SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) MARCH 4, 1998
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NORTHERN STATES POWER COMPANY
(Exact name of registrant as specified in its charter)
MINNESOTA
(State or other jurisdiction of incorporation)
1-3034 41-0448030
(Commission File Number) (IRS Employer Identification No.)
414 NICOLLET MALL, MPLS, MN 55401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 612-330-5500
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(Former name or former address, if changed since last report)
<PAGE>
ITEM 5. OTHER EVENTS
Attached as Exhibit 99.01 are the audited consolidated financial statements of
Northern States Power Company (a Minnesota Corporation) and its subsidiaries for
the year ended December 31, 1997 and the related management's discussion and
analysis.
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
(c) EXHIBITS
Exhibit
No. Description
- ------- -----------
23.01 Consent of Independent Accountants
99.01 Excerpts from Northern States Power Company 1997
Annual Report to Shareholders:
Management's Discussion and Analysis
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Consolidated Statements of Stockholder's Equity
Consolidated Statements of Capitalization
Notes to Financial Statements
Report of Independent Accountants
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
Northern States Power Company
(a Minnesota Corporation)
By /s/
--------------------------
Edward J. McIntyre
Vice President and Chief
Financial Officer
Dated: March 4, 1998
<PAGE>
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
------ --- -----------
DT 23.01 Consent of Independent Accountants
DT 99.01 Excerpts from Northern States Power Company 1997
Annual Report to Shareholders:
Management's Discussion and Analysis
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Consolidated Statements of Stockholder's Equity
Consolidated Statements of Capitalization
Notes to Financial Statements
Report of Independent Accountants
DT = Filed electronically with direct transmission of this Form 8-K.
Exhibit 23.01
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statement No. 333-00415 on Form S-3 (relating to the Northern States Power
Company Dividend Reinvestment and Stock Purchase Plan), Registration Statement
No. 2-61264 on Form S-8 (relating to the Northern States Power Company Employee
Stock Ownership Plan), Registration Statement No. 33-38700 on Form S-8 (relating
to the Northern States Power Company Executive Long-Term Incentive Award Stock
Plan), and Registration Statement No. 33-63243 on Form S-3 (relating to the
Northern States Power Company $300,000,000 Principal Amount of First Mortgage
Bonds) of our report dated February 2, 1998 relating to the consolidated
financial statements of Northern States Power Company, appearing in this Current
Report on Form 8-K.
/s/
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
March 4, 1998
Exhibit 99.01
MANAGEMENT'S DISCUSSION AND ANALYSIS
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), Energy Masters International, Inc. (EMI), which changed its
name from Cenerprise, Inc., effective Sept. 1, 1997, 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 1997 was
12.0 percent. Based on a three-year average, this return places NSP
below the top one-fourth of the industry, which was approximately 12.7
percent, and above the median three-year industry average of
approximately 11.3 percent. The total return to investors (measured by
dividends plus stock price appreciation) on NSP common stock for the
most recent five-year period averaged 12.4 percent per year. For the
same period, the total return for the electric industry averaged 10.7
percent. NSP's stock price rose 27.0 percent over the year, well above
the 22.1 percent average increase of other utilities rated AA by
Standard & Poor's (S&P).
* 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 23 consecutive years. In June 1997, NSP's
annualized common dividend rate was increased by 6 cents per share, or
2.2 percent, from $2.76 to $2.82. The dividend payout ratio was 89.4
percent in 1997, above the objective range due to the unusual events
that adversely affected NSP's earnings in 1997. (See discussion under
Results of Operations.) The objective payout ratio is based on
long-term earnings expectations.
* TO MAINTAIN LONG-TERM AVERAGE ANNUAL EARNINGS PER SHARE GROWTH OF 5
PERCENT FROM ONGOING OPERATIONS, AS DESCRIBED BELOW. Excluding the
nonrecurring items discussed later under Factors Affecting Results of
Operations, NSP's earnings per share have grown by an average annual
rate of 4.1 percent since 1993.
1997 1996 1995
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EARNINGS PER SHARE FROM ONGOING OPERATIONS $3.54 $3.82 $3.69
Earnings (losses) from nonrecurring items (.33) 0.22
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Total earnings per share $3.21 $3.82 $3.91
===========================================================================
* 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 39 cents, or 11 percent,
of NSP's earnings per share from ongoing operations in 1997, and 29
cents, or 7.6 percent, of NSP's earnings per share from ongoing
operations in 1996.
* TO MAINTAIN CONTINUED FINANCIAL STRENGTH WITH A AA RATING FOR UTILITY
BONDS. The Company's first mortgage bonds continued to be rated AA by
Fitch Investors Service, Inc. In October 1997, S&P's raised NSP's bond
rating to AA, as a part of an industry re-evaluation. In July 1997,
Moody's Investors Services (Moody's) upgraded its rating on NSP's first
mortgage bonds to Aa3. Moody's rating action reflects NSP's progress in
satisfying legislative requirements associated with spent-fuel storage
at Prairie Island and various other factors. Moody's also cited NSP's
healthy competitive position and strong financial condition. Duff &
Phelps, Inc. raised the Company's bond rating to AA in February 1998.
First mortgage bonds issued by the Wisconsin Company carry comparable
ratings. NSP's pretax interest coverage ratio for utility operations,
based on income excluding Allowance for Funds Used During Construction
(AFC), was 3.5 in 1997. A capital structure consisting of 46.7 percent
common equity at year-end 1997 contributes to NSP's financial
flexibility and strength.
<PAGE>
BUSINESS STRATEGIES
NSP's mission is to be a recognized leader in the energy industry by increasing
the value provided to our customers with energy-related products and services.
We will utilize the skills and talents of our people to thrive in a dynamic and
competitive energy environment that provides increased value for our customers
and shareholders and significant growth opportunities for our company.
Strategies to achieve this mission include:
* EXCEEDING CUSTOMER REQUIREMENTS. Anticipate and exceed customer
requirements by balancing costs, benefits and expectations to maximize
value for each customer.
* IMPROVE COMPETITIVENESS. Achieve and maintain best quartile status in
the service and price of providing our electric and gas products.
* SUPPORT EMPLOYEES. Gain competitive advantage by fully utilizing the
diversity, skills and talents of our people.
* SUPPORT THE COMMUNITY AND THE ENVIRONMENT. Preserve and enhance NSP's
name and reputation by protecting the environment and helping to meet
the social and economic needs of the community, thereby contributing to
the growth of the community and creating support for our business
requirements.
* GROW THE BUSINESS PROFITABLY. Build on our core businesses,
subsidiaries and strategic acquisitions to profitably grow our company,
enhance shareholder value and excel in a dynamic industry environment.
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 1997 and 1996. 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.
Except for the historical information contained herein, the matters discussed in
the following discussion and analysis 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; regulation; the items
discussed 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 1997 report on Form 10-K.
<PAGE>
RESULTS OF OPERATIONS
1997 COMPARED WITH 1996 AND 1995
NSP's 1997 earnings per share from ongoing operations (assuming dilution) were
$3.54, down 28 cents, or 7.3 percent, from the $3.82 earned in 1996 and down 15
cents, or 4.1 percent, from the $3.69 earned in 1995. NSP's total earnings per
share (assuming dilution), including nonrecurring transactions in 1997 and 1995
(as discussed later), were $3.21 in 1997, $3.82 in 1996 and $3.91 in 1995.
Nonrecurring transactions in 1997 include the write-off of costs incurred prior
to the termination of NSP's proposed merger with Wisconsin Energy Corporation
(WEC) and NRG's write-down of a cogeneration project.
Regulated utility businesses generated earnings of $3.24 per share from ongoing
operations in 1997, $3.58 in 1996 and $3.41 in 1995. Earnings from ongoing
regulated operations were lower in 1997, primarily due to higher utility
operations, maintenance and depreciation expenses, the impacts of less favorable
weather, and dilutive effects of stock issuances. Partially offsetting these
earnings decreases were growth in electric sales and reduced administrative
costs.
Nonregulated businesses generated earnings from ongoing operations of 30 cents
per share in 1997, 24 cents in 1996 and 28 cents in 1995. Nonregulated earnings
increased in 1997 primarily due to higher NRG earnings from new projects,
including tax credits. Increased financing costs at NRG and losses incurred by
EMI partially offset these increases.
UTILITY OPERATING RESULTS
ELECTRIC REVENUES Sales to retail customers, which account for more than 90
percent of NSP's electric revenue, increased 1.5 percent in 1997 and 1.0 percent
in 1996. Sales in 1997 included unfavorable weather impacts compared with normal
average temperatures, and sales in 1996 and 1995 included favorable weather
impacts compared with normal average temperatures, with the retail sales impact
for 1996 being less favorable than it was in 1995. Total electric sales volumes
increased 0.6 percent in 1997 and decreased 3.0 percent in 1996. Lower sales
volumes to other utilities in 1997 and 1996 and the loss of several municipal
power customers in 1995 and 1996 partially offset the retail sales growth in
1997 and contributed to the 1996 decrease.
On a weather-adjusted basis, retail electric sales volumes are estimated to have
increased 2.6 percent in 1997 and 1.5 percent in 1996. Retail electric sales
growth for 1998 is estimated to be 2.0 percent over 1997, or 1.5 percent, on a
weather-adjusted basis.
