new conservation expenditures beginning in 1996. Expense
increases in 1995 also reflect higher deferred costs due to increased customer
participation in NSP's conservation and energy management programs. These
higher amortization and cost levels are recovered concurrently through retail
rate adjustment clauses in the Company's Minnesota jurisdiction, which are
discussed later in the "Regulation" section.

Depreciation and Amortization - The increases in 1996 and 1995 reflect higher
levels of depreciable plant, including new information systems in 1996 with
relatively short useful lives.

Property and General Taxes - Property and general taxes decreased in 1996
primarily due to lower property tax rates, and increased in 1995 primarily due
to property additions and slightly higher property tax rates.

Utility Income Taxes - The variations in income taxes primarily are
attributable to fluctuations in taxable income. (See Note 10 to the Financial
Statements for a detailed reconciliation of the statutory tax rate to NSP's
effective tax rate.)

Nonoperating 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 $1.0 million and $2.6 million in 1996 and 1995, respectively, and
increased AFC-debt by $0.4 million and $1.5 million in 1996 and 1995,
respectively.

Other Income (Expense) - Note 8 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
nonregulated businesses, as discussed in the next section, nonoperating income
(net of expense items and associated income taxes) related to utility
businesses decreased $5.2 million in 1996 and increased $5.6 million in 1995.
The 1996 decrease is primarily due to lower interest income associated with
settlement of tax disputes and with customer financing. The 1995 increase
primarily was due to lower expense levels compared with 1994 costs for
environmental and regulatory contingencies, and public and governmental
affairs costs related to the Prairie Island fuel storage issue. Lower interest
income associated with the Company's settlement of federal income tax disputes
partially offset the 1995 increase.

Interest Charges (Before AFC) - Interest costs recognized for NSP's utility
businesses, including amounts capitalized to reflect the financing costs of
construction activities, were $123.1 million in 1996, $123.4 million in 1995
and $107.1 million in 1994. The slight 1996 decrease is largely due to lower
interest costs on variable rate long-term debt, partially offset by higher
average short-term borrowing levels. The 1995 increase was 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 average short-term debt balance was $265.4 million
in 1996, $208.7 million in 1995 and $204.5 million in 1994.

Nonregulated Business Results

NSP's nonregulated operations include many diversified businesses, such as
independent power production, energy sales and services, industrial heating
and cooling, and energy-related refuse-derived fuel 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 and include NRG and Cenerprise, which are owned and managed
separately.

Operating Revenues and Expenses - The net results of nonregulated businesses
that are consolidated are reported in Other Income (Deductions)-Net on the
Consolidated Statements of Income. (Note 8 to the Financial Statements lists
the individual components of this line item.) Nonregulated operating revenues
decreased $9.2 million, or 3 percent, in 1996 and increased $71.3 million, or
29 percent, in 1995. The 1996 decrease largely is due to curtailment of
Cenerprise's gas trading activities in early 1996. The 1995 increase largely
was due to increased gas marketing sales by Cenerprise. Nonregulated operating
expenses decreased $1.6 million in 1996 primarily due to lower gas costs
associated with Cenerprise's curtailment of gas trading in 1996, partially
offset by losses incurred from Cenerprise's gas trading. NRG's expenses were
higher in 1996 compared with 1995 due to increased project development costs
as NRG pursued several international and domestic projects. Until there is
substantial assurance that a project under development will come to financial
closure, such costs are expensed. Nonregulated operating expenses increased
$86.3 million, or 36 percent, in 1995 primarily due to higher gas costs
associated with Cenerprise gas sales and higher project development expenses
by NRG on pending projects. Nonregulated operating expenses include charges
of $1.5 million in 1996, $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 nonregulated projects, as discussed in Note 2 to the Financial
Statements. Consequently, a large portion of NSP's nonregulated earnings is
reported as Equity in Earnings of Unconsolidated Affiliates on the
Consolidated Statements of Income. Equity in project operating earnings
increased by $1.8 million in 1996 primarily due to first-time earnings from
new NRG projects (Schkopau operations in Germany and NRG Generating in the
U.S.), partially offset by lower equity in earnings, mainly from NRG's MIBRAG
mbh project in Germany. Equity in earnings from MIBRAG decreased in 1996
primarily due to an expected decline in heating briquette and coal sales.
Equity in project operating earnings decreased by $2.8 million in 1995
primarily due to lower earnings from the NRG energy project contract that was
terminated in 1995 (as discussed in the following section) and other domestic
projects, somewhat offset by higher earnings from NRG international energy
projects.

Equity in Gains From Contract Terminations - In 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. NRG recognized a pretax gain of approximately $30
million 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. NRG recognized a pretax gain of
$9.7 million, net of project investment costs, for its share of the contract
termination settlement.

Other Income (Expense) - Other than the operating revenues and expenses of
nonregulated businesses, as discussed previously, nonoperating income (net of
expense items) related to nonregulated businesses increased $3.8 million in
1996 and increased $4.7 million in 1995. The 1996 increase mainly is due to
higher income from NRG temporary cash investments. The 1995 increase primarily
is due to a gain on the sale of Cenerprise 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 debt issued by
nonregulated businesses. The expenses were $18.8 million in 1996, $9.9 million
in 1995 and $8.0 million in 1994. The increase in 1996 is mainly due to
interest on $125 million of NRG long-term debt issued in January 1996. The
increase in 1995 mainly is due to the issuance of long-term debt on new
affordable housing projects by Eloigne.

Income Taxes - The Consolidated Statements of Income include income taxes
related to nonregulated businesses. The results are a net benefit of $16.6
million in 1996, expense of $6.1 million in 1995 and expense of $2.6 million
in 1994. The decrease in 1996 mainly is due to lower income from Cenerprise,
tax effects of higher nonregulated debt levels and higher income tax credits
from Eloigne's affordable housing projects. 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's affordable housing
projects. The effective tax rate for nonregulated businesses 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 10 to the Financial Statements.

Factors Affecting Results of Operations

NSP's results of operations during 1996, 1995 and 1994 primarily were
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 nonregulated businesses are contributing 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 (Merger Agreement) 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, the merger plan was approved by more than 95 percent of the
respective shareholders of the Company and WEC voting 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.
At the time that the Merger Agreement was signed, anticipated cost savings of
the new organization (compared with the continued independent operation of NSP
and WEC) were estimated to be approximately $2 billion over a 10-year period,
net of transaction costs (about $30 million) and costs to achieve the merger
savings (about $122 million). The actual realization of these savings will be
dependent on numerous factors. It is anticipated that the proposed merger will
allow the companies to implement a 1.5 percent reduction in electric retail
rates in most of their jurisdictions effective following the receipt of the
necessary approvals and closing of the merger transaction, and a four-year
rate freeze thereafter for electric retail customers. In addition, the
companies agreed to provide a four-year freeze in wholesale electric rates
effective once the merger is completed.

After the merger, the regulated businesses of NSP and WEC would continue to
operate as utility subsidiaries of Primergy, which would be a registered
holding company 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 nonregulated operations. Also, regulatory authorities may
require the use of an independent transmission system operator (ISO) or
divestiture of certain transmission and/or generation assets. NSP currently
cannot determine if such divestitures would be required by regulators. In
addition, Wisconsin state law limits the total assets of nonutility affiliates
of Primergy, which, as presently interpreted, would affect the growth of
nonregulated 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 goal of NSP and WEC was to complete
the merger by year-end 1996. However, as discussed below, all necessary
regulatory approvals were not obtained by the end of 1996 and, as a result,
the merger was not completed in 1996. NSP and WEC continue to pursue
regulatory approvals, without unacceptable conditions, to allow completion of
the merger as soon as possible in 1997.

The FERC administrative law judge (ALJ), in the merger proceeding, issued an
initial decision on Aug. 29, 1996, recommending approval of the merger
application, subject to NSP and WEC meeting eight conditions. A significant
part of the ALJ's initial decision discusses the design of an ISO. The ALJ's
initial decision specifically rejected the need for divestiture of any
generation or transmission facilities as a requirement for ensuring open and
equal access to the transmission system. In October 1996, NSP and WEC filed
a Unilateral Offer of Settlement (UOS) with the FERC. The UOS includes a
transmission system control agreement and articles and bylaws for establishing
an ISO, intended to meet the requirements of the ALJ's decision and FERC
guidelines. In mid-December 1996, the FERC revised and streamlined its 30-
year-old policy for evaluating public utility mergers, with the changes
designed to expedite the processing of merger applications. The new policy
primarily focuses on three factors in reviewing mergers: the effect on
competition, rates, and state and federal regulation. For pending mergers, the
policy will be applied on a case-by-case basis. NSP and WEC believe the
proposed merger is consistent with the FERC's revised merger policy and are
hopeful that the FERC will simultaneously rule on the UOS and the pending
merger application in the first quarter of 1997.

On April 10, 1996, the Michigan Public Service Commission (MPSC) approved the
merger application through a settlement agreement containing terms consistent
with the merger application. On June 26, 1996, the North Dakota Public Service
Commission (NDPSC) approved the merger application. These state commission
approvals represent two of the four states where approval of the merger is
required.

In June 1996, the Minnesota Public Utilities Commission (MPUC) issued an order
that established the procedural framework for the MPUC's consideration of the
merger. Contested case hearings were ordered for the issues of merger-related
savings, electric rate freeze characteristics, NSP's pre-merger revenue
requirements, Primergy's ability to control the transmission interface between
the Mid-Continent Area Power Pool and the Wisconsin and Upper Michigan area,
and the impact of control of this interface on other Minnesota utilities.
Evidentiary hearings were held from Nov. 20 through Dec. 3, 1996. The
Minnesota Department of Public Service has recommended a rate reduction of 2.0
percent, compared with the 1.5 percent reduction the Company proposed. In
January and February 1997, administrative law judges issued their findings and
recommendations in the Minnesota merger applications. Among other items, they:
found that the projected merger-related cost savings were reasonable;
recommended a four-year rate freeze, with very limited exceptions for rate
changes; concluded that the merger would not provide Primergy with the ability
or incentive to negatively impact competition; and determined the Company's
pre-merger electric rates for Minnesota retail customers may exceed revenue
requirements by $3.5 million, or one-fifth of one percent. The MPUC will
consider the administrative law judges' recommendations along with other
information when it deliberates and decides the case.

On July 24, 1996, the Public Service Commission of Wisconsin (PSCW) held a
prehearing conference on the merger proceeding. At the prehearing conference,
the parties agreed upon an extensive issues list and a schedule for the
hearing. At its open meeting on Aug. 8, 1996, the PSCW revised the schedule
and set hearings to begin Oct. 30, 1996. In October 1996, the PSCW staff filed
testimony with the PSCW proposing various conditions, including potential
divestiture of certain transmission, generation and gas assets and a larger
reduction in electric rates than proposed by NSP and WEC. The staff
recommendations differ materially from the merger terms and conditions
included in the application NSP and WEC originally filed with the PSCW. In
late December 1996, two legislators from Wisconsin asked the PSCW to delay
decisions on all pending utility mergers until the Wisconsin Legislature
rewrites the state's utility merger law. In early January 1997, the PSCW voted
unanimously not to delay its decision. However, later in January, a Dane
County Circuit Court judge ordered the PSCW to delay its decision on the
merger, pending the results of an investigation regarding alleged prohibited
conversations between one of the commissioners and WEC officials. The judge
further ordered the PSCW to investigate the allegations. NSP cannot predict
when the PSCW will resolve the allegations and proceed with deliberations
concerning the proposed merger.

In a related matter, the PSCW in September 1996 issued an order setting
minimum standards for creating an ISO that differ from NSP's and WEC's ISO
proposal. This order was issued as part of a generic electric utility
restructuring process the PSCW started in 1995. Although the restructuring
process is separate from the merger proceedings, the order is related because
the PSCW staff, in its testimony filed in the merger proceeding, as discussed
above, recommended establishing an ISO that meets the standards of the PSCW's
order as a condition of approving the merger. In addition, in September 1996,
the PSCW submitted its ISO order to the FERC with a request that the FERC
require an ISO satisfying the PSCW minimum standards as a condition of FERC
approval of the NSP/WEC merger application. In October 1996, NSP and WEC filed
with the PSCW, as supplemental testimony and exhibits in the merger
proceeding, the same ISO proposal included with the UOS filed with the FERC,
as discussed previously.

On April 5, 1996, NSP and WEC submitted the initial filing to the SEC to
facilitate registration of Primergy under the PUHCA, as amended. Notification
under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended,
was filed with the United States Department of Justice (DOJ) in December 1996.
On Jan. 15, 1997, the DOJ served its second request for information and
documents. NSP and WEC anticipate responding to the second request in March
1997. In October 1995, a request for transfer of nuclear operating licenses
was filed with the Nuclear Regulatory Commission. Approval is expected in
early 1997.

Each of the state filings included a request for deferred accounting treatment
and rate recovery of amortized costs incurred in connection with the proposed
merger. At Dec. 31, 1996, $25.3 million of costs associated with the proposed
merger had been deferred as a component of Intangible and Other Assets. If the
merger is not completed, these costs would be charged to expense.

In addition to the regulatory and other governmental approvals required to
complete 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,
1996, include $106 million of long-term debt and a $10 million credit line
agreement, under which short-term borrowings totalled $3.7 million at Dec. 31,
1996. In January 1997, the PSCW adopted new rules establishing standards of
conduct for retail natural gas utilities in Wisconsin, including the Wisconsin
Company. The rules will necessitate PSCW approval of Primergy's contemplated
regulated gas operating arrangements, on which a portion of the projected
merger savings are based. NSP will timely seek all necessary approvals.

Under the Merger Agreement, completion of the merger is subject to numerous
conditions, that, unless waived by the affected party, must be met, including
but not limited to: the prior receipt of all necessary regulatory approvals
without the imposition of materially adverse terms; the accuracy of each
party's representations and warranties in the Merger Agreement, other than
representations and warranties whose inaccuracy does not result in a material
adverse effect on the business, assets, financial condition, results of
operations or prospects of such party and its subsidiaries taken as a whole;
and no such material adverse effect having occurred, or being reasonably
likely to occur, with respect to either party. In addition, both WEC and NSP
have the right to terminate the Merger Agreement under certain circumstances,
including without limiting the foregoing, the inability to fulfill all
conditions to the closing of the merger at April 30, 1997 (other than receipt
of all regulatory approvals without any materially adverse terms), or the
failure to receive all regulatory approvals without any materially adverse
terms by Oct. 31, 1997. NSP continues to work with WEC to complete the merger.
However, since numerous conditions are beyond its control, NSP cannot state
whether all necessary conditions for completion of the merger will occur.

Regulation - NSP's utility rates are approved by the FERC, the MPUC, the
NDPSC, the PSCW, the MPSC 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 retail 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 in
Minnesota, conservation and energy management program costs. For Wisconsin
electric operations, where cost-of-energy adjustment clauses are not used, the
biennial retail rate review process and an interim fuel cost hearing process
provide the opportunity for rate recovery of 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.

As discussed in Note 1 to the Financial Statements, regulated public utilities
are allowed to record as assets certain costs that would be expensed by
nonregulated enterprises, and to record as liabilities certain gains that
would be recognized as income by nonregulated enterprises. If deregulation or
other changes in the regulatory environment occur, NSP may no longer be
eligible to apply this accounting treatment and may be required to eliminate
such regulatory assets and liabilities from its balance sheet. Such changes
could have a material adverse effect on NSP's results of operations in the
period the write-off is recorded. At Dec. 31, 1996, NSP reported on its
balance sheet approximately $217 million and $162 million of regulatory assets
and liabilities, respectively, that would need to be recognized in the income
statement in the absence of regulation. Included in these regulatory assets
are $96 million of conservation expenditures that are anticipated to be
substantially recovered by the year 2000 based on accelerated recovery
available through resource adjustment clauses to customer rates, as discussed
previously. In addition to potential write-off of regulatory assets and
liabilities, deregulation and competition (as discussed below) may require
recognition of certain "stranded costs" not recoverable under market pricing.
NSP currently is recovering its costs in all regulated jurisdictions and does
not expect to write off to expense any "stranded costs" unless and until
market price levels change, or unless cost levels increase above market price
levels.

Competition - The Energy Policy Act of 1992 (the Act) is a catalyst for
comprehensive and significant changes in the operation of electric utilities,
including increased competition. The Act's reform of the PUHCA promotes
creation of wholesale nonutility power generators and authorizes the FERC to
require utilities to provide wholesale transmission services to third parties.
The legislation allows utilities and nonregulated companies to build, own and
operate power plants nationally and internationally without being subject to
restrictions that previously applied to utilities under the PUHCA. Management
believes this legislation will promote the continued trend of increased
competition in the electric energy markets. NSP plans to continue its efforts
to be a competitively priced supplier of electricity and an active participant
in the competitive market for electricity.

In April 1996, the FERC issued two final rules, Order Nos. 888 and 889, which
may have a significant impact on wholesale markets. Order No. 888, which was
preceded by a Notice of Proposed Rulemaking referred to as the Mega-NOPR,
concerns rules on nondiscriminatory open access transmission service to
promote wholesale competition. Order No. 889 requires public utilities to
implement standards of conduct and use an online information system. These new
open access rules are effective for 1996 and 1997. NSP has made transmission
filings with the FERC and believes it is taking the proper steps to comply
with the new rules as they become effective. NSP continues to be generally
supportive of the FERC's efforts to increase competition.

The FERC's Order No. 888 requires utilities to offer a transmission tariff
that includes network transmission service (NTS) to qualifying network
transmission customers. NTS allows transmission service customers to fully
integrate load and resources on an instantaneous basis, in a manner similar
to NSP's historical integration of its native load and resources. Customers
can elect to participate in the cost-sharing network by requesting NTS service
from NSP. Under NTS, NSP and participating customers share the total annual
transmission cost for their combined joint-use systems, net of related
transmission revenues, based upon each company's share of the total network
load. The expected annual expense increase to NSP, net of cost-sharing
revenues, as a result of offering NTS is estimated to be approximately $27
million for 1997. In 1996, NSP incurred $3 million of NTS costs.

Many states are considering proposals to increase competition in the supply
of electricity. NSP believes the transition to a more competitive electric
industry will be beneficial for all consumers. It is likely that retail
competition will provide more innovative services and lower prices. NSP
supports an orderly transition to an open, fair and efficient competitive
energy market for all customers and suppliers. Like many other states,
regulators in Minnesota and Wisconsin (NSP's primary jurisdictions) are
currently considering plans to restructure the electric utility industry to
promote open and fair competition for retail customers in their states. NSP
believes that, under such restructuring plans, utilities should retain direct
operational responsibility of their transmission and distribution systems, and
that utilities should be permitted to recover the cost of their investments
made under traditional regulation, including any "stranded costs." The PSCW
has voted to adopt a restructuring plan that phases in retail wheeling by
2001. The MPUC has not yet approved a timetable or action plan for retail
electric industry restructuring. NSP supports industry restructuring in
Minnesota, as long as all energy suppliers are treated equally. The timing of
regulatory actions regarding restructuring and their impact on NSP cannot be
predicted at this time and may be significant.

Wholesale Customers - The trend of increased electric supply competition, as
previously discussed, has resulted in significant changes in contract
negotiations with wholesale customers. Because the market is becoming more
competitive, rate discounts and negotiated rates are being offered to satisfy
existing wholesale customers and to attract potential new wholesale customers.
In the past several years, these customers have begun to evaluate a variety
of energy sources to provide their electric supply. Revenues from sales of
electricity to municipal customers totaled approximately $29 million in 1996,
$44 million in 1995 and $57 million in 1994. 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. NSP has been able to partially offset the effects of lost
revenues from these municipal customers by providing transmission services to
them. In addition, NSP has renewed or extended contracts with its remaining
19 municipal customers with terms expiring in the years 1999 through 2005. NSP
has other new or extended contracts with various wholesale customers and is
pursuing extensions of existing wholesale contracts and submitting proposals
to potential new wholesale customers to gain new contracts.

Used Nuclear Fuel Storage and Disposal - In 1994, NSP received legislative
authorization from the state of Minnesota for the use of 17 casks for spent
fuel storage at the Company's Prairie Island nuclear generating facility.
Under the current authorization, NSP will have sufficient storage capacity to
operate the nuclear generating facility until 2003. The first five casks were
authorized in 1994. 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.
The Company has taken steps to fulfill these requirements and has been
authorized by the Minnesota Environmental Quality Board (MEQB) to load casks
six through nine. The MEQB authorized casks six through nine, but terminated
an alternative siting process, which was one of the legislative requirements.
In October 1996, the Prairie Island Dakota Indian Tribe filed suit with the
Minnesota Court of Appeals challenging the actions of the MEQB. The Company
loaded casks six and seven in January 1997.

In addition, the Company and other utilities were successful in a lawsuit
against the U.S. Department of Energy (DOE) to compel it 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. On Jan. 31, 1997,
the Company, along with more than 30 other electric utilities and 45 state
agencies, filed another lawsuit against the DOE requesting authority to
withhold payments to the DOE for the permanent disposal program. However, it
is still unknown when the DOE actually will begin accepting used fuel.
Consequently, the Company continues to rely on interim on-site storage
facilities for the time being. Also, the Company is part of a consortium to
establish a private facility for interim storage of used nuclear fuel, the
availability of which is uncertain at this time. (See Notes 13 and 14 to the
Financial Statements for more information.)

Computer Software Changes for the Year 2000 - Like many other companies, NSP
expects to incur significant software development costs to modify existing
computer programs for the year 2000 and beyond. Assuming NSP's proposed merger
with WEC is completed, the preliminary estimate of NSP's portion of the
operating expenses to be spent on this project, primarily in 1997 and 1998,
is expected to range from $20 million to $25 million. The Company is seeking
regulatory approval to defer and amortize these costs over the four-year rate
freeze proposed as part of the merger application in Minnesota. If the merger
is not completed, the amount of additional development costs necessary to
prepare for the year 2000 is estimated to be approximately $10 million.

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 13 to the Financial
Statements), costs charged to NSP's operating expenses for environmental
monitoring and disposal of hazardous materials and wastes were approximately
$31 million in 1996, $26 million in 1995 and $31 million in 1994, and are
expected to increase to an average annual amount of approximately $33 million
for the five-year period 1997-2001. 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 1996, 1995
and 1994, the Company spent about $10 million, $13 million and $17 million,
respectively, for capital expenditures on environmental improvements at its
utility facilities. In 1997, the Company expects to incur approximately $14
million in capital expenditures for compliance with environmental regulations
and approximately $123 million for the five-year period 1997-2001. These
capital expenditure amounts include the costs of constructing used nuclear
fuel storage casks. (See Notes 13 and 14 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
1996, colder-than-normal weather during the heating season increased earnings
over a normal year by an estimated 16 cents per share. In 1995, unusual
weather, mainly a hot summer, increased earnings over a normal year by an
estimated 21 cents per share. In 1994, mild weather, mainly a cool summer,
reduced earnings from a normal year by an estimated 13 cents per share. The
effect of weather is considered part of NSP's ongoing business operations.

Impact of Nonregulated Investments - A significant portion of NSP's earnings
comes from nonregulated operations, as shown on page 54. NSP expects to
continue investing significant amounts in nonregulated projects, including
domestic and international power production projects through NRG, as described
under Future Financing Requirements. The nonregulated projects in which NRG
has invested carry a higher level of risk than NSP's traditional utility
businesses. Current investments in nonregulated projects are subject to
competition, operating risks, dependence on certain suppliers and customers,
and domestic and foreign environmental and energy regulations. Nonregulated
project investments also may be subject to partnership and government actions
and foreign government, political, economic and currency risks. Future
nonregulated projects will be subject to development risks, including
uncertainties prior to final legal closing, in addition to some or all of the
previously identified risks. 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 projects pursued by NRG that do not materialize. The
aggregate effect of these factors creates the potential for more volatility
in the nonregulated component of NSP's earnings. Accordingly, the historical
operating results of NSP's nonregulated businesses may not necessarily be
indicative of future operating results.

Accounting Changes - The Financial Accounting Standards Board (FASB) has
proposed new accounting standards that may go into effect as soon as 1998. 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 13 to the Financial
Statements.)

Use of Derivatives - Through its nonregulated subsidiaries, NSP uses
derivative financial instruments to hedge the risks of fluctuations in foreign
currency exchange rates 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.)

Union Agreements - Approximately 43 percent of NSP's benefit employees are
represented by five local labor unions under a collective-bargaining
agreement, which expired Dec. 31, 1996, but was extended to April 30, 1997.
Management and union representatives have reached a tentative agreement on the
terms of a new three-year collective-bargaining agreement, subject to approval
by the union membership. NSP is not able to predict the outcome at this time.

Non-Recurring Items - NSP's earnings for 1995 include two significant unusual
or infrequently occurring items. As discussed in the Nonregulated 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 nonregulated 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 $9.7
million gain on termination of a nonregulated cogeneration contract, interest
income from the settlement of a federal income tax dispute, a $9.4 million
charge for pre-1994 postemployment costs associated with adopting FASB
Statement No. 112 and $5 million in asset impairment write-downs for certain
nonregulated energy projects.

Inflation - Inflation at its current level is not expected to materially
affect NSP's prices to customers or returns to shareholders.

LIQUIDITY AND CAPITAL RESOURCES

1996 Financing Requirements - NSP's need for capital funds primarily is
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 nonregulated businesses. Total NSP utility capital expenditures
(including AFC) were $387 million in 1996. Of that amount, $324 million
related to replacements and improvements of NSP's electric system and nuclear
fuel, and $42 million involved construction of natural gas distribution
facilities. NSP companies invested approximately $180 million in 1996 for
equity interests in nonregulated projects and for additions to nonregulated
property. NRG primarily invested in a new domestic project and a new
international project, both of which are listed in Note 2 to the Financial
Statements. Eloigne invested in affordable housing projects, including wholly
owned properties and limited partnership ventures.

1996 Financing Activity - During 1996, 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 resources is based on the relative cost of
each resource, regulatory restrictions and the constraints of NSP's long-range
capital structure objectives. During 1996, 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 1996 remained
sufficient to meet working capital needs, debt service, dividend payout
requirements and nonregulated investment commitments, as well as to fund a
significant portion of construction expenditures. The pretax interest coverage
ratio, excluding AFC, was 3.7 in 1996, 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 75 percent of NSP's total
capital expenditures for 1996 and 75 percent of the $2.0 billion in capital
expenditures incurred for the five-year period 1992-1996.

NSP had approximately $368 million in short-term borrowings outstanding as of
Dec. 31, 1996. Throughout 1996, NSP used short-term borrowings to finance
temporarily a portion of utility capital expenditures and provide for other
NSP cash needs.

In the utility businesses, the Wisconsin Company issued $65 million of first
mortgage bonds and $18.6 million of resource recovery revenue bonds during
1996 to refinance higher-cost debt issues and reduce short-term debt levels.
Viking also issued $5.4 million in long-term debt during 1996 to finance a
construction project.

NSP's 1996 equity investments in nonregulated projects primarily were financed
through internally generated funds and the issuance of debt by nonregulated
subsidiaries. NRG issued $125 million of 7.625 percent unsecured Senior Notes
in 1996 to support equity requirements for projects currently under way and
in development. The Senior Notes were assigned ratings of BBB- by S&P and Baa3
by Moody's. In addition, Eloigne issued approximately $5 million of
nonregulated long-term debt to finance affordable housing project investments.
Project financing requirements, in excess of equity contributions from
investors, were satisfied with project debt and loans from NSP's nonregulated
businesses (mainly NRG). Project debt associated with many of NSP's
nonregulated investments is not reflected in NSP's balance sheet because the
equity method of accounting is used for such investments. (See Note 2 to the
Financial Statements.) Long-term loans made to nonregulated projects are
reflected separately on the balance sheet as Notes Receivable from
Nonregulated Projects.

During 1996, the Company issued new shares of common stock under various stock
plans, including 587,055 new shares under the Dividend Reinvestment and Stock
Purchase Plan (DRSPP), 182,828 new shares under the Employee Stock Ownership
Plan (ESOP) and 118,304 new shares under the Executive Long-Term Incentive
Award Stock Plan.

Future Financing Requirements - Utility financing requirements for 1997-2001
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 $420 million in 1997 and $2.0 billion for the five-year period 1997-
2001. Of the 1997 amount, approximately $330 million is scheduled for electric
utility facilities and approximately $70 million for natural gas facilities,
including Viking. In addition to utility capital expenditures, expected
financing requirements for the five-year period 1997-2001 include
approximately $632 million to retire long-term debt and fund principal
maturities.

Through its subsidiaries, NSP expects to invest significant amounts in
nonregulated projects in the future. Financing requirements for nonregulated
project investments will vary depending on the success, timing and level of
involvement in projects currently under consideration. NSP's potential capital
requirements for nonregulated projects and property are estimated to be
approximately $310 million in 1997 and approximately $940 million for the
five-year period 1997-2001. These amounts include commitments for NRG
investments, as discussed in Note 14 to the Financial Statements, and Eloigne
investments of up to $13 million annually in 1997-2001 for affordable housing
projects. Eloigne expects to finance approximately 30 percent of these
investments in affordable housing projects with equity and approximately 70
percent with long-term debt. In addition to the estimated potential
investments in nonregulated projects as disclosed above, NSP continues to
evaluate opportunities to enhance shareholder returns and achieve long-term
financial objectives through investments in projects or acquisitions of
existing businesses. These investments could cause significant changes to the
capital requirement estimates for nonregulated projects and property. Long-
term nonregulated 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 approved by regulators, 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
nonregulated projects are expected to be financed through internally generated
funds or the Company's issuance of common stock. Financing requirements for
the nonregulated projects, in excess of equity contributions from project
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 1997. 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. Moody's has rated the Company's first mortgage bond ratings 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, as
discussed in Notes 13 and 14 to the Financial Statements. No other rating
agencies changed their ratings of NSP's bonds as a result of this legislation.