Sales volumes to other utilities decreased 5.2 percent in 1997, while revenues
increased in 1997 (as shown in the following table). Constraints on NSP's system
due to unscheduled plant outages and storms (as discussed later) contributed to
the decrease in volumes in 1997, while higher market prices due to market
conditions contributed to the revenue increase in 1997. 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) 1997 VS. 1996 1996 vs. 1995
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Retail sales growth (excluding weather impacts) $47 $ 29
Estimated impact of weather on retail sales volume (23) (15)
Sales to other utilities 14 (20)
Municipal power sales (6) (15)
Conservation cost recovery 10 13
Fuel cost recovery 31 (10)
Other rate changes (1) (5)
Transmission and other electric revenues 19 8
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Total revenue increase (decrease) $91 $(15)
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<PAGE>
ELECTRIC PRODUCTION EXPENSES Fuel expense for electric generation in 1997
increased $8.8 million, or 2.9 percent, compared with a decrease of $24.5
million, or 7.5 percent, in 1996. The 1997 increase is primarily due to higher
average fossil fuel prices, mainly reflecting the increased use of higher-cost
plants due to plant outages and transmission line and plant limitations, as
discussed later. In 1997, management decided to take the Company's Monticello
nuclear generating plant, a baseload plant, out of service to accelerate
implementation of a design change originally planned for 1998. In addition,
during the summer of 1997, portions of transmission lines connecting two of
NSP's baseload generating plants, the Monticello nuclear and Sherco fossil
plants, to the Minneapolis-St. Paul metro area were damaged by storms. Until
repairs were completed later in 1997, the Company's generating and transmission
capabilities were temporarily reduced. As a result, NSP increased generation at
its more expensive peaking plants and purchased more power to meet 1997 sales
requirements. 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, planned maintenance outages and
conversion of two plants to peaking status.
Purchased power costs increased $42.7 million, or 17.5 percent, in 1997 after
decreasing $4.1 million, or 1.7 percent, in 1996. The 1997 increase was
primarily due to higher purchases, higher average market prices and higher
demand expenses. The higher purchases were a result of lower plant availability
due to the unplanned nuclear plant outage and storms, as discussed previously,
and higher 1997 sales requirements. The 1996 decrease primarily was due to lower
demand expenses.
GAS REVENUES The majority of NSP's retail gas sales are categorized as firm
(primarily heating customers) and interruptible (commercial/industrial customers
with an alternate energy supply). Firm sales in 1997 decreased 10.8 percent
compared with 1996 sales, while firm sales in 1996 increased 13.2 percent
compared with 1995 sales. The decrease in 1997 was primarily due to the impacts
of favorable weather in 1996 and unfavorable weather in 1997, partially offset
by sales growth. The increase in 1996 primarily was due to strong sales growth
and favorable impacts of weather.
On a weather-adjusted basis, firm gas sales are estimated to have increased 2.2
percent in 1997 and increased 5.1 percent in 1996. The firm sales increase in
1997 was partially offset by lost gas sales as a result of flooding in the Grand
Forks area. Firm gas sales in 1998 are estimated to be 7.0 percent higher
compared with 1997 sales, or 3.3 percent higher on a weather-adjusted basis.
Interruptible sales of gas increased 11.6 percent in 1997 and 3.6 percent in
1996. The increases in both years are the result of favorable gas market prices
compared with alternate fuels that caused large interruptible customers with
alternate fuel sources to use more natural gas. Other gas deliveries, including
Viking sales, increased 0.6 percent in 1997 and 5.3 percent in 1996. Viking gas
transmission deliveries to parties other than NSP increased 4.8 percent in 1997
and 7.7 percent in 1996.
The table below summarizes the principal reasons for the gas revenue changes
during the past two years:
(Millions of dollars) 1997 VS. 1996 1996 vs. 1995
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Sales growth (excluding weather impacts) $13 $ 25
Estimated impact of weather on firm sales volume (41) 13
Purchased gas adjustment clause recovery 28 52
Conservation cost recovery and other rate changes (1) 6
Transportation and other (11) 5
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Total revenue increase (decrease) $(12) $101
================================================================================
COST OF GAS PURCHASED AND TRANSPORTED The cost of gas purchased and transported
decreased $4.2 million, or 1.2 percent, in 1997, primarily due to lower gas
sendout partially offset by a 6.7 percent increase in the per unit cost of
purchased gas. The lower sendout reflects decreased gas sales, as discussed
previously, while the increase in cost per unit of purchased gas, occurring
mainly in the first quarter of 1997, reflects changes in market conditions. The
cost of gas purchased and transported increased $78.7 million, or 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.
<PAGE>
OTHER OPERATION, MAINTENANCE AND ADMINISTRATIVE AND GENERAL These expenses, in
total, increased by $37.4 million, or 5.9 percent, in 1997, compared with a
decrease of $24.9 million, or 3.8 percent, in 1996. The higher costs in 1997 are
primarily due to increased operating expenses associated with 1997 business
interruptions, higher customer service expenses, increased network transmission
service (NTS) costs, as discussed under Factors Affecting Results of Operations,
higher scheduled plant maintenance outage expenses and higher technology
improvement expenses. Business interruptions in 1997 included flooding in the
Company's service area, the unscheduled Monticello plant outage and storm damage
to transmission lines. Technology improvements included development of customer
information, automated meter reading and other systems, including preparation
for the year 2000. These cost increases were partially offset by a $6.9 million
decrease in administrative and general expenses, reflecting decreases in
insurance and employee benefit costs.
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 in
1996 reflect fewer employees and decreases in insurance and claims, employee
benefit and other corporate costs. (See Note 8 to the Financial Statements for a
summary of administrative and general expenses.)
CONSERVATION AND ENERGY MANAGEMENT Expenses increased in both 1997 and 1996
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. These higher
amortization and cost levels are recovered concurrently through retail rate
adjustment clauses in the Company's Minnesota jurisdiction, which are discussed
later under Factors Affecting Results of Operations.
DEPRECIATION AND AMORTIZATION The increases in 1997 and 1996 reflect higher
levels of depreciable plant, including new information systems and equipment in
1997 and 1996 with relatively short useful lives. Information technology
improvements are expected to continue in 1998.
PROPERTY AND GENERAL TAXES Property and general taxes decreased in 1997 and
1996, primarily due to lower property tax rates partially offset by increases
due to property additions.
UTILITY INCOME TAXES The variations in income taxes primarily are attributable
to fluctuations in taxable income and changes to effective tax rates. (See Note
7 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
MERGER COSTS In May 1997, NSP and WEC mutually terminated their plans to merge.
NSP's earnings for 1997 include a pretax charge to nonoperating expense of $29
million, or 25 cents per share, to write off its cumulative merger-related costs
incurred. This charge is being reported as a nonrecurring item outside of
earnings from ongoing operations.
UTILITY FINANCING COSTS Interest costs recognized for NSP's utility businesses,
including amounts capitalized to reflect the financing costs of construction
activities, were $120.3 million in 1997, $123.1 million in 1996 and $123.4
million in 1995. The 1997 decrease is due primarily to lower average short-term
borrowing levels, and the retirement of $100 million of first mortgage bonds in
October 1997. 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 average short-term debt balance was $208.3 million in
1997, $265.4 million in 1996 and $208.7 million in 1995. In addition to interest
expense, beginning in 1997, financing costs of NSP's utility businesses include
distributions on redeemable preferred securities.
<PAGE>
NONREGULATED BUSINESS RESULTS
NSP's nonregulated operations include diversified businesses such as NRG's
businesses, which are primarily independent power production, commercial and
industrial heating and cooling, and energy-related refuse-derived fuel
production. In addition, EMI's primary business is energy sales and service. NSP
also has investments in affordable housing projects through Eloigne and several
income-producing properties through other subsidiaries. Due to the nature of
these nonregulated businesses, NSP anticipates that the earnings from
nonregulated operations will experience more variability than regulated utility
businesses. As discussed below and shown in Note 8 to the Financial Statements,
NSP's nonregulated earnings for these periods are experiencing such variability.
The following summarizes the earnings contributions of NSP's nonregulated
businesses:
CONTRIBUTION TO NSP'S EARNINGS PER SHARE
1997 1996 1995
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NRG:
Ongoing operations $0.39 $0.29 $0.24
Nonrecurring items (0.08) 0.00 0.22
Eloigne 0.06 0.05 0.02
EMI (0.15) (0.12) (0.02)
Seren Innovations (0.02) .00 .00
Other (1) 0.02 0.02 0.04
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Total $0.22 $0.24 $0.50
===============================================================================
(1) Includes NSP-owned refuse-derived fuel operations managed by NRG
NRG
NRG's earnings from ongoing operations (excluding the nonrecurring transaction
discussed later) increased in 1997, compared with 1996, primarily due to income
from new projects, including tax credits. New projects contributing to NRG's
earnings increase include: Bolivian Power Company Ltd. (COBEE); Pacific
Generation Company (PGC); the Schkopau power generating facility in Germany,
which began operation in July 1996; and the Australian State of Victoria's Loy
Yang A power plant in which NRG, through affiliates, purchased a 25.37 percent
interest in May 1997. NRG's landfill gas subsidiary, NEO, has entered into
projects in 1996 and 1997 that are generating higher levels of energy tax
credits. Also contributing to NRG's increased earnings were the gains on the
sale of equity interests in two projects late in 1997. Higher interest costs due
to the $250 million senior notes issued in mid-1997 partially offset the
increased earnings. NRG's earnings in 1997 were adversely affected by declines
in the value of the Australian dollar and German deutsche mark in relation to
the U.S. dollar. Had exchange rates throughout 1997 stayed the same as the
beginning of the year, NRG's 1997 earnings would have been higher by
approximately 4 cents per share.
As of year-end 1997, NRG and its partner's effort to restructure the debt of the
58-megawatt Sunnyside cogeneration project in Utah was not successful. Due to a
lack of progress in restructuring the project's debt, NRG recorded a
nonrecurring expense of 8 cents per share to write down its investment in the
Sunnyside project late in 1997. This write-down reduced income from nonregulated
businesses before interest and taxes by $9 million for 1997 and is considered a
nonrecurring item.
Excluding the nonrecurring items discussed later, NRG's earnings from ongoing
operations increased in 1996, compared with 1995, due primarily to higher equity
in earnings of projects. Equity in earnings of projects increased in 1996,
primarily due to first-time earnings from Schkopau and NRG Generating (U.S.)
Inc. and higher income from Scudder Latin American Power Projects. These
earnings were partially offset by lower equity earnings from the MIBRAG project.
Equity in earnings from MIBRAG decreased, primarily due to an expected decline
in heating briquette and coal sales. NRG's earnings from ongoing operations were
higher in 1996, as compared with 1995, despite experiencing an increased level
of business development costs in 1996 as it pursued several international and
domestic projects. Until there is substantial assurance that a project in
development will come to financial closure, such costs are expensed.
NRG's earnings for 1995 included two nonrecurring items that added 22 cents to
1995 earnings. A gain of approximately 26 cents per share was recorded for a
power sales contract termination settlement, which was partially offset by a
domestic energy project write-down of 4 cents per share.
Further information on NRG's financial results may be obtained from NRG's annual
report on Form 10-K filed with the SEC.
<PAGE>
EMI
EMI's losses for 1997 were higher than 1996, primarily due to losses incurred by
EMI's gas marketing joint venture, Enerval, the partial write-down of EMI's
investment in Enerval, and increased expenses related to combining operations
with Energy Solutions International, Inc. (ESI) and Energy Masters Corporation
(EMC), both purchased by EMI in July 1997. These increased losses were partially
offset by increased operating margins, primarily due to the curtailment of gas
trading activity in the second quarter of 1996, which had negatively impacted
operating margins during the first half of 1996. EMI is currently in the process
of evaluating proposals for the sale of its interest in Enerval and expects to
finalize the sale during the first quarter of 1998. EMI's investment in and
advances to Enerval have been written down to an estimate of their net
realizable value.
EMI's earnings for 1996 decreased, compared with 1995, largely due to price
volatility in the gas market, which adversely affected earnings from Enerval,
and losses incurred from the gas trading business.
OTHER
Eloigne's earnings have continued to grow in 1997 and 1996 due to investments in
new affordable housing projects. NSP's new communications and data services
subsidiary, Seren Innovations, experienced a loss in its first year, 1997, as it
focused on development of its products and services.
FACTORS AFFECTING RESULTS OF OPERATIONS
NSP's results of operations during 1997, 1996 and 1995 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:
REGULATION NSP's utility rates are approved by the Federal Energy Regulatory
Commission (FERC) and state regulatory commissions in Minnesota, North Dakota,
South Dakota, Wisconsin and Michigan. 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, 1997, NSP reported on its balance sheet
approximately $212 million and $129 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
$87 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 a potential write-off of regulatory assets and liabilities,
deregulation and competition (as discussed later) may require recognition of
certain "stranded costs" not recoverable under market pricing. NSP currently is
<PAGE>
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.
RATE FILINGS On Dec. 2, 1997, the Company filed a natural gas rate case seeking
an annual rate increase of approximately $18.5 million for retail customers in
Minnesota. An interim rate increase totaling $13.9 million on an annual basis
has been approved, subject to refund, effective Feb. 1, 1998.
On Nov. 14, 1997, the Wisconsin Company filed retail electric and natural gas
rate cases for Wisconsin customers requesting that the rate changes become
effective during the second quarter of 1998. The Wisconsin Company is seeking an
annual increase in retail electric rates of approximately $12.7 million and an
annual decrease in retail natural gas rates of approximately $1.7 million.
On February 17, 1998, NSP filed a rate application with the FERC to update its
rates for point to point transmission service. As filed, the proposed rates
increase annual transmission revenues by approximately $4 million. In addition,
the filing is expected to support reductions in NSP's NTS costs, as discussed
later.
COMPETITION The Energy Policy Act of 1992 (the Act) has been a catalyst for
comprehensive and significant changes in the operation of electric utilities,
including increased competition. The Act's reform of the Public Utility Holding
Company Act of 1935 (PUHCA) promoted creation of wholesale nonutility power
generators and authorized 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. 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 1996, the FERC issued Orders No. 888 and 889, which have had a significant
impact on wholesale electric markets by giving competitors the ability to
transmit electricity through utilities' transmission systems. Order No. 888
granted nondiscriminatory access to transmission service. Order No. 889 ensures
a fair market by imposing standards of conduct on transmission system owners, by
requiring separation of the wholesale power supply ("merchant") function from
the transmission system operation function and by mandating the posting of
transmission availability and pricing information on an electronic bulletin
board. These new open access rules became effective in 1996 and 1997. In 1997,
the FERC issued clarifying final orders in response to rehearing requests by
numerous market participants regarding Orders No. 888 and 889. These FERC
clarifying final orders are currently being appealed in federal court. 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.
In compliance with FERC Orders No. 888 and 889, NSP has separated personnel who
perform the merchant function, which includes power and energy marketing and
trading, from personnel who perform the transmission system operation function.
In 1997, NSP's merchant function, NSP Energy Marketing, expanded its power
trading to focus on new market opportunities created by open transmission
access. NSP is also developing risk management practices to respond to the
rapidly growing electric commodity market. In addition, a significant effort was
put forth in 1997 to enter current and all new requests for transmission service
into the electronic bulletin board, as directed by FERC Order No. 889 and
supported by NSP.
The FERC Order No. 888 requires utilities to offer, among other services,
Network Transmission Service (NTS) to qualifying customers. Under NTS, NSP and
other qualifying regional utilities share the total annual costs of operating
and maintaining the regional transmission network that NSP uses, net of related
network revenues, based on each company's share of the total network load. The
transmission tariff filed with the FERC is used as the cost basis for
FERC-regulated utilities in determining NTS rates. In 1997, NSP conducted a
review of information received from other participating utilities and commenced
settlement negotiations with these utilities regarding the final amount of NTS
costs to be paid by NSP for 1997. Based on this review and discussion, NSP
concluded that its net NTS costs for 1997 were less than the $27 million
previously estimated. NSP recorded a liability for what management believes is a
reasonable estimate of the net NTS costs for 1997. NSP expects that its
transmission tariff filing and settlement negotiations will result in lower NTS
costs in 1998.
Some states have begun to allow retail customers to choose their electricity
supplier, and many other states are considering retail access proposals. NSP
believes that retail competition will result in more innovative services and
<PAGE>
lower prices for all consumers if the transition is managed in a thoughtful
manner. NSP supports fair and equal treatment for all competitors, recovery of
utilities' investments made under traditional regulation and a resolution of
property tax issues. NSP supports a plan that would take two or three years to
resolve these issues and develop infrastructure, and another two to three years
to phase in customers' choice. In 1997, the Minnesota Public Utilities
Commission (MPUC) approved a report by its staff that identifies issues that
must be resolved before retail competition can begin, but did not approve an
action plan or schedule for its implementation. The Minnesota Legislature began
studying the issues in 1997 and concluded that another year of study was
necessary before any action could be taken. The Public Service Commission of
Wisconsin (PSCW) revised its restructuring plan, delaying the start of retail
competition another year to 2002. The Michigan Public Service Commission (MPSC)
approved a plan to begin offering a choice of suppliers to retail customers in
selected markets in 1998. That plan was unsuccessfully challenged by the
affected Michigan utilities, and the courts upheld the MPSC's authority to
implement retail competition. The timing of regulatory actions regarding
restructuring and their impact on NSP cannot be predicted at this time and may
be significant.
USED NUCLEAR FUEL STORAGE AND DISPOSAL In 1994, NSP received legislative
authorization from the state of Minnesota for the use of 17 casks for temporary
spent-fuel storage at the Company's Prairie Island nuclear generating facility.
Based on assumptions in the original Certificate of Need granted by the MPUC,
the Company previously estimated that 17 casks would allow operation of the
Prairie Island facility to continue to 2003. After review of the 1994
legislative authorization which amends the Certificate of Need, and through the
use of longer fuel cycles, the Company has determined 17 casks will allow
operation of the facility until 2007. The first nine casks have been authorized
by the Minnesota Environmental Quality Board (MEQB). The Company had loaded
seven of the casks as of Dec. 31, 1997. As a condition of the 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. The MEQB has
terminated an alternative siting process, which had been one of the original
legislative requirements.