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, 1996, with an assumed
interest rate of 7.5 percent, the Company could have issued about $2.4 billion
of additional first mortgage bonds under its indenture, and the Wisconsin
Company could have issued about $333 million of additional first mortgage
bonds under its indenture.

The Company filed a shelf registration for first mortgage bonds with the 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.
NSP also filed a shelf registration for $200 million in grantor trust-
originated preferred securities in December 1996. In January 1997, the Company
issued $200 million of 7.875 percent grantor trust preferred securities. The
proceeds were used to redeem $40 million of preferred stock and reduce short-
term debt levels. Financing costs paid to holders of the trust-originated
preferred securities will be included in expenses in arriving at net income.

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 $474 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 $300 million
to the Company and an additional $75 million to subsidiaries of the Company.
NRG currently is in the process of negotiating a $100 million unsecured
revolving bank credit facility. NSP credit lines make short-term financing
available in the form of bank loans, letters of credit and support for
commercial paper for utility operations.

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, 1996, and remained in compliance with all interest
and dividend coverage requirements.

The Company's Articles of Incorporation authorize an additional 90.9 million
shares of common stock in excess of shares issued at Dec. 31, 1996. 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 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 4 to the Financial Statements for discussion of
stock awards outstanding.) The Company plans to issue market shares for its
DRSPP, ESOP and Executive Long-Term Incentive Award Stock plans in 1997.
Depending on the timing of approvals and outcome of NSP's proposed merger with
WEC, a general stock offering of up to $200 million may occur in 1997. Also,
other offerings may be necessary over the next several years to fund
significant equity investments in nonregulated projects should they occur.

Internally generated funds from utility operations are expected to equal
approximately 95 percent of anticipated utility capital expenditures for 1997
and approximately 95 percent of the $2.0 billion in anticipated utility
capital expenditures for the five-year period 1997-2001. Internally generated
funds from all operations are expected to equal approximately 60 percent and
80 percent of the anticipated total capital requirements for 1997 and the
five-year period 1997-2001, respectively. Because NSP has generally been
reinvesting foreign cash flows in operations outside the United States, the
equity income from foreign investments is not fully available to provide
operating cash flows for domestic cash requirements such as payment of NSP
dividends, domestic capital expenditures and domestic debt service. Through
NRG, NSP is establishing 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 in the future.

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 prior to completion of the merger. While the
Company currently plans to 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.

See Item 14(a)-1 in Part IV for index of financial statements included
herein.

See Note 16 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 sheets and statements
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, 1996 and 1995, and the results
of their operations and their cash flows for the years then ended in
conformity with generally accepted accounting principles. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for the
opinion expressed above. The consolidated financial statements of the Company
and its subsidiaries for the year ended Dec. 31, 1994 were audited by other
independent accountants whose report dated Feb. 8, 1995 expressed an
unqualified opinion on those statements.

/s/

PRICE WATERHOUSE LLP
Minneapolis, Minnesota
Feb. 3, 1997

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Northern States Power Company:

We have audited the accompanying consolidated statements of income, changes
in common stockholders' equity, and cash flows of Northern States Power
Company (Minnesota) and its subsidiaries (the Companies) for the year ended
December 31, 1994, listed in the accompanying table of contents in Item
14(a)1. These consolidated financial statements are the responsibility of the
Companies' management. Our responsibility is to express an opinion on the
consolidated financial statements based on our audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all
material respects, the results of operations and cash flows of the Companies
for the year ended December 31, 1994, in conformity with generally accepted
accounting principles.

/s/

DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 8, 1995

Consolidated Statements of Income

Year Ended Dec. 31

(Thousands of dollars,
except per share data) 1996 1995 1994

Utility Operating Revenues
Electric $2 127 413 $2 142 770 $2 066 644
Gas 526 793 425 814 419 903
Total 2 654 206 2 568 584 2 486 547

Utility Operating Expenses
Fuel for electric
generation 301 201 325 652 321 126
Purchased and interchange
power 240 066 244 593 249 754
Cost of gas purchased and
transported 335 453 256 758 263 905
Other operation 336 506 321 121 316 479
Maintenance 155 830 158 203 170 145
Administrative and general 148 656 186 147 187 996
Conservation and energy
management 69 784 53 466 31 231
Depreciation and amortization 306 432 290 184 273 801
Property and general taxes 232 824 239 433 234 564
Income taxes 161 410 147 148 129 228
Total 2 288 162 2 222 705 2 178 229

Utility Operating Income 366 044 345 879 308 318

Other Income (Expense)
Equity in earnings of
unconsolidated affiliates:
Earnings from operations 31 025 29 217 32 024
Gain from contract
termination 29 850 9 685
Allowance for funds used
during construction---equity 7 595 6 794 4 548
Other income
(deductions)---net (14 026) (7 975) (3 686)
Income taxes on nonregulated
operations and nonoperating
items 14 600 (5 080) (199)
Total 39 194 52 806 42 372

Income Before Interest
Charges 405 238 398 685 350 690

Interest Charges
Interest on utility
long-term debt 101 177 103 298 89 553
Other utility interest
and amortization 21 950 20 151 17 555
Nonregulated interest
and amortization 18 834 9 879 7 975
Allowance for funds used
during construction---debt (11 262) (10 438) (7 868)
Total 130 699 122 890 107 215

Net Income 274 539 275 795 243 475
Preferred Stock Dividends 12 245 12 449 12 364
Earnings Available
for Common Stock $262 294 $263 346 $231 111

Average Number of Common and
Equivalent Shares
Outstanding (000's) 68 679 67 416 66 845

Earnings Per Average
Common Share $3.82 $3.91 $3.46

Common Dividends
Declared per Share $2.745 $2.685 $2.625

See Notes to Financial Statements

Consolidated Statements of Cash Flows

Year Ended Dec. 31

(Thousands of dollars) 1996 1995 1994

Cash Flows from Operating
Activities:
Net income $274 539 $275 795 $243 475
Adjustments to reconcile
net income to cash from
operating activities:
Depreciation and
amortization 335 605 322 296 304 583
Nuclear fuel amortization 45 774 49 778 45 553
Deferred income taxes (30 561) (11 076) (6 101)
Deferred investment tax
credits recognized (9 352) (9 117) (9 501)
Allowance for funds used
during construction
---equity (7 595) (6 794) (4 548)
Undistributed equity in
earnings of unconsolidated
affiliate operations (25 976) (24 305) (23 588)
Undistributed equity in
gain from nonregulated
contract termination (17 565)
Cash used for changes in
certain working capital
items (see below) (58 634) (791) (8 627)
Conservation program
expenditures---net of
amortization (2 854) (21 668) (29 963)
Cash provided by (used for)
changes in other assets
and liabilities 23 518 17 234 (1 042)

Net Cash Provided by
Operating Activities 544 464 573 787 510 241

Cash Flows from Investing
Activities:
Capital expenditures:
Utility plant additions
(including nuclear fuel) (386 655) (386 022) (387 026)
Additions to nonregulated
property (25 807) (14 984) (22 260)
Increase (decrease) in
construction payables (3 716) (12 588) 11 668
Allowance for funds used
during construction---equity 7 595 6 794 4 548
Investment in external
decommissioning fund (40 497) (33 196) (42 677)
Equity investments, loans
and deposits for
nonregulated projects (299 173) (55 884) (133 348)
Collection of loans made
to nonregulated projects 116 126 1 766 459
Other investments---net (15 873) (998) (488)

Net Cash Used for
Investing Activities (648 000) (495 112) (569 124)

Cash Flows from
Financing Activities:
Change in short-term
debt---net issuances
(repayments) 152 173 (22 245) 132 239
Proceeds from issuance
of long-term debt 197 824 277 174 367 184
Loan to ESOP (15 000)
Repayment of long-term
debt, including
reacquisition premiums (67 628) (195 683) (272 097)
Proceeds from issuance
of common stock 41 725 56 185 1 368
Dividends paid (198 234) (191 367) (186 568)

Net Cash Provided by
(Used for) Financing
Activities 125 860 (90 936) 42 126

Net Increase (Decrease) in
Cash and Cash Equivalents 22 324 (12 261) (16 757)
Cash and Cash Equivalents
at Beginning of Period 28 794 41 055 57 812
Cash and Cash Equivalents
at End of Period $51 118 $28 794 $41 055

Cash Provided by (Used for)
Changes in Certain Working
Capital Items:
Customer accounts receivable
and unbilled utility
revenues $(41 495) $(66 311) $14 708
Materials and supplies
inventories (9 891) 14 290 (13 462)
Payables and accrued
liabilities (excluding
construction payables) 1 179 53 141 32 550
Customer rate refunds (1 825) (10 410)
Other (8 427) (86) (32 013)

Net $(58 634) $(791) $(8 627)

Supplemental Disclosures of
Cash Flow Information:
Cash paid during the year for:
Interest (net of amount
capitalized) $121 697 $113 705 $106 867
Income taxes (net of
refunds received) $165 146 $131 452 $170 474

See Notes to Financial Statements

Consolidated Balance Sheets

Dec. 31
(Thousands of dollars) 1996 1995

Assets
Utility Plant
Electric---including construction
work in progress: 1996, $132,705;
1995, $137,662 $6 766 896 $6 553 383
Gas 750 449 710 035
Other 331 441 299 585
Total 7 848 786 7 563 003
Accumulated provision
for depreciation (3 611 244) (3 343 760)
Nuclear fuel---including
amounts in process: 1996,
$6,916; 1995, $34,235 892 484 843 919
Accumulated provision
for amortization (792 146) (752 821)
Net utility plant 4 337 880 4 310 341
Current Assets
Cash and cash equivalents 51 118 28 794
Customer accounts receivable---
net of accumulated provision
for uncollectible accounts:
1996, $10,195; 1995, $4,338 288 330 281 584
Unbilled utility revenues 147 366 112 650
Other receivables 83 324 78 993
Materials and supplies
inventories---at average cost
Fuel 45 013 43 941
Other 109 425 100 607
Prepayments and other 72 647 57 894
Total current assets 797 223 704 463
Other Assets
Equity investments in
nonregulated projects and
other investments 451 223 289 495
Regulatory assets 354 128 374 212
External decommissioning
fund investments 260 756 203 625
Nonregulated property---net of
accumulated depreciation:
1996, $93,320; 1995,
$83,724 192 790 177 598
Notes receivable from
nonregulated projects 75 811 14 560
Other long-term receivables 63 684 68 505
Intangible and other assets 103 405 85 786
Total other assets 1 501 797 1 213 781
Total $6 636 900 $6 228 585

Liabilities and Equity
Capitalization
Common stockholders' equity $2 135 880 $2 027 391
Preferred stockholders'
equity 240 469 240 469
Long-term debt 1 592 568 1 542 286
Total capitalization 3 968 917 3 810 146
Current Liabilities
Long-term debt due within
one year 119 618 25 760
Other long-term debt potentially
due within one year 141 600 141 600
Short-term debt---primarily
commercial paper 368 367 216 194
Accounts payable 236 341 246 051
Taxes accrued 204 348 202 777
Interest accrued 34 722 31 806
Dividends payable on common
and preferred stocks 50 409 48 875
Accrued payroll, vacation
and other 80 995 78 310
Total current liabilities 1 236 400 991 373
Other Liabilities
Deferred income taxes 804 342 841 153
Deferred investment
tax credits 149 606 161 513
Regulatory liabilities 302 647 242 787
Pension and other benefit
obligations 114 312 115 797
Other long-term obligations
and deferred income 60 676 65 816
Total other liabilities 1 431 583 1 427 066

Commitments and Contingent
Liabilities (See Notes 13 and 14)
Total $6 636 900 $6 228 585

See Notes to Financial Statements

Consolidated Statements of Common Stockholders' Equity

Cumulative
Currency
Number of Retained Shares Held Translation
(Dollar amounts Shares Issued Par Value Premium Earnings by ESOP Adjustments
in thousands)

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 (12 364)
Common stock (175 292)
Issuances of common
stock - net 42 567 106 1 262
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 (12 450)
Common stock (180 510)
Issuances of common
stock - net 1 253 790 3 135 53 050
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
Net income 274 539
Dividends declared:
Cumulative preferred stock (12 245)
Common stock (187 521)
Issuances of common
stock - net 887 778 2 219 39 256
Tax benefit from
stock options exercised 369
Loan to ESOP to purchase shares* (15 000)
Repayment of ESOP loan* 6 566
Currency translation adjustments 306
Balance at Dec. 31, 1996 69 063 712 $172 659 $638 719 $1 340 799 $(19 091) $2 794

*Did not affect NSP cash flows

See Notes to Financial Statements

Consolidated Statements of Capitalization

Dec. 31
(Thousands of dollars) 1996 1995

Common Stockholders' Equity
Common stock---authorized
160,000,000 shares of
$2.50 par value; issued
shares: 1996, 69,063,712;
1995, 68,175,934 $172 659 $170 440
Premium on common stock 638 719 599 094
Retained earnings 1 340 799 1 266 026
Leveraged common stock held
by Employee Stock Ownership
Plan (ESOP)---shares at cost:
1996, 381,313; 1995, 229,154 (19 091) (10 657)
Currency translation
adjustments---net 2 794 2 488
Total common stockholders'
equity $2 135 880 $2 027 391

Cumulative Preferred Stock---authorized
7,000,000 shares of $100 par value;
outstanding shares: 1996 and 1995,
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*
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, 1995-2006, 6.63% 19 800** 21 100**
March 1, 2011, Variable Rate 13 700* 13 700*
July 1, 2025, 7 1/8% 250 000 250 000
Total 1 083 500 1 093 600
Less redeemable bonds
classified as current
(See Note 6) (13 700) (13 700)
Less current maturities (101 400) (10 100)
Net $ 968 400 $1 069 800

* Pollution control financing
** Resource recovery financing

See Notes to Financial Statements

Dec. 31
(Thousands of dollars) 1996 1995

Long-Term Debt---continued
First Mortgage Bonds - Wisconsin Company
(less reacquired bonds of $3,365
at Dec. 31, 1995)
Series due:
Oct. 1, 2003, 5 3/4% $40 000 $40 000
April 1, 2021, 9 1/8% 44 635
March 1, 2023, 7 1/4% 110 000 110 000
Dec. 1, 2026, 7 3/8% 65 000
Total $215 000 $194 635

Guaranty Agreements---Minnesota Company
Series due:
Feb. 1, 1995-2003, 5.41% $ 5 500* $ 5 700*
May 1, 1995-2003, 5.69% 23 750* 24 250*
Feb. 1, 2003, 7.40% 3 500* 3 500*
Total 32 750 33 450
Less current maturities (700) (700)
Net $32 050 $32 750

Other 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, 1995-2008, 7.07% 23 050** 24 150**
City of La Crosse, Resource
Recovery Bond---Series due
Nov. 1, 2011, 7 3/4% 18 600**
Nov. 1, 2021, 6% 18 600**
Viking Gas Transmission
Company Senior Notes---Series due
Oct. 31, 2008, 6.4% 25 244 27 378
Nov. 30, 2011, 7.1% 5 370
NRG Energy, Inc. Senior
Notes---Series due
Feb. 1, 2006, 7.625% 125 000
NRG Energy Center, Inc.
(Minneapolis Energy Center)
Senior Secured Notes---Series due
June 15, 2013, 7.31% 76 992 79 326
United Power & Land Notes due
March 31, 2000, 7.62% 7 708 8 542
Various Eloigne Company
Affordable Housing Project
Notes due 1995-2024,
1.0%---9.9% 24 755 20 696
Employee Stock Ownership
Plan Bank Loans due
1995-2002, Variable Rate 17 571 9 874
Miscellaneous 7 533 8 967
Total 528 723 394 433
Less variable rate Becker bonds
classified as current
(See Note 6) (127 900) (127 900)
Less current maturities (17 518) (14 960)
Net $383 305 $251 573

Unamortized discount on
long-term debt-net (6 187) (6 472)

Total long-term debt $1 592 568 $1 542 286

Total capitalization $3 968 917 $3 810 146

* 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 the Company holds a controlling financial
interest, including: the Wisconsin Company; NRG Energy, Inc. (NRG); Viking;
Cenerprise, Inc. (Cenerprise); and Eloigne Company (Eloigne). The Company and
its subsidiaries collectively are referred to herein as NSP. As discussed in
Note 2, 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.

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 and resource adjustment clauses, under which
rates are adjusted to reflect changes in average costs of fuels, purchased
energy, purchased gas, and in Minnesota, conservation and energy management
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. For Wisconsin electric
operations where cost-of-energy adjustment clauses are not used, the biennial
retail rate review process and an interim fuel cost hearing process provide
the opportunity for rate recovery of 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 direct labor and materials,
contracted work, 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 noncash 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 5.5 percent in 1996, 6.0 percent in
1995 and 5.0 percent in 1994. 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 immaterial decreases in annual depreciation accruals for 1996 and
1995.

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 1996 for computer software, 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 3.68 percent in 1996, 3.64 percent in 1995 and 3.55 percent in 1994.

Decommissioning - As discussed in Note 13, 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 decontamination and removal, over the
estimated operating lives of the Company's nuclear plants. The Financial
Accounting Standards Board (FASB) has proposed new accounting standards that
would require the full accrual of nuclear plant decommissioning and certain
other site exit obligations beginning as soon as 1998. (See Note 13 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 13.

Environmental Costs - Accruals for environmental costs are recognized when it
is probable that a liability has been incurred and the amount of the liability
can be reasonably estimated. Costs are charged to expense or deferred as a
regulatory asset based on expected recovery 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 nonnuclear 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 - Under the liability method used by NSP, 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, 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 9. NSP's policy for income taxes related to international operations is
discussed in Note 10.

Investment tax credits were deferred and are being 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.
Income, expense and cash flows are translated at weighted-average rates of
exchange for the period. The resulting currency translation adjustments are
accumulated and reported as a separate component of stockholders' equity.

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, 1996, NSP's translation gains or
losses from foreign currency transactions that have occurred since the
respective foreign investment dates have been immaterial.

Derivative Financial Instruments - NSP's policy is to hedge foreign currency
denominated investments as they are made, where appropriate hedging
instruments are available, to preserve their U.S. dollar value. 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 Cenerprise 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 Cenerprise's
nonregulated 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 costs, unbilled revenues and
actuarially determined benefit costs. As better information becomes available
(or actual amounts are determinable), the recorded estimates are revised.
Consequently, operating results can be affected by revisions to prior
accounting estimates. Recent changes in interest rates have resulted in
changes to actuarial assumptions used in the benefit cost calculations for
postretirement benefits, as discussed in Note 7. Also, the depreciable lives
of certain plant assets are reviewed and, if appropriate, revised each year,
as discussed previously.

Cash Equivalents - NSP considers investments in certain debt instruments
(primarily commercial paper and money market funds) 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 Statement of Financial Accounting Standards (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 9
describes the nature and amounts of these regulatory deferrals.

Stock-Based Employee Compensation - NSP has several stock-based compensation
plans, as described in Note 4. Under the intrinsic-value-based method of
accounting followed by NSP, no compensation expense is recorded for stock
options because there is no difference between the market price and purchase
price at the grant date, which is the measurement date for determining
compensation expense. NSP does, however, record compensation expense for stock
that is awarded to certain employees, but held by NSP until the restrictions
lapse or the stock is forfeited. Effective for 1996, the FASB issued a new
accounting standard, SFAS No. 123---Accounting for Stock-Based Compensation,
which provides an optional accounting method for compensation from stock
option and other stock award programs. NSP did not elect the new optional
accounting method. If the provisions of the optional method had been adopted
as of the beginning of 1995, the effect on net income and earnings per share
for 1996 and 1995 would have been immaterial.

Other Assets - The purchase of various nonregulated entities at a price
exceeding the underlying fair value of net assets acquired has resulted in
recorded goodwill of $20 million ($18 million net of accumulated amortization)
at Dec. 31, 1996. This goodwill and other intangible assets acquired are being
amortized using the straight-line method over periods of five 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 $12 million and deferred merger costs of $25.3
million at Dec. 31, 1996. The financing costs are being amortized over the
remaining maturity period of the related debt.

2. Investments Accounted for by the Equity Method

Through its nonregulated 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
Geographic Economic Placed in
Name Area Interest Service

Various independent power July 1991-
production facilities U.S.A. 45%-50% December 1994

Various affordable housing April 1993-
limited partnerships U.S.A. 20%-99% December 1996

NRG Generating (U.S.)
Inc. (NRGG) U.S.A. 42% April 1996

MIBRAG Mining and Power
Generation Europe 33% January 1994

Gladstone Power Station Australia 37.5% March 1994

Scudder Latin American
Trust for Independent Latin
Power Energy Projects America 25% June 1993

Schkopau Power Station Europe 20.6% January 1996-
July 1996

COBEE Electric Power South America 62%* December 1996

* Not consolidated as NRG intends to divest a portion of its interest.

Summarized Financial Information of Unconsolidated Affiliates - Summarized
financial information for these projects, including interests owned by NSP and
other parties, was as follows (for the years ended and as of Dec. 31):

Results of Operations
(Millions of dollars)
1996 1995 1994

Operating Revenues $958 $790 $778
Operating Income $105 $154 $129
Net Income $89 $160 $117

NSP's Equity in Earnings of
Unconsolidated Affiliates $31 $59 $42

Financial Position
(Millions of dollars)
1996 1995

Current Assets $ 681 $ 762
Other Assets 3 525 2 632
Total Assets $4 206 $3 394

Current Liabilities $ 397 $ 296
Other Liabilities 2 798 2 290
Equity 1 011 808
Total Liabilities and Equity $4 206 $3 394

NSP's Equity Investment in
Unconsolidated Affiliates $410 $266

3. Preferred Securities

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, 1996, the annualized
dividend rates were $5.50 for both series A and series B.

At Dec. 31, 1996, various preferred stock series were callable at prices per
share ranging from $100.00 to $103.75, plus accrued dividends.

On Jan. 31, 1997, NSP issued $200 million in 7.875 percent grantor trust-
originated preferred securities that mature in 2037. A portion of the proceeds
were used to redeem the Company's $6.80 and $7.00 series of preferred stock
in February 1997.

4. 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, 1996, 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 nonqualified stock options and restricted stock. The awards granted
in any calendar year cannot exceed one-half of one percent of the number of
outstanding shares of NSP common stock at the end of the previous calendar
year. When options are exercised, or restricted stock granted, the Company may
either issue new shares or purchase market shares. 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.

Stock options currently granted may be exercised one year from the date of
grant and are exercisable thereafter for up to nine years. The options are
forfeited if employment ceases before the one-year vesting term. If employment
ceases after the one-year vesting term, options will either be forfeited, or
would need to be exercised within three or 36 months, depending on the
circumstances. The exercise price of an option is the market price of NSP
common stock on the date of grant. The plan, in previous years, granted other
types of performance awards, some of which are still outstanding. Most of
these performance awards were valued in dollars, but paid in shares based on
the market price at the time of payment. Transactions under the various
incentive stock programs, with the corresponding weighted average exercise
price, were as follows:

Stock Option and Performance Awards

1996 1995 1994
Average Average Average
(Thousands of shares) Shares Price Shares Price Shares Price

Outstanding Jan. 1 990 $41.97 782 $40.58 537 $39.38
Options granted in January 263 $50.94 278 $45.50 304 $42.19
Other stock awards
Options and awards
exercised (105) $41.98 (64) $40.26 (43) $36.67
Options and awards
forfeited (27) $47.70 (6) $44.58 (14) $42.28
Options and awards
expired (4) $40.00 (2) $39.87
Outstanding at Dec. 31 1 117 $43.97 990 $41.97 782 $40.58
Exercisable at Dec. 31 870 $41.96 716 $40.60 491 $39.59

The following table summarizes information about stock options outstanding at
Dec. 31, 1996.

Range of exercise prices
$33.25-40.94 $42.19-50.94

Options Outstanding:
Number outstanding at
Dec. 31, 1996 244 501 861 759
Weighted-average remaining
contractual life (years) 4.2 7.7
Weighted-average
exercise price $37.22 $45.88

Options Exercisable:
Number exercisable at
Dec. 31, 1996 244 501 614 214
Weighted-average exercise
price $37.22 $43.85

In addition to stock options and performance awards, restricted stock is
granted based on a dollar value of the award. The market price on the date of
grant is used to determine the number of restricted shares awarded. The stock
is held by NSP until the restrictions lapse: 50 percent of the stock will
vest one year from the date of the award and the remaining 50 percent vests
two years from the date of the award. Dividends on the shares held while the
restrictions are in place are reinvested to obtain additional shares, and the
restrictions apply to these additional shares. In each of the years 1994
through 1996, NSP granted restricted stock awards of about 20,000 shares per
year at then-current market prices of NSP stock. Compensation expense related
to these awards was immaterial.

5. Short-Term Borrowings

As of Dec. 31, 1996 and 1995, the Company had approximately $300 million and
$265 million, respectively, of commercial bank credit lines under commitment
fee arrangements. These credit lines make short-term financing available in
the form of bank loans, letters of credit and support for commercial paper
sales. There were no borrowings against these credit lines at Dec. 31, 1996
and 1995. At Dec. 31, 1996 and 1995, credit lines of $75 million and $17
million, respectively, primarily were provided by commercial banks to wholly
owned subsidiaries of the Company. At Dec. 31, 1996, approximately $4 million
in loans against these credit lines were outstanding. In addition, at Dec. 31,
1996 and 1995, $21 million and $10 million, respectively, in letters of credit
were outstanding, which reduced the available credit lines.

At Dec. 31, 1996 and 1995, NSP had $362 million and $216 million,
respectively, in short-term commercial paper borrowings outstanding, and $7
million and $0.6 million, respectively, in short-term bank loans outstanding.
The weighted average interest rates on all short-term borrowings were 5.7
percent as of both Dec. 31, 1996 and Dec. 31, 1995.

6. Long-Term Debt

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 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.

The Company's 2011 series First Mortgage Bonds and the 2019 series City of
Becker Pollution Control Revenue Bonds 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 4.2 percent and 3.6 percent, respectively,
at Dec. 31, 1996. 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 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: 1997,
$119,618,000; 1998, $18,971,000; 1999, $212,369,000; 2000, $117,416,000; and
2001, $163,209,000.

7. 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 expired Dec. 31, 1996, but was extended
to April 30, 1997. Management and union representatives have reached a
tentative agreement on the terms of a new three-year collective-bargaining
agreement, subject to approval by the union membership. NSP is not able to
predict the outcome at this time.

Pension Benefits - NSP has a noncontributory, 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.

NSP's policy is to fully fund into an external trust the actuarially
determined pension costs recognized for ratemaking and financial reporting
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) 1996 1995
Actuarial present value of benefit obligation:
Vested $660 920 $686 403
Nonvested 147 278 155 177

Accumulated benefit obligation $808 198 $841 580

Projected benefit obligation $993 821 $1 039 981
Plan assets at fair value 1 634 696 1 456 530
Plan assets in excess of projected
benefit obligation 640 875 416 549
Unrecognized prior service cost 19 734 20 805
Unrecognized net actuarial gain (651 368) (452 699)
Unrecognized net transitional asset (539) (615)
Net pension asset (liability)
recorded $8 702 $(15 960)

For ratemaking purposes, the Company's pension costs are determined and
recorded under the aggregate-cost actuarial 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) 1996 1995 1994

Service cost-benefits
earned during the period $29 971 $24 499 $27 536
Interest cost on projected
benefit obligation 70 863 69 742 65 107
Actual return on assets (265 370) (344 837) (12 668)
Net amortization and deferral 139 874 240 458 (82 114)

Net periodic pension cost
determined under SFAS No. 87 (24 662) (10 138) (2 139)
Additional costs recognized
due to actions of regulators 23 572 10 454 3 922
Net periodic pension cost
recognized for financial
reporting $(1 090) $316 $1 783

The weighted average discount rate used in determining the actuarial present
value of the projected obligation was 7.5 percent in 1996 and 7 percent in
1995. The rate of increase in future compensation levels used in determining
the actuarial present value of the projected obligation was 5 percent in 1996
and 1995. The assumed long-term rate of return on assets used for cost
determinations under SFAS No. 87 was 9 percent for 1996 and 1995, and 8
percent for 1994. Assumption changes increased 1996 pension costs (determined
under SFAS No. 87) by approximately $12.6 million and decreased 1995 costs by
approximately $21.5 million. Because the Company's pension expense is
determined under the aggregate-cost method (not SFAS No. 87) for ratemaking
and financial reporting purposes, the effects of regulation prevent the
majority of these assumption changes from affecting earnings.

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 $4.3 million in 1996, $3.7 million in 1995 and $2.6 million in 1994.

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. In conjunction with the 1993
adoption of SFAS No. 106-Employers' Accounting for Postretirement Benefits
Other Than Pensions, 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.

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 principally consist of investments in equity
mutual funds and cash equivalents. The funded status of NSP's retiree health
care plan as of Dec. 31 is as follows:

(Thousands of dollars) 1996 1995
APBO:
Retirees $144 180 $145 763
Fully eligible plan participants 23 438 24 406
Other active plan participants 101 065 116 810
Total APBO 268 683 286 979
Plan assets at fair value 15 514 11 583
APBO in excess of plan assets 253 169 275 396
Unrecognized net actuarial loss (12 467) (40 411)
Unrecognized transition obligation (172 480) (183 260)
Net benefit liability recorded $ 68 222 $ 51 725

The assumed health care cost trend rates used in measuring the APBO at Dec.
31, 1996 and 1995, were 9.8 percent and 10.4 percent for those under age 65,
and 7.1 percent and 7.3 percent for those age 65 and over, respectively. 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 14 percent as of
Dec. 31, 1996. 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 7.5 percent for Dec. 31, 1996,
and 7 percent for Dec. 31, 1995, compounded annually. The assumed long-term
rate of return on assets used for cost determinations under SFAS No. 106 was
8 percent for 1996, 1995 and 1994. Assumption changes decreased 1995 costs by
approximately $2.0 million and increased 1996 costs by approximately $1.3
million.