Regarding permanent fuel storage, in 1996 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. In
January 1997, the Company, other utility parties and state parties filed another
lawsuit against the DOE, requesting authority to withhold payments to the DOE
for the permanent disposal program. In April 1997, the parties filed for
additional relief, asking the U.S. Court of Appeals for the District of Columbia
(the Court) to order the DOE to take spent nuclear fuel by Jan. 31, 1998. In
November, 1997, the Court, in a unanimous ruling, reiterated the unconditional
obligation for the DOE to begin acceptance of spent nuclear fuel by Jan. 31,
1998. The Court confirmed this obligation exists under both the statute and the
standard contract; however, the Court denied the Company's request for an order
directing the DOE to accept spent nuclear fuel by the Jan. 31, 1998 date in the
standard contract, finding that the contractual remedies under the standard
contract, i.e., damages, may be adequate. The Court also held that the DOE
cannot use its own delays or the unavailability of a permanent disposal or
temporary storage facility as defense to utilities' actions for damages.
In its November 1997 decision, the Court did not discuss the request to escrow
payments to the Nuclear Waste Fund. In December 1997, the DOE petitioned the
Court for rehearing. Based on the Court's ruling, NSP and other utilities are
currently analyzing claims against the DOE for the costs incurred as a result of
the DOE's failure to meet its statutory and contractual obligations. 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. 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.)
TECHNOLOGY CHANGES FOR THE YEAR 2000 Like many other companies, NSP expects to
incur significant costs to modify or replace existing technology, including
computer software, for uninterrupted operation in the year 2000 and beyond. In
1996, NSP's Board of Directors approved funding to address development and
remediation efforts related to the year 2000. A committee made up of senior
management is leading NSP's initiatives to identify year 2000 related issues and
remediate business processes as necessary in 1998. Testing of computer software
modifications and other remediated processes is scheduled for 1999. NSP is also
working with major suppliers so that NSP does not experience business
interruptions due to year 2000 issues in the suppliers' business processes. The
amount of additional development and remediation costs necessary after 1997 for
NSP to prepare for the year
<PAGE>
2000 is estimated to be approximately $20 million, expected mainly in 1998. In
1997 and 1996, NSP expensed approximately $2.3 million and $0.6 million,
respectively, for this modification effort.
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 1997, $31 million in 1996
and $26 million in 1995, and are expected to average approximately $35 million
per year for the five-year period 1998-2002. 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 1997, 1996
and 1995, the Company spent about $19 million, $10 million and $13 million,
respectively, for capital expenditures on environmental improvements at its
utility facilities. In 1998, the Company expects to incur approximately $18
million in capital expenditures for compliance with environmental regulations
and approximately $142 million for the five-year period 1998-2002. 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
1997, warmer-than-normal weather late in the year decreased earnings over a
normal year by an estimated 11 cents per share. 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. 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 discussed in the Results of Operations section.
NSP expects to continue investing 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 (as listed in Note 10 to the Financial
Statements) consist of minority interests, and a substantial portion of future
investments may take the form of minority interests, which may limit NRG's
financial risk and 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 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 would require the full accrual of nuclear plant
decommissioning and certain other site exit obligations. Material adjustments to
NSP's balance sheet would occur upon implementation of the FASB's proposal,
which does not currently have a scheduled effective date. 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 mitigate the impact of changes in foreign currency
exchange rates and natural gas prices, and changes in interest rates on the cost
of borrowing. Also, to mitigate 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.)
<PAGE>
NONRECURRING ITEMS NSP's earnings for 1997 include two significant unusual or
infrequently occurring items. As discussed previously, NSP recorded a
nonrecurring charge of $29 million, or 25 cents per share, to write off costs
previously deferred as a result of the proposed merger with WEC. Also, as
discussed in the Nonregulated Business Results section, NRG wrote down a
cogeneration project, reducing income from nonregulated businesses before
interest and taxes by $9 million, or 8 cents per share.
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, or 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, or 4 cents
per share, for a nonregulated domestic energy project.
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
1997 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 $397 million in 1997. Of that amount, $305 million related to replacements
and improvements of NSP's electric system and nuclear fuel, and $72 million
involved construction of natural gas distribution and transmission facilities.
NSP companies invested approximately $591 million in 1997 for equity interests
in and loans to nonregulated projects, for the acquisition of existing
businesses and for additions to nonregulated property. NRG invested in many
energy projects in 1997, including the $149 million purchase of PGC, and several
equity investments, the largest of which are listed in Note 10 to the Financial
Statements. Eloigne invested in affordable housing projects, including wholly
owned properties and limited partnership ventures.
1997 FINANCING ACTIVITY During 1997, NSP's sources of capital included
internally generated funds and external financings, as discussed later. 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.
Funds generated internally from operating cash flows in 1997 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. NSP's objective pretax interest coverage ratio for
utility operations is 3.5 - 5.0. The utility pretax interest coverage ratio,
excluding AFC, was 3.6 in 1997, 4.4 in 1996, and 4.1 in 1995, which falls within
the objective range. Internally generated funds from utility operations could
have provided financing for more than 100 percent of NSP's utility capital
expenditures for 1997 and approximately 90 percent of the $1.9 billion in
utility capital expenditures incurred for the five-year period 1993-1997. The
pretax interest coverage ratio, excluding AFC, for all NSP operations was 2.8 in
1997, 3.7 in 1996 and 3.8 in 1995. The 1997 decline in the coverage ratio is due
to the unusual events that adversely affected NSP's earnings in 1997, as
discussed previously in the Results of Operations section, and issuance of new
debt by NRG, as discussed later.
NSP had approximately $260 million in short-term borrowings, including $122
million related to NRG, outstanding as of Dec. 31, 1997. Throughout 1997, the
Company used short-term borrowings to temporarily finance a portion of utility
capital expenditures and provide for other cash needs. NRG's line of credit
borrowings were used for the acquisition of PGC and other corporate purposes.
In the utility businesses, during 1997 NSP issued $200 million of 7.875 percent
preferred securities through a wholly owned special purpose subsidiary trust and
used the proceeds to redeem two preferred stock issues and reduce short-term
debt levels. The Company also collateralized $188 million of outstanding
pollution control bonds under its first mortgage indenture, and Viking issued
$14 million of long-term debt to finance an expansion project.
NSP's 1997 business acquisition, equity investments in nonregulated projects,
and construction expenditures were primarily financed through internally
generated funds and the issuance of debt by nonregulated subsidiaries. NRG
issued $250 million of 7.5 percent unsecured publicly traded Senior Notes in
1997 to support equity requirements for projects currently under way and in
development. The Senior Notes were assigned ratings of BBB- by S&P and
<PAGE>
Baa3 by Moody's. 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 10 to
the Financial Statements.) Loans made by NSP to nonregulated projects are
reflected separately on the balance sheet as Notes Receivable from Nonregulated
Projects.
During 1997, the Company issued 5.6 million shares of common stock. Of these
shares, 4.9 million were sold to a group of underwriters in September 1997 at an
offering price to the public of $49.5625 per share. The net proceeds to the
Company of $237 million were used for general corporate purposes, including the
retirement of $100 million of first mortgage bonds that matured Oct. 1, 1997,
expenditures for the Company's construction program and the repayment of
short-term borrowings. Of the remaining new shares, 0.3 million were issued
under the Dividend Reinvestment and Stock Purchase Plan (DRSPP), 0.2 million
were issued under the Employee Stock Ownership Plan (ESOP) and 0.2 million were
issued under the Executive Long-Term Incentive Award Stock Plan.
FUTURE FINANCING REQUIREMENTS Utility financing requirements for 1998-2002 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 $441 million
in 1998 and $2.1 billion for the five-year period 1998-2002. Of the 1998 amount,
approximately $371 million is scheduled for electric utility facilities and
approximately $49 million for natural gas facilities, including Viking. Approval
of the $1.25 billion Viking Voyageur Project, a proposed natural gas
transmission pipeline, would increase the total gas expenditures approximately
$500 million for the five-year period 1998-2002, with yearly expenditures
dependent on FERC approval. In addition to utility capital expenditures,
expected financing requirements for the five-year period 1998-2002 include
approximately $606 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 1998 and approximately $940 million for the
five-year period 1998-2002. These amounts include commitments for NRG
investments, as discussed in Note 14 to the Financial Statements, and Eloigne
investments of up to $11 million annually in 1998-2002 for affordable housing
projects. 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 securities as needed to maintain desired
capitalization ratios. Over the long term, NSP's equity investments in
nonregulated projects are expected to be financed at the nonregulated subsidiary
level, from internally generated funds or the issuance of subsidiary debt.
Financing requirements for the nonregulated projects, in excess of equity
contributions from project investors, are expected to be fulfilled through
project or subsidiary debt. In addition, to provide additional capital to NRG,
NSP is considering the public offering of up to 20 percent equity ownership of
NRG in late 1998 or 1999. Eloigne expects to finance approximately 60 percent of
its estimated five-year investments in affordable housing projects with equity
and approximately 40 percent with long-term 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
<PAGE>
issue long-term securities and obtain short-term credit. NSP expects to maintain
adequate access to securities markets in 1998. Access to securities markets at a
reasonable cost is determined in large part by credit quality. The Company's
first mortgage bonds are currently rated AA by Standard & Poor's Corporation,
Aa3 by Moody's Investors Service, Inc., 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.
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, 1997, with an assumed
interest rate of 6.75 percent, the Company could have issued about $2.1 billion
of additional first mortgage bonds under its indenture, and the Wisconsin
Company could have issued about $351 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 remaining $300 million of registered, but unissued, bonds over the
next several years to raise additional capital or redeem outstanding securities.