The net annual periodic postretirement benefit cost recorded consists of the
following components:

(Thousands of dollars) 1996 1995 1994
Service cost-benefits
earned during the year $ 6 380 $ 5 206 $ 5 039
Interest cost (on service
cost and APBO) 19 283 19 201 16 092
Actual return on assets (947) (1 046) (147)
Amortization of transition
obligation 10 780 10 780 10 780
Net amortization and deferral 140 406 (340)
Net periodic postretirement
health care cost under
SFAS No. 106 35 636 34 547 31 424
Additional costs recognized
due to actions of regulators 4 033 4 033 4 033
Net postretirement cost
recognized for financial
reporting $39 669 $38 580 $35 457

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 of approximately
$12 million for Minnesota retail customers were 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 1996, 1995 and 1994, which represent
compensation expense, were $4,647,000, $5,059,000 and $5,695,000,
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 5.9 million and 5.7 million
shares of the Company's common stock as of Dec. 31, 1996 and 1995,
respectively. An average of 208,288, 221,066 and 111,845 uncommitted leveraged
ESOP shares were excluded from earnings-per-share calculations in 1996, 1995
and 1994, respectively. The fair value of NSP's leveraged ESOP shares was
approximately the same as cost at Dec. 31, 1996 and 1995.

8. Detail of Certain Income and Expense Items

Administrative and general (A&G) expense for utility operations consists of
the following:

(Thousands of dollars) 1996 1995 1994
A&G salaries and wages $47 546 $48 437 $49 726
Pension, medical and
other benefits---all
utility employees 64 733 81 279 80 693
Information technology,
facilities and
administrative support 21 281 31 863 29 751
Insurance and claims 5 503 13 969 16 771
Other 9 593 10 599 11 055

Total $148 656 $186 147 $187 996

Other income (deductions)---net consist of the following:

(Thousands of dollars) 1996 1995 1994
Nonregulated operations:
Operating revenues and sales $303 903 $313 082 $241 827
Operating expenses* 326 332 327 894 241 480
Pretax operating
income (loss)** (22 429) (14 812) 347
Interest and investment income 15 417 11 953 10 839
Charitable contributions (5 410) (5 314) (5 037)
Environmental and regulatory
contingencies 1 219 1 027 (4 568)
Other---net (excluding
income taxes) (2 823) (829) (5 267)

Total---net expense
before income taxes $(14 026) $ (7 975) $ (3 686)

* Includes nonregulated energy project write-downs of $1.5 million
in 1996, $5.0 million in 1995 and $5.0 million in 1994.

** See "Operating Results" on page 54 for a summary of the total
operating results of nonregulated businesses.

9. 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:

Remaining
Amortization
(Thousands of dollars) Period 1996 1995
AFC recorded in plant
on a net-of-tax basis* Plant Lives $137 412 $146 662
Conservation and energy
management programs* Primarily 4 Years 95 716 98 570
Losses on reacquired
debt Term of New Debt 63 481 63 209
Environmental costs Primarily 11 Years 42 322 45 018
State commission
accounting adjustments* Plant Lives 7 296 7 221
Unrecovered purchased
gas costs 1-2 Years 3 885 5 932
Deferred postretirement
benefit costs 11 Years 1 413 5 568
Other Various 2 603 2 032
Total regulatory assets $354 128 $374 212

Deferred income tax
adjustments $92 390 $83 066
Investment tax credit
deferrals 97 636 104 371
Unrealized gains from
decommissioning investments 43 008 26 374
Pension costs-regulatory
differences 45 080 21 508
Fuel costs, refunds and other 24 533 7 468
Total regulatory liabilities $302 647 $242 787

* Earns a return on investment in the ratemaking process.

10. 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:

1996 1995 1994

Federal statutory rate 35.0% 35.0% 35.0%
Increases (decreases) in tax from:
State income taxes, net of
federal income tax benefit 5.2% 5.1% 5.9%
Tax credits recognized (3.7)% (3.4)% (3.5)%
Equity income from
unconsolidated affiliates (2.6)% (2.5)% (2.5)%
Regulatory differences---
utility plant items 0.9% 1.0% 0.5%
Other---net 0.4% (0.7)%

Effective income tax rate 34.8% 35.6% 34.7%

(Thousands of dollars)

Income taxes are comprised of the following expense (benefit) items:
Included in utility operating expenses:
Current federal
tax expense $154 421 $137 011 $108 652
Current state tax expense 39 923 33 359 34 823
Deferred federal tax expense (19 933) (12 019) (3 450)
Deferred state tax expense (3 958) (2 396) (1 606)
Deferred investment
tax credits (9 043) (8 807) (9 191)
Total 161 410 147 148 129 228

Included in income taxes on nonregulated operations
and nonoperating items:
Current federal tax expense (906) 5 481 3 959
Current state tax expense 712 1 629 923
Current foreign tax expense 616 233 219
Current federal tax credits (8 044) (5 292) (3 548)
Deferred federal tax expense (5 150) 2 646 (835)
Deferred state tax expense (1 520) 693 (209)
Deferred investment
tax credits (308) (310) (310)
Total (14 600) 5 080 199

Total income
tax expense $146 810 $152 228 $129 427

Income before income taxes includes net foreign equity income of $28 million,
$32 million and $26 million in 1996, 1995 and 1994, respectively. Except to
the extent NSP's earnings from foreign operations are subject to current U.S.
income taxes, NSP's management intends to reinvest indefinitely such earnings
in its foreign operations. Accordingly, U.S. income taxes and foreign
withholding taxes have not been provided on a cumulative amount of unremitted
earnings of foreign subsidiaries of approximately $87 million at Dec. 31,
1996. 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 noncurrent
portions) at Dec. 31 were:

(Thousands of dollars) 1996 1995

Deferred tax liabilities:
Differences between book
and tax bases of property $850 139 856 507
Regulatory assets 121 232 124 910
Tax benefit transfer leases 43 481 59 579
Other 23 182 13 338
Total deferred tax liabilities $1 038 034 $1 054 334

Deferred tax assets:
Regulatory liabilities $90 485 $81 427
Deferred investment tax credits 57 239 61 911
Deferred compensation, vacation
and other accrued liabilities
not currently deductible 65 690 62 440
Other 34 509 22 658
Total deferred tax assets $247 923 $228 436
Net deferred tax liability $790 111 $825 898

11. Financial Instruments

Fair Values The estimated Dec. 31 fair values of NSP's recorded financial
instruments are as follows:

1996 1995
Carrying Fair Carrying Fair
(Thousands of dollars) Amount Value Amount Value

Cash, cash equivalents
and short-term
investments $51 118 $51 118 $28 943 $28 943
Long-term
decommissioning
investments $260 756 $260 756 $203 625 $203 625
Long-term debt,
including current
portion $1 853 786 $1 838 408 $1 709 646 $1 781 066

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, mainly debt securities
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 for debt of the same remaining maturities
and credit quality.

Derivatives - NRG has entered into seven 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).
As of Dec. 31, 1996, NRG had $132 million of foreign currency denominated
assets that were hedged by forward foreign currency exchange contracts with
a notional value of $123 million. In addition, NRG had approximately $82
million of foreign currency denominated retained earnings from foreign
projects that were hedged by forward foreign currency exchange contracts with
a notional value of $59 million. 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. In connection with the forward foreign currency
exchange contracts, cash collateral of $16 million was required at Dec. 31,
1996, which is reflected as other current assets on NSP's balance sheet. The
forward foreign currency exchange contracts terminate in 1998 through 2006 and
require foreign currency interest payments by either party during each year
of the contract. If the contracts had been terminated at Dec. 31, 1996, $13.3
million would have been payable by NRG for currency exchange rate changes to
date. Management believes NRG's exposure to credit risk due to nonperformance
by the counterparties to its forward exchange contracts is not significant,
based on the investment grade rating of the counterparties.

Cenerprise has entered into natural gas futures contracts in the notional
amount of $22 million at Dec. 31, 1996. 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 Cenerprise's
natural gas reserves. Cenerprise's futures contracts hedge $22 million in
anticipated natural gas sales in 1997-1998. Margin balances of $1 million at
Dec. 31, 1996, 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 nonperformance by these
counterparties is not significant. If the contracts had been terminated at
Dec. 31, 1996, $0.5 million would have been payable to Cenerprise 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
Notional Effective
Amount Term of Interest
(Millions Swap Dec. 31,
of dollars) Agreement 1996

5 7/8% Series due
Oct. 1, 1997 $100 Maturity 5.73%

5 1/2% Series due
Feb. 1, 1999 $200 Maturity 5.34%

7 1/4% Series due March 1,
March 1, 2023 $ 20 1998 7.89%

Market risks associated with these agreements result from short-term interest
rate fluctuations. Credit risk related to nonperformance 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 market 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, 1996, $2.0 million would
have been payable by the Company, while the present value of the related fixed
rate debt was $3.5 million below 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 Cenerprise natural gas purchases)
and for nonregulated equity investment commitments. At Dec. 31, 1996, letters
of credit of $70 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. 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, 1996 and 1995, was $588,076,000 and $585,625,000,
respectively. The corresponding accumulated provisions for depreciation were
$168,641,000 and $150,022,000.

13. 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. Fuel expense includes DOE fuel disposal assessments of $11.3
million, $12.3 million and $10.6 million for 1996, 1995 and 1994,
respectively. The cumulative amount of such assessments paid by NSP to the DOE
through Dec. 31, 1996, was approximately $240 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 Nuclear Waste Policy Act stipulated that the DOE execute contracts with
utilities that require DOE to begin accepting spent nuclear fuel no later than
Jan. 31, 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. In 1996, the Company and
13 other major utilities were successful in a lawsuit against the DOE to
clarify the DOE's obligation to accept spent nuclear fuel beginning in 1998.
In July 1996, the U.S. Court of Appeals for the District of Columbia Circuit
unanimously ruled that the Nuclear Waste Policy Act creates an unconditional
obligation for the DOE to begin acceptance of spent nuclear fuel by Jan. 31,
1998. The DOE did not seek U.S. Supreme Court review. The ruling is a very
positive development for the industry regarding concerns about the storage and
disposal of used nuclear fuel. In December 1996, the DOE notified commercial
spent fuel owners of an anticipated delay in accepting used nuclear fuel by
the required date of Jan. 31, 1998, and conceded that a permanent storage or
disposal facility will not be available until at least 2010. Because of the
DOE's inadequate progress to provide a permanent repository, the MPUC 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. On Jan. 31, 1997, the Company, along with more than
30 other electric utilities and 45 state agencies, including the Minnesota
Department of Public Service, filed another lawsuit against the DOE requesting
authority to withhold payments to the DOE for the permanent disposal program.
In the meantime, NSP is investigating all of its alternatives for used fuel
storage until a DOE facility is available, including pursuing the
establishment of a private facility for interim storage of used nuclear fuel
as part of a consortium of electric utilities. If on-site temporary storage
at NSP's nuclear plants reaches approved capacity, the Company could seek
interim storage at this or another contracted private facility, if available.

In 1994, the Company received Minnesota legislative approval for additional
on-site temporary storage facilities at NSP's 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, were approved
to 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, or
certain resource commitments are not met, and the Minnesota Legislature
revokes its approval. (See additional discussion of legislative commitments
in Note 14.) NSP has loaded used nuclear fuel into five of the dry cask
containers as of Dec. 31, 1996, and in January 1997, loaded casks six and
seven. 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 2003 and
2004 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.

Nuclear fuel expenses in 1996, 1995 and 1994 include about $4 million, $5
million and $5 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 1996 was $3.8 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 $41
million at Dec. 31, 1996, has been deferred as a regulatory asset and is
reported under the caption Environmental Costs in Note 9.

Plant Decommissioning - Decommissioning of all Company nuclear facilities is
planned for the years 2010-2022, using the prompt dismantlement method. The
Company currently is 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 1997,
would require the full accrual of nuclear plant decommissioning and certain
other site exit obligations beginning as soon as 1998. Using Dec. 31, 1996,
estimates, NSP's adoption of the proposed accounting would result in the
recording of the total discounted decommissioning obligation of $592 million
as a liability, with the corresponding costs capitalized as plant and other
assets 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 an 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 assets (including accumulated earnings) will be funded
through internally generated funds and issuance of Company debt or stock. The
assets held in trusts as of Dec. 31, 1996, primarily consisted of investments
in fixed income securities, such as tax-exempt municipal bonds and U.S.
government securities, which mature in three to 27 years, and common stock of
public companies. The Company plans to reinvest matured securities until
decommissioning commences.

At Dec. 31, 1996, the Company has recorded and recovered in rates cumulative
decommissioning accruals of $422 million. The following table summarizes the
funded status of the Company's decommissioning obligation at Dec. 31, 1996:

(Thousands of dollars) 1996
Estimated decommissioning cost
obligation from most recent
approved study (1993 dollars) $ 750 824
Effect of escalating costs
to 1996 dollars (at 4.5% per year) 105 991
Estimated decommissioning
cost obligation in current dollars 856 815
Effect of escalating costs
to payment date (at 4.5% per year) 987 970
Estimated future decommissioning
costs (undiscounted) $1 844 785
Effect of discounting obligation
(using risk-free interest rate) (1 253 038)
Discounted decommissioning cost obligation 591 747
External trust fund assets at fair value 260 756
Discounted decommissioning obligation
in excess of assets currently held
in external trust $ 330 991

Decommissioning expenses recognized include the following components:

(Thousands of dollars) 1996 1995 1994
Annual decommissioning cost accrual
reported as depreciation expense:
Externally funded $33 178 $33 178 $33 188
Internally funded
(including interest costs) 1 268 1 174 1 109
Interest cost on externally
funded decommissioning obligation 5 246 5 966 3 540
Earnings from external trust funds (6 294) (5 620) (3 539)
Net decommissioning accruals
recorded $33 398 $34 698 $34 298

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.

The MPUC last approved a nuclear decommissioning study and related nuclear
plant depreciation capital recovery request in 1994 based on a 1993 study.
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, as discussed
previously. In October 1996, the Company submitted to the MPUC a revised
nuclear decommissioning study. The filing recommends no change to current
accruals and funding. Approval was received from the MPUC in February 1997.
The Company believes future decommissioning cost accruals will continue to be
recovered in customer rates.

14. 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 13. The additional commitments, which can be met by
building, purchasing or (in the case of biomass) converting generation
resources, are:

Megawatts Contract
Power Type Required Deadline

Wind 100 (1) (Additional) 12/31/96 (2)
Wind 100 (Additional) 12/31/98 (3)
Biomass 50 (Additional) 12/31/98 (4)
Wind 200 (Additional) 12/31/02
Biomass 75 (Additional) 12/31/98 (5)

(1) In addition to 25 megawatts of wind generation currently
installed
(2) Contract pending MPUC approval
(3) Proposals under review by independent evaluator
(4) Developer selected for 75 megawatts; negotiating contract
(5) Solicited bids for remaining 50 megawatts of the 125-megawatt
total biomass requirement

The Company is complying with the requirements of these resource commitments.
Twenty-five megawatts of third-party wind generation has been fully
operational since May 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 Minnesota Development Corporation II (Zond) to supply the wind
energy. The Company resolved a conflict over wind rights and other issues with
an unsuccessful bidder and signed an agreement with Zond allowing construction
of the 100 megawatts of wind power. In October 1996, NSP issued a request for
proposal for another 100-megawatt increment of wind power to fulfill the
cumulative 225-megawatt requirement by Dec. 31, 1998. Bids were received on
Feb. 7, 1997, and are being evaluated by an independent evaluator. A decision
is expected by the summer of 1997.

In July 1996, Minnesota Agri-Power Project was selected to supply 75 megawatts
of farm-grown, closed-loop biomass generation resources to be operational to
the NSP system by Dec. 31, 2001. The 75 megawatts of biomass generation
resources represents Phase I of NSP's legislative commitment to have 125
megawatts of such generation operational by Dec. 31, 2002.

Since 1994, NSP has spent nearly $3 million in a good faith effort to locate
an alternate spent fuel storage site in Goodhue County, as required by the
1994 Minnesota Legislature. In 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
Legislature required. In August 1996, NSP submitted a license application to
the Nuclear Regulatory Commission (NRC) for an alternative site in Goodhue
County to provide temporary storage for spent nuclear fuel. The application
to the NRC was required before casks six through nine could be used at the
existing facility for temporary spent nuclear fuel storage. In October 1996,
the MEQB terminated the alternate spent fuel storage facility siting process
in Goodhue County and certified that NSP has met the requirements necessary
to use the casks at the Prairie Island nuclear generating facility. In October
1996, the Prairie Island Dakota Indian Tribe filed suit with the Minnesota
Court of Appeals challenging the MEQB actions. NSP is defending the legality
of the MEQB's actions. The Tribe also asked that the Court stay the MEQB
actions while the lawsuit is pending, which would prevent NSP from using casks
six through nine. In November 1996, the Court denied the Tribe's motion for
a stay and referred the Tribe to the MEQB. In December 1996, the Tribe then
asked that the MEQB stay its actions while the lawsuit is pending. In December
1996, the MEQB denied the Tribe's request for a stay of further loading of
casks six through nine. In January 1997, the Tribe again requested the Court
stay the MEQB actions during the pendency of the suit. The Company loaded
casks six and seven in January 1997. In January 1997, the Court denied the
Tribe's motion for a stay. A decision by the Court on the merits is expected
in late spring 1997. In November 1996, the Company requested that the NRC put
the license application on hold while the Court reviews the lawsuit by the
Tribe. In December 1996, the NRC granted the Company's request to suspend
review of the application.

Other commitments established by the Legislature include a low-income discount
for electric customers, required conservation improvement expenditures and
various study and reporting requirements to a legislative electric energy task
force. In 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. 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 $420 million in 1997 and $2.0 billion
for 1997-2001. There also are contractual commitments for the disposal of used
nuclear fuel. (See Note 13.)

As of Dec. 31, 1996, NRG is contractually committed to additional equity
investments of approximately $37 million in 1997 and approximately $200
million for 1997-2001 for various international power generation projects. In
addition, in 1996 NRG has provided a $10 million loan commitment to a wholly
owned subsidiary of NRG Generating (U.S.) Inc. (NRGG), an unconsolidated
affiliate of NRG, in order for the NRGG subsidiary to fund its capital
contribution to a cogeneration project currently under construction. No funds
have been disbursed to date on the commitment. However, NRG expects to fund
this loan sometime in 1997. Also in 1996, NRG executed an agreement whereby
NRG is obligated to provide to NRGG, power generation investment opportunities
in the United States over a three-year period. These projects must have in
aggregate, over the three-year term, an equity value of at least $60 million
or a minimum of 150 net megawatts. In addition, NRG has committed to finance
NRGG's investment in the projects to the extent funds are not available to
NRGG on comparable terms from other sources.

Leases - Rentals under operating leases were approximately $29 million, $27
million and $24 million for 1996, 1995 and 1994, 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 1997 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 $415 million of
coal, $20 million of nuclear fuel and $385 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 nonperformance 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 1997-2005 500
Seasonal Diversity Exchanges:
Summer exchanges from MH 1997-2014 150
1997-2016 200
Winter exchanges to MH 1997-2014 150
1997-2015 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 future annual capacity costs
for all MH agreements is estimated to be approximately $58 million. These
commitments to MH represent about 18 percent of MH's system capability in 1997
and account for approximately 10 percent of NSP's 1997 electric system
capability. The risk of loss from nonperformance 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 for the purchase
of summer season capacity and energy. From 1997 through 2001, the Company will
buy 150 megawatts of summer season capacity for $12 million annually. From
2002 through 2015, the Company will purchase 100 megawatts of capacity for $10
million annually. Under the agreement, energy will be priced at the cost of
fuel consumed per megawatt-hour at the Coyote Generating Station in North
Dakota. The Company also has a seasonal (summer) purchase power agreement with
Minnesota Power for the purchase of 173 megawatts, including reserves, from
1997-2000. The annual cost of this capacity will be approximately $2 million.

The Company has agreements with several nonregulated power producers to
purchase electric capacity and associated energy. The 1997 cost of these
commitments for nonregulated installed capacity is approximately $36 million
for 379 megawatts of summer capacity. This annual cost will increase to
approximately $37 million-$44 million for 1998-2018 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 effective May 1997.

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 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 $5 million (five times the amount of its annual premium) and $26
million (generally five 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 $40 million, and other current liabilities include an accrual of $6 million
at Dec. 31, 1996, for estimated costs associated with environmental
remediation. Approximately $34 million of the long-term liability and $4
million of the current liability relate to a DOE assessment for
decommissioning a federal uranium enrichment facility, as discussed in Note
13. 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 13 for further discussion.)

The Environmental Protection Agency (EPA) or state environmental agencies have
designated the Company as a "potentially responsible party" (PRP) for 13 waste
disposal sites to which the Company allegedly sent hazardous materials. Nine
of these 13 sites have been remediated and, consistent with settlements
reached with the EPA and other PRPs, the Company has paid $1.7 million for its
share of the remediation costs. While these remediated sites will continue to
be monitored, the Company expects that future remediation costs, if any, will
be immaterial. Under applicable law, the Company, along with each PRP, could
be held jointly and severally liable for the total remediation costs of PRP
sites. Of the four unremediated sites, the total remediation costs are
currently estimated to be approximately $18 million. If additional remediation
is necessary or unexpected costs are incurred, the amount could be higher. The
Company is not aware of the other parties' inability to pay, nor does it know
if responsibility for any of the sites is in dispute. For these 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 $1.4 million for its share of future
costs for these four sites, including $0.6 million, which is expected to be
paid in 1997. While it is not feasible to determine the ultimate impact of PRP
site remediation at this time, the amounts accrued represent the best current
estimate of the Company's future liability. 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 remediation costs incurred, but 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 to
predict the timing or amount of any costs associated with sites, other than
those discussed above.

The Wisconsin Company potentially may be involved in the cleanup and
remediation at four sites. Two sites are solid and hazardous waste landfill
sites in Eau Claire and Amery, Wis. The Wisconsin Company contends that it did
not dispose of hazardous wastes in these landfills 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 these matters at this time. The third site
is a landfill in Hudson, Wis., which is one of the PRP waste disposal sites
discussed previously as part of the Company's sites. The fourth 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. WDNR's consultant is
preparing a remedial option study for the entire Ashland site, which includes
the Wisconsin Company's portion and two other adjacent portions. Until this
study is completed and more information is known concerning the extent of the
final remediation required by the WDNR, the remediation method selected, the
related costs, the various parties involved, and the extent of the Wisconsin
Company's responsibility, if any, for sharing the costs, the ultimate cost to
the Wisconsin Company and timing of any payments related to the Ashland site
are not determinable. At Dec. 31, 1996, the Company had recorded an estimated
liability of $900,000 for future remediation costs associated with the
Wisconsin Company-owned portion of the Ashland site. Through Dec. 31, 1996,
the Wisconsin Company has incurred approximately $525,000 in actual
expenditures, excluding future remediation costs for this site. Based on a
recent Public Service Commission of Wisconsin decision to allow recovery of
incremental costs incurred for this site in 1997 rates, the Wisconsin Company
has recorded a regulatory asset for the accrued and actual expenditures
related to the Ashland site. The ultimate cleanup and remediation costs at the
Eau Claire, Amery and Ashland sites and the extent of the Wisconsin Company's
responsibility, if any, for sharing such costs are not known at this time, but
may be significant.

The Company also is continuing to investigate various properties, which it
presently or previously owned. The properties were formerly sites of gas
manufacturing, gas storage plants or gas pipelines. The purpose of this
investigation is to determine if waste materials are present, if they are 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 already remediated one
site, which continues to be monitored. The Company has paid $2.5 million to
remediate this site and expects to incur in the future only immaterial
monitoring costs related to this remediated site. Another 14 gas sites remain
under investigation, and the Company 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 was initiated in 1996
to determine the cost and method of cleanup, which is expected to begin in
1997. As of Dec. 31, 1996, the Company has paid $5.4 million on these six
active sites and has recorded an estimated liability of approximately $4.8
million for future costs, 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 at this time the ultimate costs of gas site remediation, the
amounts accrued represent the best current estimate of the Company's future
liability for 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 has
been finalized. NSP has invested significantly over the years to reduce sulfur
dioxide emissions at its plants. No additional capital expenditures are
anticipated to comply with the sulfur dioxide emission limits of the Clean Air
Act. NSP is still evaluating how best to implement the nitrogen oxides
standards. 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 still in the process of implementing some provisions of the
Clean Air Act, its total financial impact is unknown at this time. Capital
expenditures for opacity compliance are considered in the capital expenditure
commitments disclosed previously. The depreciation of these capital costs will
be subject to regulatory recovery 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 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. Although the ultimate cost and timing
of asbestos removal is not yet known, it is estimated that removal under
current regulations would cost $47 million in 1996 dollars. Depending on the
timing of asbestos removal, such costs would be recorded as incurred as
operating expenses for maintenance projects, capital expenditures for
construction projects, or removal costs for demolition projects.

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 1993, a natural gas explosion occurred on the Company's distribution system
in St. Paul, Minn. In 1995, the National Transportation Safety Board found
little, if any, fault with the Company's actions or conduct. Total damages
related to the explosion 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. Eighteen lawsuits have been filed, including one suit with multiple
plaintiffs. In February 1997, NSP settled six of the lawsuits, including all
of the death and serious burn cases. Most, if not all, of the settlement will
be paid by NSP's insurer. Additional mediation is scheduled for early 1997.
A trial to decide any additional civil liability and the parties responsible
for the explosion has been scheduled for May 1997, with the damages portion
of the trial scheduled for six months thereafter. The ultimate costs to the
Company are unknown at this time.

In late 1996, the Company was named in a class action lawsuit commenced by two
NSP commercial customers who claim that the expected energy savings from NSP's
lighting efficiency program were misrepresented. The Company denies all
liability with respect to the customers' claims. However, the ultimate costs
to the Company, if any, are unknown at this time.

15. Segment Information
Year Ended Dec. 31
(Thousands of dollars) 1996 1995 1994
Utility operating income
before income taxes
Electric $469 321 $444 687 $399 185
Gas 58 133 48 340 38 361
Total operating income
before income taxes $527 454 $493 027 $437 546

Utility depreciation
and amortization
Electric $279 828 $266 231 $252 322
Gas 26 604 23 953 21 479
Total depreciation
and amortization $306 432 $290 184 $273 801

Utility capital expenditures
Electric utility $323 532 $317 750 $303 896
Gas utility 42 225 37 215 60 183
Common utility 20 898 31 057 22 947
Total utility capital
expenditures $386 655 $386 022 $387 026

Identifiable assets
Electric utility $4 735 330 $4 751 650 $4 634 511
Gas utility 649 218 600 738 556 975
Total identifiable assets 5 384 548 5 352 388 5 191 486
Other corporate assets* 1 252 352 876 197 758 246
Total assets $6 636 900 $6 228 585 $5 949 732

* Includes equity investments for nonregulated energy projects
outside of the United States of $295 million in 1996, $185
million in 1995 and $134 million in 1994.

16. Summarized Quarterly Financial Data (Unaudited)

Quarter Ended
March 31, June 30, Sept. 30, Dec. 31,
1996 1996 1996 1996

(Thousands of dollars)

Utility operating
revenues $718 709 $592 258 $633 258 $709 981
Utility operating
income 89 277 70 801 105 456 100 510
Net income 67 210 43 382 84 239 79 708
Earnings available
for common stock 64 149 40 321 81 178 76 646
Earnings per average
common share $.94 $.59 $1.18 $1.11
Dividends declared
per common share $.675 $.690 $.690 $.690
Stock prices---high $53 3/8 $49 5/8 $49 3/4 $49 1/8
---low $47 5/8 $45 1/2 $44 1/2 $45 1/2

Quarter Ended
March 31, June 30, Sept. 30, Dec. 31,
1995 1995 1995 1995

(Thousands of dollars)

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

17. Merger Agreement with Wisconsin Energy Corporation (WEC)

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 WEC have entered into an Agreement and Plan of Merger (Merger
Agreement), which provides for a 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,
1996. The unaudited pro forma income statement information gives effect to the
Transaction as if it had occurred on Jan. 1, 1996. 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. Completion of the
Transaction is subject to numerous conditions, many of which are beyond NSP's
control.

Primergy Information - The summarized Primergy pro forma financial information
on page 49 reflects the combination of the historical financial statements of
NSP and WEC after giving effect to the Transaction to form Primergy. A $154
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.

Primergy Pro Forma Financial Information

Pro Forma
NSP WEC Combined

(Millions of dollars,
except per share amounts)
As of Dec. 31, 1996:
Utility Plant---Net $4 338 $3 058 $7 396
Current Assets 797 566 1 363
Other Assets 1 502 1 187 2 535
Total Assets $6 637 $4 811 $11 294

Common Stockholders' Equity $2 136 $1 946 $4 082
Preferred Stockholders' Equity 240 30 270
Long-Term Debt 1 593 1 416 3 009
Total Capitalization 3 969 3 392 7 361
Current Liabilities 1 236 527 1 763
Other Liabilities 1 432 892 2 170
Total Equity & Liabilities $6 637 $4 811 $11 294

For the Year Ended Dec. 31, 1996:
Utility Operating Revenues $2 654 $1 774 $4 428
Utility Operating Income $366 $306 $672
Net Income, after Preferred
Dividend Requirements $262 $218 $480
Earnings per Common Share:
As reported $3.82 $1.97
Using NSP Equivalent
Shares* $3.51
Using Primergy Shares $2.16

* 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 NSP's historical financial statements
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. Due to immateriality, 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.