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 $575 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 $300 million to the Company and an
additional $245 million to subsidiaries of the Company, including a $175 million
unsecured revolving bank credit facility available to NRG. 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 $500 million of its remaining authorized, but unissued,
preferred stock at Dec. 31, 1997, and remained in compliance with all interest
and dividend coverage requirements.
The Company's Articles of Incorporation authorize an additional 85.4 million
shares of common stock in excess of shares issued at Dec. 31, 1997. In 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 3 to the Financial Statements for discussion of stock awards outstanding.)
The Company plans to issue new shares for its DRSPP, ESOP and Executive
Long-Term Incentive Award Stock plans in 1998. NSP currently has no plans for
any general offerings of common stock in 1998 or 1999.
Internally generated funds from utility operations are expected to equal
approximately 85 percent of anticipated utility capital expenditures for 1998
and approximately 95 percent of the $2.1 billion in anticipated utility capital
expenditures for the five-year period 1998-2002. Internally generated funds from
all operations are expected to equal approximately 60 percent and 85 percent of
the anticipated total capital requirements for 1998 and the five-year period
1998-2002, 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.
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year Ended Dec. 31
------------------------------------
(Thousands of dollars, except per share data) 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
UTILITY OPERATING REVENUES
Electric $2 218 550 $2 127 413 $2 142 770
Gas 515 196 526 793 425 814
- ------------------------------------------------------------------------------------------------------------------
Total 2 733 746 2 654 206 2 568 584
- ------------------------------------------------------------------------------------------------------------------
UTILITY OPERATING EXPENSES
Fuel for electric generation 309 999 301 201 325 652
Purchased and interchange power 286 239 243 562 247 699
Cost of gas purchased and transported 331 296 335 453 256 758
Other operation 368 545 333 010 318 015
Maintenance 164 542 155 830 158 203
Administrative and general 141 802 148 656 186 147
Conservation and energy management 70 939 69 784 53 466
Depreciation and amortization 325 880 306 432 290 184
Property and general taxes 227 893 232 824 239 433
Income taxes 144 855 161 410 147 148
- ------------------------------------------------------------------------------------------------------------------
Total 2 371 990 2 288 162 2 222 705
- ------------------------------------------------------------------------------------------------------------------
UTILITY OPERATING INCOME 361 756 366 044 345 879
- ------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Income from nonregulated businesses - before interest and taxes 12 078 18 543 49 611
Allowance for funds used during construction---equity 6 401 7 595 6 794
Merger costs (29 005)
Other utility income (deductions)---net (2 886) (1 544) 1 481
Income taxes on nonregulated operations and nonoperating items 48 145 14 600 (5 080)
- ------------------------------------------------------------------------------------------------------------------
Total 34 733 39 194 52 806
- ------------------------------------------------------------------------------------------------------------------
INCOME BEFORE FINANCING COSTS 396 489 405 238 398 685
- ------------------------------------------------------------------------------------------------------------------
FINANCING COSTS
Interest on utility long-term debt 101 250 101 177 103 298
Other utility interest and amortization 19 063 21 950 20 151
Nonregulated interest and amortization 34 627 18 834 9 879
Allowance for funds used during construction---debt (10 208) (11 262) (10 438)
- ------------------------------------------------------------------------------------------------------------------
Total interest charges 144 732 130 699 122 890
Distributions on redeemable preferred securities of subsidiary trust 14 437
- ------------------------------------------------------------------------------------------------------------------
Total Financing Costs 159 169 130 699 122 890
- ------------------------------------------------------------------------------------------------------------------
NET INCOME 237 320 274 539 275 795
Preferred Stock Dividends 11 071 12 245 12 449
- ------------------------------------------------------------------------------------------------------------------
Earnings Available for Common Stock $226 249 $262 294 $263 346
==================================================================================================================
Average Number of Common Shares Outstanding (000's) 70 297 68 561 67 323
Average Number of Common and Potentially Dilutive Shares Outstanding (000's)70 435 68 679 67 416
EARNINGS PER AVERAGE COMMON SHARE - BASIC $3.22 $3.83 $3.91
EARNINGS PER AVERAGE COMMON SHARE - ASSUMING DILUTION $3.21 $3.82 $3.91
Common Dividends Declared per Share $2.805 $2.745 $2.685
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended Dec. 31
------------------------------------
(Thousands of dollars) 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $237 320 $274 539 $275 795
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization 358 928 335 605 322 296
Nuclear fuel amortization 40 015 45 774 49 778
Deferred income taxes (5 902) (30 561) (11 076)
Deferred investment tax credits recognized (10 061) (9 352) (9 117)
Allowance for funds used during construction --- equity (6 401) (7 595) (6 794)
Undistributed equity in earnings of unconsolidated affiliates (5 364) (25 976) (24 305)
Undistributed equity in gain from nonregulated contract termination (17 565)
Write-off of prior year merger costs 25 289
Cash provided by (used for) changes in certain working capital items
(see below) 36 117 (58 634) (791)
Conservation program expenditures --- net of amortization (9 207) (2 854) (21 668)
Cash provided by changes in other assets and liabilities 29 051 23 518 17 234
- -------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 689 785 544 464 573 787
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures:
Utility plant additions (including nuclear fuel) (396 605) (386 655) (386 022)
Additions to nonregulated property (35 928) (25 807) (14 984)
Increase (decrease) in construction payables 2 563 (3 716) (12 588)
Allowance for funds used during construction --- equity 6 401 7 595 6 794
Investment in external decommissioning fund (41 261) (40 497) (33 196)
Equity investments, loans and deposits for nonregulated projects (395 495) (299 173) (55 884)
Collection of loans made to nonregulated projects 87 128 116 126 1 766
Business acquisitions (159 600)
Other investments --- net (15 692) (15 873) (998)
- -------------------------------------------------------------------------------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES (948 489) (648 000) (495 112)
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in short-term debt --- net issuances (repayments) (108 023) 152 173 (22 245)
Proceeds from issuance of long-term debt - net 299 779 197 824 277 174
Loan to ESOP (15 000)
Repayment of long-term debt, including reacquisition premiums (141 681) (67 628) (195 683)
Proceeds from issuance of preferred securities - net 193 315
Proceeds from issuance of common stock - net 267 965 41 725 56 185
Redemption of preferred stock, including reacquisition premiums (41 278)
Dividends paid (207 726) (198 234) (191 367)
- -------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED FOR) FINANCING ACTIVITIES 262 351 125 860 (90 936)
- -------------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3 647 22 324 (12 261)
Cash and Cash Equivalents at Beginning of Period 51 118 28 794 41 055
- -------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $54 765 $51 118 $28 794
===================================================================================================================
CASH PROVIDED BY (USED FOR) CHANGES IN CERTAIN WORKING CAPITAL ITEMS:
Customer accounts receivable and unbilled utility revenues $47 878 $(41 495) $(66 311)
Materials and supplies inventories (8 547) (9 891) 14 290
Payables and accrued liabilities (excluding construction payables) (7 342) 1 179 51 316
Other 4 128 (8 427) (86)
- -------------------------------------------------------------------------------------------------------------------
Net $36 117 $(58 634) $(791)
===================================================================================================================
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $144 062 $121 697 $113 705
Income taxes (net of refunds received) $113 009 $165 146 $131 452
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS Dec. 31
----------------------
(Thousands of dollars) 1997 1996
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
UTILITY PLANT
Electric---including construction work in progress:
1997, $92,302; 1996, $132,705 $6 964 888 $6 766 896
Gas 821 119 750 449
Other 343 950 331 441
- ---------------------------------------------------------------------------------------------------------------
Total 8 129 957 7 848 786
Accumulated provision for depreciation (3 868 810) (3 611 244)
Nuclear fuel---including amounts in process:
1997, $23,381; 1996, $6,916 932 335 892 484
Accumulated provision for amortization (832 162) (792 146)
- ---------------------------------------------------------------------------------------------------------------
Net utility plant 4 361 320 4 337 880
- ---------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 54 765 51 118
Customer accounts receivable --- net of accumulated provisions
for uncollectible accounts: 1997, $10,406; 1996, $10,195 269 455 288 330
Unbilled utility revenues 121 619 147 366
Notes receivable from nonregulated projects 55 787 5 753
Other receivables 80 803 77 571
Materials and supplies inventories---at average cost:
Fuel 56 434 45 013
Other 107 254 109 425
Prepayments and other 55 674 72 647
- ---------------------------------------------------------------------------------------------------------------
Total current assets 801 791 797 223
- ---------------------------------------------------------------------------------------------------------------
OTHER ASSETS
Equity investments in nonregulated projects 740 734 409 729
External decommissioning fund and other investments 400 290 302 250
Regulatory assets 340 122 354 128
Nonregulated property---net of accumulated depreciation:
1997, $105,526; 1996, $93,320 256 726 192 790
Notes receivable from nonregulated projects 77 639 75 811
Other long-term receivables 42 600 63 684
Long-term prepayments and deferred charges 30 015 57 237
Intangible assets - net of accumulated amortization 92 829 46 168
- ---------------------------------------------------------------------------------------------------------------
Total other assets 1 980 955 1 501 797
- ---------------------------------------------------------------------------------------------------------------
TOTAL $7 144 066 $6 636 900
===============================================================================================================
LIABILITIES AND EQUITY
CAPITALIZATION
Common stockholders' equity $2 371 728 $2 135 880
Preferred stockholders' equity 200 340 240 469
Company obligated mandatorily redeemable preferred securities of subsidiary trust
holding as its sole asset junior subordinated deferrable debentures of the Company 200 000
Long-term debt 1 878 875 1 592 568
- ---------------------------------------------------------------------------------------------------------------
Total capitalization 4 650 943 3 968 917
- ---------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year 22 820 119 618
Other long-term debt potentially due within one year 141 600 141 600
Short-term debt 260 352 368 367
Accounts payable 249 813 236 341
Taxes accrued 186 369 204 348
Interest accrued 28 724 34 722
Dividends payable on common and preferred stocks 54 778 50 409
Accrued payroll, vacation and other 89 562 80 995
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 1 034 018 1 236 400
- ---------------------------------------------------------------------------------------------------------------
OTHER LIABILITIES
Deferred income taxes 792 569 804 342
Deferred investment tax credits 138 509 149 606
Regulatory liabilities 305 765 302 647
Postretirement and other benefit obligations 135 612 114 312
Other long-term obligations and deferred income 86 650 60 676
- ---------------------------------------------------------------------------------------------------------------
Total other liabilities 1 459 105 1 431 583
- ---------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENT LIABILITIES (SEE NOTES 13 AND 14)
- ---------------------------------------------------------------------------------------------------------------
TOTAL $7 144 066 $6 636 900
===============================================================================================================
</TABLE>
See Notes to Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
CUMULATIVE
CURRENCY
NUMBER OF RETAINED SHARES HELD TRANSLATION
(Dollar amounts in thousands) SHARES ISSUED PAR VALUE PREMIUM EARNINGS BY ESOP ADJUSTMENTS
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
- -------------------------------------------------------------------------------------------------------------------------
Net income 237 320
Dividends declared:
Cumulative preferred stock (9 923)
Common stock (202 173)
Premium on redeemed preferred stock (1,148)
Issuances of common stock - net 5 554 670 13 887 253 999
Tax benefit from stock options exercised 1 009
Repayment of ESOP loan * 8 558
Currency translation adjustments (65 681)
- -------------------------------------------------------------------------------------------------------------------------
BALANCE AT DEC. 31, 1997 74 618 382 $186 546 $893 727 $1 364 875 $(10 533) $(62 887)
=========================================================================================================================
</TABLE>
* Did not affect NSP cash flows
See Notes to Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
Dec. 31
---------------------------
(Thousands of dollars) 1997 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
COMMON STOCKHOLDERS' EQUITY
Common stock---authorized 160,000,000 shares of $2.50 par value;
issued shares: 1997, 74,618,382; 1996, 69,063,712 $186 546 $172 659
Premium on common stock 893 727 638 719
Retained earnings 1 364 875 1 340 799
Leveraged common stock held by Employee Stock Ownership Plan (ESOP)
---shares at cost: 1997, 230,253; 1996, 381,313 (10 533) (19 091)
Currency translation adjustments---net (62 887) 2 794
- -------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity $2 371 728 $2 135 880
===================================================================================================================
CUMULATIVE PREFERRED STOCK---authorized 7,000,000 shares of $100 par value;
outstanding shares: 1997, 2,000,000; 1996, 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
7.00 series, 200,000 shares 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 200 000 240 000
Premium on preferred stock 340 469
- -------------------------------------------------------------------------------------------------------------------
Total preferred stockholders' equity $200 340 $240 469
===================================================================================================================
MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST (See Note 2)
7 7/8% series, 8,000,000 shares, due Jan. 31, 2037 $200 000
===================================================================================================================
LONG-TERM DEBT
First Mortgage Bonds - Minnesota Company
Series due:
Oct. 1, 1997, 5 7/8% $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, 1996-2006, 6.65% 18 400** 19 800**
March 1, 2011, Variable Rate 13 700* 13 700*
July 1, 2025, 7 1/8% 250 000 250 000
April 1, 2007, 6.80% 60 000*
March 1, 2019, Variable Rate 27 900*
Sept. 1, 2019, Variable Rate 100 000*
- -------------------------------------------------------------------------------------------------------------------
Total 1 170 000 1 083 500
Less redeemable bonds classified as current (See Note 5) (141 600) (13 700)
Less current maturities (1 500) (101 400)
- -------------------------------------------------------------------------------------------------------------------
Net $1 026 900 $968 400
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
* POLLUTION CONTROL FINANCING
** RESOURCE RECOVERY FINANCING
See Notes to Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
Dec. 31
-------------------------------
(Thousands of dollars) 1997 1996
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
LONG-TERM DEBT---CONTINUED
First Mortgage Bonds - Wisconsin Company
Series due:
Oct. 1, 2003, 5 3/4% $40 000 $40 000
March 1, 2023, 7 1/4% 110 000 110 000
Dec. 1, 2026, 7 3/8% 65 000 65 000
- -------------------------------------------------------------------------------------------------------------------
Total 215 000 $215 000
- -------------------------------------------------------------------------------------------------------------------
Guaranty Agreements---Minnesota Company
Series due:
Feb. 1, 1997 - 2003, 5.41% $5 300* $ 5 500*
May 1, 1997 - 2003, 5.70% 23 250* 23 750*
Feb. 1, 2003, 7.40% 3 500* 3 500*
- -------------------------------------------------------------------------------------------------------------------
Total 32 050 32 750
Less current maturities (700) (700)
- -------------------------------------------------------------------------------------------------------------------
Net $31 350 $32 050
- -------------------------------------------------------------------------------------------------------------------
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*
March 1, 2019, Variable Rate 27 900*
Sept. 1, 2019, Variable Rate 100 000*
Anoka County Resource Recovery Bond---Series due
Dec. 1, 1997 - 2008, 7.09% 21 850** 23 050**
City of La Crosse Resource Recovery Bond---Series due
Nov. 1, 2021, 6% 18 600** 18 600**
Viking Gas Transmission Company Senior Notes---Series due
Oct. 31, 2008, 6.65% 23 111 25 244
Nov. 30, 2011, 7.1% 5 010 5 370
Sept. 30, 2012, 7.31% 13 767
NRG Energy, Inc. Senior Notes---Series due
Feb. 1, 2006, 7.625% 125 000 125 000
June 15, 2007, 7.5% 250 000
NRG Energy Center, Inc. (Minneapolis Energy Center) Senior Secured Notes---Series due
June 15, 2013, 7.31% 74 481 76 992
Pacific Generation Company debt due 2000-2007, 4.7% - 9.9% 33 424
Various NEO Corporation debt due Oct. 30, 2000, 6.9% - 9.4% 5 618
United Power & Land Notes due
March 31, 2000, 7.62% 6 875 7 708
Various Eloigne Company Affordable Housing Project Notes due
1997 - 2024, 1.0% - 9.9% 27 223 24 755
Employee Stock Ownership Plan Bank Loans due
1997 - 2003, Variable Rate 10 535 17 571
Miscellaneous 7 385 7 533
- -------------------------------------------------------------------------------------------------------------------
Total 631 879 528 723
Less redeemable bonds classified as current (see Note 5) (127 900)
Less current maturities (20 620) (17 518)
- -------------------------------------------------------------------------------------------------------------------
Net $611 259 $383 305
- -------------------------------------------------------------------------------------------------------------------
Unamortized discount on long-term debt-net (5 634) (6 187)
- -------------------------------------------------------------------------------------------------------------------
Total long-term debt $1 878 875 $1 592 568
===================================================================================================================
Total capitalization $4 650 943 $3 968 917
===================================================================================================================
</TABLE>
* POLLUTION CONTROL FINANCING
** RESOURCE RECOVERY FINANCING
See Notes to Financial Statements.
<PAGE>
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; Energy Masters
International, Inc. (EMI), formerly Cenerprise, Inc.; and Eloigne Company
(Eloigne). The Company and its subsidiaries collectively are referred to herein
as NSP. As discussed in Note 10, 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 5.75 percent in 1997, 5.5 percent in 1996
and 6.0 percent in 1995. 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 changes in annual depreciation accruals for 1997 and
1996.
<PAGE>
The Company also submitted in 1997, as required every five years, an average
service life filing for transmission, distribution and general properties. The
filing, as approved by the MPUC, decreased depreciation approximately $1 million
from 1996 levels. Depreciation provisions, as a percentage of the average
balance of depreciable utility property in service, were 3.78 percent in 1997,
3.68 percent in 1996 and 3.64 percent in 1995.
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 no sooner than
1999. (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 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. Costs may be
deferred as a regulatory asset based on expected recovery in future rates. 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 7.
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. During 1997, the
effects of changes in currency exchange rates on NRG's international project
investments, mainly in Australia, reduced equity by $66 million.
Exchange gains and losses that result from foreign currency transactions (e.g.,
converting cash distributions made in one currency to another) and derivative
arrangements that do not qualify for hedge accounting (see Note 11) are included
in the results of operations as a component of income from nonregulated
businesses before interest and taxes. The earnings impact of these items was not
material to NSP's results for the periods presented.