New NSP Pro Forma Financial Information

Merger
Divestitures- Pro Forma
NSP Net New NSP

(Millions of dollars)
As of Dec. 31, 1996:
Utility Plant---Net $4 338 ($711) $3 627
Current Assets 797 (178) 619
Other Assets 1 502 (756) 746
Total Assets $6 637 ($1 645) $4 992

Common Stockholders'
Equity $2 136 ($812) $1 324
Preferred Stockholders'
Equity 240 240
Long-Term Debt 1 593 (514) 1 079
Total Capitalization 3 969 (1 326) 2 643
Current Liabilities 1 236 (139) 1 097
Other Liabilities 1 432 (180) 1 252
Total Equity &
Liabilities $6 637 ($1 645) $4 992

For the Year Ended Dec. 31, 1996:

Utility Operating
Revenues $2 654 ($221) $2 433
Utility Operating Income $366 ($63) $303
Net Income, after Preferred
Dividend Requirements $262 ($57) $205

Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure

During 1996 there were no disagreements with the Company's independent
public accountants on accounting procedures or accounting and financial
disclosures.

PART III
Item 10 - Directors and Executive Officers of the Registrant

(a)

CLASS II -- Nominees for Terms Expiring in 2000

Richard M. Kovacevich Chairman and Chief Executive Officer, Norwest
Age 53 Corporation, Minneapolis, Minnesota, a holding
Director Since 1990 company for banking institutions, since January
Member of Finance and 31, 1997. Prior thereto, Chairman, President
Power Supply Committees and Chief Executive Officer, since May 1, 1995,
President and Chief Executive Officer, since
January 1, 1993, and President and Chief
Operating Officer, since January 1, 1989.
Also director of Dayton Hudson Corporation,
Norwest Corporation, Petsmart, Inc. and
ReliaStar Financial Corp.

Douglas W. Leatherdale Chairman, President and Chief Executive Officer,
Age 60 The St. Paul Companies, Inc., a worldwide
Director Since 1991 property and liability insurance organization,
Member of Audit and since May 1, 1990. Also director of The John
Corporate Management Nuveen Company and United HealthCare
Committees Corporation.

G. M. Pieschel Chairman of the Board, Farmers and Merchants
Age 69 State Bank, Springfield, Minnesota, a commercial
Director Since 1978 bank, since January 14, 1993. Prior thereto,
Member of Audit and Chief Executive Officer and President of Farmers
Finance Committees and Merchants State Bank.

A. Patricia Sampson Founder of The Sampson Group, Inc., a management
Age 48 development and strategic planning consulting
Director Since 1985 business. She also serves as a consultant with
Member of Audit and Dr. Sanders and Associates, a management and
Finance Committees diversity consulting company, since January 1,
1995. Prior thereto, Chief Executive Officer,
since July 1993 and Executive Director, since
October 1986, Greater Minneapolis Area Chapter
of the American Red Cross.

CLASS III -- Directors Whose Terms Expire in 1998

H. Lyman Bretting President and Chief Executive Officer, C.G.
Age 60 Bretting Manufacturing Company, Inc., Ashland,
Director Since 1990 Wisconsin, a manufacturer of napkin and paper
Member of Finance towel folding machines. Also director of M&I
and Power Supply National Bank of Ashland and Northern States
Committees Power Company (Wisconsin), a wholly-owned
subsidiary of the Company.

David A. Christensen President and Chief Executive Officer, Raven
Age 62 Industries, Inc., Sioux Falls, South Dakota, a
Director Since 1976 manufacturer of reinforced plastics, electronic
Member of Corporate equipment and sewn products. Also director of
Management and Power Norwest Corporation and Raven Industries, Inc.
Supply Committees

Allen F. Jacobson Retired effective November 1, 1991 as Chairman
Age 70 and Chief Executive Officer, Minnesota Mining
Director Since 1983 and Manufacturing Company (3M). Also director
Member of Corporate of Abbot Laboratories, Deluxe Corporation,
Management and Power Minnesota Mining and Manufacturing Company,
Supply Committees Mobil Corporation, Potlatch Corporation,
Prudential Insurance Company of America, Sara
Lee Corporation, Silicon Graphics, Inc., U.S.
West, Inc., and Valmont Industries, Inc.

Margaret R. Preska Distinguished Service Professor, Minnesota State
Age 59 Universities, since February 1, 1992. Prior
Director Since 1980 thereto, President, Mankato State University,
Member of Corporate Mankato, Minnesota, an educational institution.
Management and Power
Supply Committees

CLASS I -- Directors Whose Terms Expire in 1999

W. John Driscoll Retired effective June 30, 1994 as Chairman of
Age 68 the Board, Rock Island Company, St. Paul,
Director Since 1974 Minnesota, a private investment company, in
Member of Audit and which capacity he had served since May 15, 1993.
Corporate Management Prior thereto, President. Also director of
Committees Comshare Inc., The John Nuveen Company, The St.
Paul Companies, Inc. and Weyerhaeuser Company.

Dale L. Haakenstad Retired effective December 31, 1989 as President
Age 69 and Chief Executive Officer, Western States Life
Director Since 1978 Insurance Company, Fargo, North Dakota.
Member of Audit and
Power Supply
Committees

James J. Howard Chairman, President and Chief Executive Officer
Age 61 of the Company since December 1, 1994. Prior
Director Since 1987 thereto, Chairman and Chief Executive
Ex-officio member of Officer of the Company since July 1, 1990.
all Committees Also director of Ecolab Inc., Honeywell
Inc., ReliaStar Financial Corp. and Walgreen
Company.

John E. Pearson Retired effective January 31, 1992 as Chairman,
Age 70 The NWNL Companies, Inc. and Northwestern
Director Since 1983 National Life Insurance Company, a wholly-owned
Member of Corporate subsidiary of The NWNL Companies, Inc. in which
Management and capacity he had served since July 1, 1991. Prior
Finance Committees thereto, Chairman and Chief Executive Officer,
The NWNL Companies, Inc., and Northwestern
National Life Insurance Company.

(b) Reference is made to "Executive Officers" as of March 1, 1997, in Part
I.

(c) The information called for with respect to the identification of certain
significant employees is not applicable to the registrant.

(d) There are no family relationships between the directors and executive
officers listed above. There are no arrangements nor understandings
between any named officer and any other person pursuant to which such
person was selected as an officer.

(e) Each of the officers named in Part I was elected to serve in the office
indicated until the meeting of the Board of Directors preceding the
Annual Meeting of Shareholders in 1997 and until his or her successor is
elected and qualified.

(f) There are no legal proceedings involving directors, nominees for
directors, or officers.

Section 16(a) Beneficial Ownership Reporting Compliance

The Securities Exchange Act of 1934 requires all executive officers and
directors to report any changes in the ownership of common stock of the
Company to the Securities and Exchange Commission, the New York Stock Exchange
and the Company.

Based solely upon a review of these reports and written representations
that no additional reports were required to be filed in 1996, the Company
believes that all reports were filed on a timely basis.

Item 11 - Executive Compensation

COMPENSATION OF EXECUTIVE OFFICERS

The following table sets forth cash and noncash compensation for each of the
last three fiscal years ended December 31, 1996, for services in all
capacities to the Company and its subsidiaries, to the Chief Executive
Officer and the next four highest compensated executive officers of the
Company.

SUMMARY COMPENSATION TABLE

ANNUAL COMPENSATION LONG-TERM COMPENSATION
AWARDS PAYOUTS
(a) (b) (c) (d) (e) (f) (g) (h) (i)
NUMBER OF
OTHER RESTRICTED SECURITIES
ANNUAL STOCK UNDERLYING LTIP ALL OTHER
COMPENSATION AWARDS OPTIONS PAYOUTS COMPENSATION
NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($)(1) ($)(2) ($)(3) AND SARS (#) ($)(4) ($)(5)

JAMES J. HOWARD(6) 1996 622,000 401,000 7,610 478,940 15,264 0 20,056
Chairman, President & 1995 565,000 400,000 8,476 328,830 15,522 0 5,930
Chief Executive Officer 1994 511,300 317,800 3,504 240,311 15,150 0 9,056

EDWARD J. MCINTYRE 1996 241,000 105,000 985 108,450 4,968 0 4,378
Vice President & Chief 1995 222,000 102,000 3,165 75,369 5,123 0 3,274
Financial Officer 1994 205,600 102,700 2,465 61,680 5,117 0 6,438

LOREN L. TAYLOR 1996 215,000 84,000 1,312 96,750 4,432 0 5,201
President, NSP Electric 1995 200,000 93,000 2,008 67,900 4,615 0 10,763
1994 174,583 55,000 1,046 40,942 3,455 0 3,166

DOUGLAS D. ANTONY(7) 1996 215,000 111,000 900 96,750 4,432 0 6,504
President, 1995 200,000 107,000 1,025 67,900 4,615 0 2,290
NSP Generation 1994 163,893 75,100 1,025 41,837 2,942 0 4,419

GARY R. JOHNSON 1996 214,000 86,000 1,074 96,300 4,411 0 7,124
Vice President, General 1995 198,000 89,000 1,074 67,221 4,569 0 2,422
Counsel and 1994 183,600 81,700 9,945 55,080 4,570 0 3,672
Corporate Secretary

(1) This column consists of awards made to each named executive under the
Company's Executive Incentive Compensation Plan.

(2) This column consists of reimbursements for taxes on certain personal
benefits received by the named executives.

(3) Amounts shown in this column reflect the market value of the shares of
restricted stock awarded under the LTIP, except with respect to Mr.
Antony's additional award (discussed below) and are based on the closing
price of the Company's common stock on the date that the awards were made.
Restricted shares earned for 1996 under the Company's LTIP were granted
on January 22, 1997 based on the performance period ending September 30,
1996. As of December 31, 1996, the named executives held the following
as a result of grants under the LTIP: Mr. Howard held 9,543 restricted
shares at a market value of $437,785; Mr. McIntyre held 2,266 restricted
shares at a market value of $103,952; Mr. Antony held 1,877 restricted
shares at a market value of $86,107; Mr. Taylor held 1,866 restricted
shares at a market value of $85,636 and Mr. Johnson held 2,022 restricted
shares at a market value of $92,759. The restricted stock awards vest one
year after the date of grant with respect to fifty (50%) of the shares
and two years after such date with respect to the remaining shares,
conditioned upon the continued employment of the recipient with the
Company. Non-preferential dividends are paid on the restricted shares.

Mr. Antony received an additional 2,200 shares of restricted stock during
1994, which as of December 31, 1996, had a market value of $56,626. These
additional shares vested with respect to 50% of the shares since Mr.
Antony had been continually employed by the Company on October 26, 1996.
The remainder of the shares were forfeited on February 3, 1997 due to Mr.
Antony's resignation from the Company prior to October 26, 1998, the date
on which the remainder would have vested.

The total number of restricted shares awarded during the years 1994, 1995
and 1996 are as follows: 14,540 shares for Mr. Howard, 3,613 shares for
Mr. McIntyre, 4,817 shares for Mr. Antony, 2,637 shares for Mr. Taylor and
3,146 shares for Mr. Johnson.

(4) The Company had no LTIP payouts in 1996.

(5) This column consists of the following: $1,812.89 was contributed by the
Company for the Employee Stock Ownership Plan (ESOP) for each named
executive officer (the Company contribution on behalf of all ESOP
participants, including the named executive officers, was equal to 1.20%
of their covered compensation); the value to each named executive of the
remainder of insurance premiums paid under the Officer Survivor Benefit
Plan by the Company: $14,233 for Mr. Howard, $617 for Mr. McIntyre,
$3,093 for Mr. Johnson, $0 for Mr. Taylor and $3,112 for Mr. Antony
(these figures show an increase over prior years for all of the named
executive officers, except Mr. Taylor, due to a change in the methodology
used by Mullin Consulting, Inc. for determining the actuarial estimate of
the annual value of each named executive's interest in the Officer
Survivor Benefit Plan life insurance policy); imputed income as a result
of life insurance paid by the Company on behalf of each named executive:
$3,110 for Mr. Howard, $453 for Mr. McIntyre, $548 for Mr. Johnson,
$0 for Mr. Taylor and $679 for Mr. Antony; Company matching 401(k) plan
contribution of $900 to each named executive; and, earnings accrued under
the Company Deferred Compensation Plan to the extent such earnings
exceeded the market rate of interest (as prescribed pursuant to the SEC
rules), which was $0 for Mr. Howard, $595 for Mr. McIntyre, $770 for Mr.
Johnson, $2,488 for Mr. Taylor and $0 for Mr. Antony.

(6) Effective as of the completion of the Mergers, Mr. Howard has entered
into an employment agreement with Primergy Corporation pursuant to which
he will serve as the Chairman and Chief Executive Officer of Primergy for a
specified period and will thereafter serve only as Chairman of the Board.
Mr. Howard will receive an annual base salary, short-term and long-term
incentive compensation (including stock options and restricted stock) and
supplemental retirement benefits no less than he received before the
completion of the Mergers, as well as life insurance providing a death
benefit of three times his annual base salary. Mr. Howard also will be
entitled to retirement and welfare benefits on the same basis as other
executives, and certain fringe benefits.

(7) Mr. Antony has retired from the Company effective February 3, 1997.

OPTIONS AND STOCK APPRECIATION RIGHTS (SARS)

The following table indicates for each of the named executives (i) the extent
to which the Company used stock options and SARs for executive compensation
purposes in 1996 and (ii) the potential value of such options and SARs as
determined pursuant to the SEC rules.

OPTIONS AND SARS GRANTED IN 1996

POTENTIAL REALIZABLE
VALUE
AT ASSUMED ANNUAL RATES
OF STOCK PRICE
APPRECIATION
INDIVIDUAL GRANTS FOR OPTION TERM
(a) (b) (c) (d) (e) (f) (g)
% OF TOTAL
OPTIONS AND
OPTIONS/ SARS EXERCISE
SARS GRANTED TO OR BASE
GRANTED(1) EMPLOYEES PRICE EXPIRATION
NAME (#) IN 1996 ($/SH) DATE 5%($)(2) 10%($)(2)

J. Howard 15,264 options 5.80% 50.9375 1/24/06 488,972 1,239,151
E. McIntyre 4,968 options 1.89% 50.9375 1/24/06 159,147 403,308
G. Johnson 4,411 options 1.68% 50.9375 1/24/06 141,303 358,091
L. Taylor 4,432 options 1.68% 50.9375 1/24/06 141,976 359,795
D. Antony 4,432 options 1.68% 50.9375 1/24/06 141,976 359,795

(1) Options were granted on January 24, 1996 and vested on January 24, 1997.
No SARs were awarded for 1996.