DERIVATIVE FINANCIAL INSTRUMENTS NSP's policy is to hedge projected foreign
currency denominated cash flows, 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 with terms of less than one to three years. Gains and losses on these
agreements offset the effect of foreign currency exchange rate fluctuations on
NRG's known and anticipated cash flows. Gains on agreements that hedge firm
commitments of
<PAGE>
cash flows are deferred and included in the measurement of the related foreign
currency transaction in the period the transaction occurs, and losses on these
agreements are deferred in the same manner unless it is estimated that deferral
would lead to recognizing losses in later periods. Gains and losses on
agreements that hedge cash flows not meeting the criteria of a firm commitment
are recorded in the current period as a component of NSP's nonregulated income
before interest and taxes. Prior to July 1997, NSP's policy was to hedge foreign
currency denominated investments as they were made, where appropriate hedging
instruments were available, to preserve their U.S. dollar value. Gains and
losses on these agreements offset the effects of foreign currency exchange rate
fluctuations on the valuation of the investments underlying the hedges. Hedging
gains and losses, net of income tax effects, on these agreements were reported
with other currency translation adjustments as a separate component of
stockholders' equity. While NRG is not currently hedging foreign currency
denominated investments, NRG will hedge such investments when management
believes that preserving the U.S. dollar value of the investment is appropriate.
NRG is not hedging currency translation adjustments related to future operating
results. NRG does not speculate in foreign currencies.
Where appropriate, NRG also uses interest rate hedging instruments to protect
against increases in the cost of borrowing at both the corporate and project
level. Gains and losses on interest rate hedging instruments are deferred and
included in the measurement of the underlying equity investment when made.
Another derivative arrangement is the use of natural gas futures contracts by
EMI 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 EMI's nonregulated operating expenses. NSP does not speculate
in natural gas futures. A final 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 derivative financial instruments are 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.
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 3. 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 1997,
1996 and 1995 would have been immaterial.
<PAGE>
DEVELOPMENT COSTS As it pursues projects under development, NRG expenses
development costs incurred until a sales agreement or letter of intent is signed
and the project has received capital authorization. Additional costs incurred
after this point are capitalized as part of equity investments in projects. When
project operations begin, such capitalized costs are amortized on a
straight-line basis over the lesser of the life of the project's related assets
or revenue contract period.
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 $43 million ($38 million net of accumulated amortization) at Dec.
31, 1997. This goodwill and other intangible assets acquired are being amortized
using the straight-line method over periods of three 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 $22 million at Dec. 31, 1997. These financing
costs are being amortized over the remaining maturity period of the related
debt.
RECLASSIFICATIONS Certain reclassifications have been made to the 1996 and 1995
income statements to conform to 1997 presentation. These classifications had no
effect on net income or earnings per share.
2. 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, 1997, the annualized
dividend rates were $5.50 for both series A and series B.
At Dec. 31, 1997, various preferred stock series were callable at prices per
share ranging from $100.00 to $103.75, plus accrued dividends.
In January 1997, a wholly owned special purpose subsidiary trust of NSP issued
$200 million in 7.875 percent preferred securities that mature in 2037. A
portion of the proceeds was used to redeem the Company's $6.80 and $7.00 series
of preferred stock in February 1997. Distributions paid to preferred security
holders are reflected as a financing cost in the Consolidated Statement of
Income along with interest expense. Distributions paid by the subsidiary trust
on the preferred securities are financed through interest payments from the
Company on debentures issued by the Company and held by the subsidiary trust,
which are eliminated in NSP's consolidation. The preferred securities are
redeemable at $25 per share beginning in 2002. Distributions and redemption
payments are guaranteed by NSP.
3. 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, 1997, the Company could have paid, without restrictions, additional cash
dividends of more than $1 billion on common stock.
Nonqualified stock options and restricted stock may be granted under NSP's
Executive Long-Term Incentive Award Stock Plan. The awards granted in any
calendar year cannot exceed 1 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
stock options unexercised, the weighted average number of shares of common stock
outstanding for the calculation of Earnings Per Share - Assuming Dilution
includes any dilutive effects of stock options and other stock awards as
potential common shares.
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:
<PAGE>
Stock Option and Performance Awards
<TABLE>
<CAPTION>
1997 1996 1995
----------------- ------------------ ------------------
AVERAGE Average Average
(Thousands of shares) SHARES PRICE Shares Price Shares Price
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding Jan. 1 1 117 43.97 990 $41.97 782 $40.58
Options granted in January 287 47.44 263 $50.94 278 $45.50
Options and awards exercised (260) 42.23 (105) $41.98 (64) $40.26
Options and awards forfeited (30) 47.19 (27) $47.70 (6) $44.58
Options and awards expired (11) 50.94 (4) $40.00
- ----------------------------------------------------------------------------------------------
Outstanding at Dec. 31 1 103 45.13 1 117 $43.97 990 $41.97
Exercisable at Dec. 31 843 44.41 870 $41.96 716 $40.60
==============================================================================================
</TABLE>
The following table summarizes information about stock options outstanding at
Dec. 31, 1997:
Range of Exercise Prices
-----------------------------
$33.25-40.94 $42.19-50.94
- --------------------------------------------------------------------------------
Options Outstanding:
Number outstanding at Dec. 31, 1997 170 346 923 517
Weighted-average remaining contractual life (years) 3.1 7.4
Weighted-average exercise price $37.15 $46.60
Options Exercisable:
Number exercisable at Dec. 31, 1997 170 346 663 156
Weighted-average exercise price $37.15 $46.27
In addition to stock options, 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 1995 through 1997, NSP granted
restricted stock awards of 15,898, 18,584 and 26,344 shares, respectively, at
then-current market prices of NSP stock. Compensation expense related to these
awards was immaterial.
4. Short-Term Borrowings
As of Dec. 31, 1997 and 1996, the Company had a $300 million revolving credit
facility under a commitment fee arrangement. This facility provides short-term
financing in the form of bank loans, letters of credit and support for
commercial paper sales. There were no borrowings against this facility at Dec.
31, 1997 and 1996. At Dec. 31, 1997 and 1996, credit lines of $245 million and
$75 million, respectively, were provided primarily by commercial banks to wholly
owned subsidiaries of the Company. There were $122 million and approximately $4
million in outstanding loans against these subsidiary credit lines at Dec. 31,
1997 and 1996, respectively. In addition, at Dec. 31, 1997 and 1996, $49 million
and $21 million, respectively, in letters of credit were outstanding (as
discussed in Note 11), which reduced the available credit lines.
At Dec. 31, 1997 and 1996, the Company had $138 million and $362 million,
respectively, in short-term commercial paper borrowings outstanding, and another
$122 million and $7 million, respectively, in short-term bank loans outstanding,
mainly for nonregulated subsidiaries. The weighted average interest rates on all
short-term borrowings were 6.2 percent as of Dec. 31, 1997, and 5.7 percent as
of Dec. 31, 1996.
5. 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 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 $1
billion. 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.
<PAGE>
The Company's 2011 and 2019 series First Mortgage 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 4.0 percent and 3.8 percent,
respectively, at Dec. 31, 1997. 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 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 (in millions) are:
1998, $22.8; 1999, $217.3; 2000, $122.4; 2001, $167.8; and 2002, $76.6.
6. Benefit Plans and Other Postretirement Benefits
NSP offers the following benefit plans to its benefit employees, of whom
approximately 40 percent are represented by five local labor unions under a
collective-bargaining agreement, which expires Dec. 31, 1999.
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) 1997 1996
- -------------------------------------------------------------------------------
Actuarial present value of benefit obligation:
Vested $701 219 $660 920
Nonvested 165 004 147 278
- -------------------------------------------------------------------------------
Accumulated benefit obligation $866 223 $808 198
===============================================================================
Projected benefit obligation $1 048 251 $993 821
Plan assets at fair value 1 978 538 1 634 696
- -------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 930 287 640 875
Unrecognized prior service cost 18 663 19 734
Unrecognized net actuarial gain (953 825) (651 368)
Unrecognized net transitional asset (463) (539)
- -------------------------------------------------------------------------------
Net pension asset (liability) recorded $(5 338) $8 702
===============================================================================
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:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost-benefits earned during the period $27 680 $29 971 $24 499
Interest cost on projected benefit obligation 72 651 70 863 69 742
Actual return on assets (420 174) (265 370) (344 837)
Net amortization and deferral 285 048 139 874 240 458
- ----------------------------------------------------------------------------------------------
Net periodic pension cost determined under SFAS No. 87 (34 795) (24 662) (10 138)
Additional costs recognized due to actions of regulators 30 862 23 572 10 454
- ----------------------------------------------------------------------------------------------
Net periodic pension cost recognized for financial reporting $(3 933) $(1 090) $316
==============================================================================================
</TABLE>
The weighted average discount rate used in determining the actuarial present
value of the projected obligation was 7 percent for Dec. 31, 1997 and 7.5
percent for Dec. 31, 1996. The rate of increase in future compensation levels
used in determining the actuarial present value of the projected obligation was
5 percent in 1997 and 1996. The assumed long-term rate of return on assets used
for cost determinations under SFAS No. 87 was 9 percent for
<PAGE>
1997, 1996 and 1995. Assumption changes decreased 1997 pension costs (determined
under SFAS No. 87) by approximately $6.9 million and increased 1996 costs by
approximately $12.6 million. However, 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 prevented the majority
of 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 $4.4
million in 1997, $4.3 million in 1996 and $3.7 million in 1995.