(2) The hypothetical potential appreciation shown in columns (f) and (g) for
the named executives is required by the SEC rules. The amounts in these
columns do not represent either the historical or anticipated future
performance of the Company's common stock level of appreciation.

The following table indicates for each of the named executives the number and
value of exercisable and unexercisable options and SARs as of December 31,
1996.

AGGREGATED OPTION AND SAR EXERCISES IN 1996
AND FY-END OPTION/SAR VALUE

(A) (B) (C) (D) (E)
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED IN-THE-MONEY
SHARES OPTIONS AND SARS AT 12/31/96 OPTIONS AND SARS AT
ACQUIRED ON REALIZED (#) -- EXERCISABLE (EX)/ 12/31/96 ($) -- EXERCISABLE (EX)/
NAME EXERCISE(#) VALUE($) UNEXERCISABLE (UNEX) UNEXERCISABLE (UNEX)*

J. Howard N/A N/A 83,095 (ex) 451,498 (ex)
15,264 (unex) -- (unex)
E. McIntyre N/A N/A 27,641 (ex) 148,186 (ex)
4,968 (unex) -- (unex)
G. Johnson N/A N/A 19,698 (ex) 74,951 (ex)
4,411 (unex) -- (unex)
L. Taylor N/A N/A 15,743 (ex) 55,545 (ex)
4,432 (unex) -- (unex)
D. Antony N/A N/A 13,495 (ex) 49,839 (ex)
4,432 (unex) -- (unex)

*Share price on December 31, 1996 was $45.875. Unexercisable options were
granted on January 24, 1996 at a price of $50.9375. No SARs were granted in
1996.

PENSION PLAN TABLE

The following table illustrates the approximate retirement benefits payable
to employees retiring at the normal retirement age of 65 years:

ESTIMATED ANNUAL BENEFITS FOR YEARS OF SERVICE INDICATED
AVERAGE
COMPENSATION YEARS OF SERVICE
(4 YEARS) 5 10 15 20 25 30

$ 50,000 $ 3,500 $ 7,000 $ 10,500 $ 14,000 $ 18,000 $ 21,500
100,000 7,500 15,500 23,000 30,500 38,000 46,000
150,000 11,500 23,500 35,000 47,000 58,500 70,500
200,000 16,000 31,500 47,500 63,000 79,000 95,000
250,000 20,000 40,000 59,500 79,500 99,500 119,500
300,000 24,000 48,000 72,000 96,000 120,000 144,000
350,000 28,000 56,000 84,000 112,500 140,500 168,500
400,000 32,000 64,500 96,500 128,500 160,500 193,000
450,000 36,000 72,500 108,500 145,000 181,000 217,500
500,000 40,500 80,500 121,000 161,000 201,500 242,000
550,000 44,500 89,000 133,000 177,500 222,000 266,500
600,000 48,500 97,000 145,500 194,000 242,500 291,000
650,000 52,500 105,000 157,500 210,000 263,000 315,500
700,000 56,500 113,500 170,000 226,500 283,000 340,000
750,000 60,500 121,500 182,000 243,000 303,500 364,500
800,000 65,000 129,500 194,500 259,500 324,000 389,000
850,000 69,000 138,000 206,500 275,500 344,500 413,500
900,000 73,000 146,000 219,000 292,000 365,000 438,000
950,000 77,000 154,000 231,000 308,000 385,500 462,500
1,000,000 81,000 162,500 243,500 324,500 405,500 487,000
wage base: $62,700

After an employee has reached 30 years of service, no additional years are
used in determining pension benefits. The annual compensation used to
calculate the average compensation shown in this table is based on the
participant's base salary for the year (as shown on the Summary Compensation
Table at column (c)) and bonus compensation paid in that same year (as shown
on the Summary Compensation Table at column (d); see figure for prior year).
The benefit amounts shown are amounts computed in the form of a straight-life
annuity. The amounts are not subject to offset for social security or
otherwise, except as provided in the employment agreement with Mr. Howard, as
described below.

At the end of 1996, each of the executive officers named in the Summary
Compensation Table had the following credited service: Mr. Howard, 9.92
years, Mr. Antony, 27.5 years, Mr. Johnson, 18.08 years, Mr. McIntyre, 23.83
years and Mr. Taylor, 23.58 years.

An employment agreement with Mr. Howard provides that he and his spouse, if
she survives him, will receive combined benefits from the Pension Plan and
supplemental Company payments as though he had completed 30 years of service,
less the pension benefits earned from a former employer.

SEVERANCE PLAN

The executive officers of the Company, including the named executives, are
participants under the NSP Senior Executive Severance Policy which provides
for payment of severance benefits to any participant whose employment is
terminated after April 28, 1995, the effective date of the Policy, and the
second anniversary of the date on which the Mergers are consummated in
accordance with the Merger Agreement (or April 28, 2005, if the Mergers are
not consummated), if the participant's employment is terminated: (i) by the
employer, other than for cause, disability or retirement; (ii) as a result of
the sale of a business by the employer if the purchaser of the business does
not agree to employ the participant on the same terms and conditions as were
in effect before the sale, including comparable severance protection; (iii)
or by the participant within 90 days after a reduction in his or her salary,
a material and adverse diminishment of his or her duties and responsibilities
or of the program of incentive compensation and employee benefits covering
the participant, or a relocation of the participant by more than 50 miles.

The severance benefits under the Policy consist of: (i) a cash lump sum
payment of three years' salary and annual incentive compensation; (ii) a cash
lump sum payment of the actuarial equivalent of the additional retirement
benefits the participant would have earned if he or she had remained employed
for three more years; (iii) continued medical, dental and life insurance
coverage for three years; (iv) outplacement services at a cost of not more
than $30,000 or the use of office space and support for up to one year; (v)
financial planning counseling for two years; and (vi) transfer of title of
the participant's company car, if any, at no cost to the participant. If the
foregoing benefits, when taken together with any other payments to the
participant, result in the imposition of the excise tax on excess parachute
payments, then the severance benefits will be reduced only if the reduction
results in a greater after-tax payment to the participant.

DIRECTOR COMPENSATION

Employees of the Company receive no separate compensation for services as a
director. Directors not employed by the Company receive a $20,000 annual
retainer, or a pro rata portion thereof if service is less than 12 months,
and $1,200 for attendance at each Board meeting and $1,000 for each Committee
meeting attended. A $2,500 annual retainer is paid to each elected Committee
Chairperson. In addition, directors have a deferred compensation and
retirement plan in which they can participate. The deferred compensation plan
provides for deferral of the director fees until after retirement from the
Board of Directors. The retirement plan continues payment of the director's
retainer, at the rate in effect for the calendar quarter immediately
preceding the director's retirement multiplied by 1.2. Benefits continue for
a period equal to the number of calendar quarters served on the Board, up to
40 calendar quarters.

In addition, to more closely align directors' interests with those of NSP's
shareholders, non-employee directors participate in the Stock Equivalent Plan
for Non-employee directors. Under that Plan, directors receive an annual
award of stock equivalent units which each have a value equal to one share of
Common Stock of the Company. Stock equivalent units do not entitle a director
to vote and are only payable in cash upon a director's termination in
service. The stock equivalent units fluctuate in value as the value of Common
Stock of the Company fluctuates. Additional stock equivalent units are
accumulated upon the payment of and at the same value as dividends declared
on Common Stock of the Company. The number of stock equivalents for each
non-employee director is listed in the Share Ownership chart which follows.

SHARE OWNERSHIP OF DIRECTORS, NOMINEES AND NAMED EXECUTIVE OFFICERS

The following table lists the beneficial ownership of NSP Common Stock owned
as of March 1, 1997, by the Company's directors and nominees, the named
executive officers shown in the Summary Compensation Table that follows and
the directors and all executive officers of the Company as a group. None of
these individuals own any shares of NSP Preferred Stock.

ACQUIRABLE
STOCK WITHIN RESTRICTED
NAME OF BENEFICIAL OWNER COMMON STOCK EQUIVALENTS(1) 60 DAYS(2) STOCK TOTAL

H. Lyman Bretting 1,416 112 -- -- 1,528
David A. Christensen 500 112 -- -- 612
W. John Driscoll 2,000 112 -- -- 2,112
Dale L. Haakenstad 741 112 -- -- 853
James J. Howard 25,426 -- 98,360 13,710 137,497
Allen F. Jacobson 712 112 -- -- 824
Richard M. Kovacevich 1,000 112 -- -- 1,112
Douglas W. Leatherdale 300 112 -- -- 412
John E. Pearson 1,519 112 -- -- 1,631
G. M. Pieschel 767 112 -- -- 879
Margaret R. Preska 600 112 -- -- 712
A. Patricia Sampson 410 112 -- -- 522
Douglas D. Antony(3) 5,162 -- 17,927 2,785 25,874
Gary R. Johnson 1,684 -- 23,971 2,768 28,423
Edward J. McIntyre 9,147 -- 32,610 3,114 44,871
Loren L. Taylor 5,490 -- 20,070 2,785 28,346

Directors and executive
officers as a group 85,033 1,232 285,539 36,769 401,341

(1) Represents stock units awarded under the Stock Equivalent Plan for
Non-employee Directors as of March 1, 1997.

(2) Represents exercisable options and performance units under the Executive
Long-Term Incentive Award Stock Plan as of March 1, 1997. Options to
purchase Common Stock of the Company which are exercisable within the next
60 days are 96,363 option shares for Mr. Howard, 17,713 option shares for
Mr. Antony, 23,656 option shares for Mr. Johnson, 31,972 option shares
for Mr. McIntyre and 19,834 option shares for Mr. Taylor. The number of
shares that would have been payable upon the exercise of performance
units on March 1, 1997 are: 1,997 for Mr. Howard, 214 for Mr. Antony,
315 for Mr. Johnson, 638 for Mr. McIntyre and 236 for Mr. Taylor.

(3) Mr. Antony has retired from the Company effective February 3, 1997.

Item 13 - Certain Relationships and Related Transactions
None

PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports on
Form 8-K

(a) 1. Financial Statements Page

Included in Part II of this report:

Report of Independent Accountants for the
years ended Dec. 31, 1996 and 1995. 67

Independent Auditors' Report for the year
ended Dec. 31, 1994. 68

Consolidated Statements of Income
for the three years ended Dec. 31, 1996. 69

Consolidated Statements of Cash Flows for the
three years ended Dec. 31, 1996. 70

Consolidated Balance Sheets, Dec. 31, 1996 and 1995. 71

Consolidated Statements of Changes in Common
Stockholders' Equity for the three years ended
Dec. 31, 1996. 72

Consolidated Statements of Capitalization,
Dec. 31, 1996 and 1995. 73

Notes to Financial Statements. 75

(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).

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* Dec. 1, 1996 (Exhibit 4.01 to Form 8-K dated December 12,
1996, File No. 10-3140).

4.62* NSP Employee Stock Ownership Plan. (Exhibit 4.60 to Form 10-
K for the year 1994, File No. 1-3034).

10.01* 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).

10.02* 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).

10.03* 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).

10.04* 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).

10.05* 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).

10.06* 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).

10.07* 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).

10.08* 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

10.09* Executive Long-Term Incentive Award Stock Plan. (Exhibit
10.10 to Form 10-K for 1988, File No. 1-3034).

10.10* 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).

10.11* 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).

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 1997.

12.01 Statement of Computation of Ratio of Earnings to Fixed Charges.

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 Statement pursuant to Private Securities Litigation Reform Act of
1995.

99.02* Press Release, dated May 1, 1995, of NSP (Exhibit (99)-1 to
Form 8-K dated April 28, 1995, File No. 1-3034).

99.03 Unaudited Pro Forma Combined Condensed Balance Sheets for
Primergy Corporation at Dec. 31, 1996 and Unaudited Pro Forma
Combined Condensed Statements of Income for the three years
ended Dec. 31, 1996.

99.04 Unaudited Pro Forma Condensed Balance Sheet for New NSP at
Dec. 31, 1996 and Unaudited Pro Forma Condensed Statements
of Income for the three years ended Dec. 31, 1996.

99.05* Audited Financial Statements of Wisconsin Energy Corporation.
(Item 8 of Wisconsin Energy Corporation's Annual Report on
Form 10-K for the fiscal year ended Dec. 31, 1996, 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,
1996, or between Dec. 31, 1996 and the date of this report.

Nov. 14, 1996 (Filed Nov. 15, 1996) - Item 5. Other
Events. Re: Disclosure of NRG Energy, Inc.'s definitive
purchase agreement with Bolivian Power Company Limited
for the purchase of outstanding common stock.

Dec. 18, 1996 (Filed Jan. 8, 1997) - Item 5. Other Events.
Re: Disclosure of expiration of tender offer for the
outstanding shares of Bolivian Power Company Limited.

Dec. 31, 1996 (Filed Jan. 24, 1997) - Item 5. Other Events.
Re: Disclosure of expiration and extension of expired
collective bargaining agreements between NSP and NSP
represented employees. Disclosure of NSP's 1996 financial
results.

Jan. 21, 1997 (Filed Jan. 21, 1997) - Item 5. Other Events.
Re: Disclosure of NSP's non-binding letter of intent with
TransCanada Gas Pipeline, Ltd., regarding a proposed
expansion and transaction involving Viking Gas Transmission
Company.

Jan. 28, 1997 (Filed Jan. 31, 1997) - Item 5. Other Events.
Re: Disclosure of offering by NSP Financing I of
$200,000,000 of 7 7/8% Trust Originated Preferred
Securities.

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 26, 1997 /s/

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.

/s/ /s/

James J Howard E J McIntyre
Chairman of the Board, Vice President and Chief Financial
President and Chief Officer
Executive Officer (Principal Financial Officer)
(Principal Executive Officer)

/s/ /s/

Roger D Sandeen H Lyman Bretting
Vice President, Controller and Chief Director
Information Officer
(Principal Accounting Officer)

/s/ /s/

David A Christensen W John Driscoll
Director Director

/s/ /s/

Dale L Haakenstad Allen F Jacobson
Director Director

/s/ /s/

Richard M Kovacevich Douglas W Leatherdale
Director Director

/s/ /s/

John E Pearson G M Pieschel
Director Director

/s/ /s/

Margaret R Preska A Patricia Sampson
Director Director

EXHIBIT INDEX

Method of Exhibit
Filing No. Description

DT 10.14 Annual Executive Incentive Plan for 1997

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 99.01 Statement pursuant to Private Securities
Litigation Reform Act of 1995.

DT 99.03 Unaudited Pro Forma Combined Condensed Balance
Sheets for Primergy Corporation at Dec. 31, 1996
and Unaudited Pro Forma Combined Condensed
Statements of Income for the three years ended
Dec. 31, 1996.

DT 99.04 Unaudited Pro Forma Condensed Balance Sheet for
New NSP at Dec. 31, 1996 and Unaudited Pro Forma
Condensed Statements of Income for the three years
ended Dec. 31, 1996.

DT = Filed electronically with this direct transmission.