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
later. 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) 1997 1996
- ----------------------------------------------------------------------------
APBO:
Retirees $149 081 $144 180
Fully eligible plan participants 21 245 23 438
Other active plan participants 108 904 101 065
- -----------------------------------------------------------------------------
Total APBO 279 230 268 683
Plan assets at fair value 19 784 15 514
- -----------------------------------------------------------------------------
APBO in excess of plan assets 259 446 253 169
Unrecognized net actuarial loss (14 408) (12 467)
Unrecognized transition obligation (161 700) (172 480)
- ------------------------------------------------------------------------------
Net benefit liability recorded $83 338 $ 68 222
=============================================================================
The assumed health care cost trend rates used in measuring the APBO at Dec. 31,
1997 and 1996, were 9.2 percent and 9.8 percent for those under age 65, and 6.8
percent and 7.1 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 14.5 percent as of Dec. 31,
1997. Service and interest cost components of the net periodic postretirement
cost would increase by approximately 15.4 percent with a similar 1 percent
increase in the assumed health care cost trend rate. The assumed discount rate
used in determining the APBO was 7 percent for Dec. 31, 1997, and 7.5 percent
for Dec. 31, 1996, compounded annually. The assumed long-term rate of return on
assets used for cost determinations under SFAS No. 106 was 8 percent for 1997,
1996 and 1995. Assumption changes decreased costs by approximately $4.0 million
in 1997 and approximately $2.0 million in 1996.
<PAGE>
The net annual periodic postretirement benefit cost recorded consists of the
following components:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost-benefits earned during the year $5 095 $ 6 380 $ 5 206
Interest cost (on service cost and APBO) 18 872 19 283 19 201
Actual return on assets (1 461) (947) (1 046)
Amortization of transition obligation 10 780 10 780 10 780
Net amortization and deferral 222 140 406
- -------------------------------------------------------------------------------------------------
Net periodic postretirement health care cost under SFAS No. 106 33 508 35 636 34 547
Additional costs recognized due to actions of regulators 4 033 4 033
- -------------------------------------------------------------------------------------------------
Net postretirement cost recognized for financial reporting $33 508 $39 669 $38 580
=================================================================================================
</TABLE>
Regulators for nearly all of NSP's retail and wholesale customers 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 will begin in 1998 for Minnesota. For wholesale
ratemaking, the FERC has required external funding for all benefits paid and
accrued under SFAS No. 106 since 1993.
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 1997, 1996 and 1995, which represent
compensation expense, were $4.4 million, $4.6 million and $5.0 million,
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 5.6 million and 5.9 million shares of the
Company's common stock as of Dec. 31, 1997 and 1996, respectively. An average of
0.3 million, 0.2 million and 0.2 million uncommitted leveraged ESOP shares were
excluded from earnings-per-share calculations in 1997, 1996 and 1995,
respectively. The fair value of NSP's leveraged ESOP shares was approximately
the same as cost at Dec. 31, 1997 and 1996.
<PAGE>
7. 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:
<TABLE>
<CAPTION>
1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal statutory rate 35.0% 35.0% 35.0%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit 4.3% 5.2% 5.1%
Tax credits recognized (7.9)% (4.1)% (3.4)%
Equity income from unconsolidated affiliates (2.5)% (2.6)% (2.5)%
Regulatory differences---utility plant items 1.1% 0.9% 1.0%
Other---net (1.0)% 0.4% 0.4%
- ------------------------------------------------------------------------------------------------------------------
Effective income tax rate 29.0% 34.8% 35.6%
==================================================================================================================
(Thousands of dollars)
Income taxes are comprised of the following expense (benefit) items:
Included in utility operating expenses:
Current federal tax expense $125 202 $154 421 $137 011
Current state tax expense 28 812 39 923 33 359
Deferred federal tax expense (88) (19 933) (12 019)
Deferred state tax expense (23) (3 958) (2 396)
Deferred investment tax credits (9 048) (9 043) (8 807)
- ------------------------------------------------------------------------------------------------------------------
Total 144 855 161 410 147 148
- ------------------------------------------------------------------------------------------------------------------
Included in income taxes on nonregulated operations
and nonoperating items:
Current federal tax expense (19 470) (906) 5 481
Current state tax expense (5 804) 712 1 629
Current foreign tax expense 236 616 233
Current federal tax credits (17 006) (8 044) (5 292)
Deferred federal tax expense (2 237) (5 150) 2 646
Deferred state tax expense (662) (1 520) 693
Deferred foreign tax expense (2 892) 0 0
Deferred investment tax credits (310) (308) (310)
- ------------------------------------------------------------------------------------------------------------------
Total (48 145) (14 600) 5 080
- ------------------------------------------------------------------------------------------------------------------
Total income tax expense $96 710 $146 810 $152 228
==================================================================================================================
</TABLE>
Income before income taxes includes net foreign equity income of $27 million,
$28 million and $32 million in 1997, 1996 and 1995, 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 $112 million at Dec. 31, 1997. 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.
<PAGE>
The components of NSP's net deferred tax liability (current and noncurrent
portions) at Dec. 31 were:
(Thousands of dollars) 1997 1996
- --------------------------------------------------------------------------------
Deferred tax liabilities:
Differences between book and tax bases of property $867 155 $850 139
Regulatory assets 100 564 121 232
Tax benefit transfer leases 31 614 43 481
Other 21 715 23 182
- --------------------------------------------------------------------------------
Total deferred tax liabilities $1 021 048 $1 038 034
- --------------------------------------------------------------------------------
Deferred tax assets:
Regulatory liabilities $83 765 $90 485
Deferred compensation, vacation and other
accrued liabilities not currently deductible 70 765 65 690
Deferred investment tax credits 54 741 57 239
Other 26 557 34 509
- --------------------------------------------------------------------------------
Total deferred tax assets $235 828 $247 923
- --------------------------------------------------------------------------------
Net deferred tax liability $785 220 $790 111
================================================================================
8. Detail of Certain Income and Expense Items
Administrative and general (A&G) expense for utility operations consists of the
following:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
A&G salaries and wages $44 514 $47 546 $48 437
Pension, medical and other benefits---all utility employees 57 529 64 733 81 279
Information technology, facilities and administrative support 28 653 21 281 31 863
Insurance and claims 1 087 5 503 13 969
Other 10 019 9 593 10 599
- ----------------------------------------------------------------------------------------------
Total $141 802 $148 656 $186 147
==============================================================================================
</TABLE>
Income from nonregulated businesses consists of the following:
<TABLE>
<CAPTION>
(Thousands of dollars, except per share amounts) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $217 844 $303 903 $313 082
Equity in earnings of unconsolidated affiliates:
Earnings from operations 18 600 30 668 28 055
Gains from contract terminations 29 850
Operating and development expenses * (251 087) (326 332) (327 894)
Interest and other income 26 721 10 304 6 518
- ----------------------------------------------------------------------------------------------------
Income from nonregulated businesses before interest and taxes 12 078 18 543 49 611
Interest expense (34 627) (18 834) (9 879)
Income tax benefit (expense) 38 032 16 576 (6 119)
- -----------------------------------------------------------------------------------------------------
Net Income $15 483 $16 285 $33 613
====================================================================================================
Contribution of nonregulated businesses to NSP's earnings per share* $0.22 $0.24 $0.50
====================================================================================================
</TABLE>
* Includes nonrecurring project write-downs of $9 million in 1997 and $5 million
in 1995
<PAGE>
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:
<TABLE>
<CAPTION>
Remaining
(Thousands of dollars) Amortization Period 1997 1996
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
AFC recorded in plant on a net-of-tax basis * Plant Lives $128 364 $137 412
Conservation and energy management programs * Primarily 3 Years 86 508 95 716
Losses on reacquired debt Term of Related Debt 59 353 63 481
Environmental costs Primarily 10 Years 45 849 42 322
State commission accounting adjustments * Plant Lives 7 286 7 296
Unrecovered purchased gas costs 1-2 Years 8 020 3 885
Other Various 4 742 4 016
- -----------------------------------------------------------------------------------------------------------
Total regulatory assets $340 122 $354 128
===========================================================================================================
Deferred income tax adjustments 88 035 $92 390
Investment tax credit deferrals 91 146 97 636
Unrealized gains from decommissioning investments 85 482 43 008
Pension costs-regulatory differences 27 107 45 080
Fuel costs, refunds and other 13 995 24 533
- -----------------------------------------------------------------------------------------------------------
Total regulatory liabilities $305 765 $302 647
===========================================================================================================
</TABLE>
* Earns a return on investment in the ratemaking process
10. 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:
<TABLE>
<CAPTION>
Name Geographic Area Economic Interest
- ------------------------------------------------------------------------------------
<S> <C> <C>
Loy Yang Power * Australia 25.37%
Pacific Generation Company * USA/Canada 8.50%-28.70%
Gladstone Power Station Australia 37.50%
COBEE South America 48.30%
MIBRAG mbH Europe 33.33%
NRG Generating (U.S.) Inc. USA 45.21%
Schkopau Power Station Europe 20.55%
Energy Development, Limited * Australia 19.97%
Scudder Latin American Trust
for Independent Power Energy Projects Latin America 25%
Various independent power production facilities * USA 45%-50%
Various affordable housing limited partnerships * USA 20%-99%
</TABLE>
*Acquired in 1997
<PAGE>
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)
1997 1996 1995
---- ---- ----
Operating Revenues $1 698 $958 $790
Operating Income $ 93 $105 $154
Net Income $ 84 $89 $160
NSP's Equity in Earnings of
Unconsolidated Affiliates $19 $31 $59
FINANCIAL POSITION
(Millions of dollars)
1997 1996
---- ----
Current Assets $ 742 $ 681
Other Assets 7 853 3 525
----- ------
Total Assets $8 595 $4 206
====== ======
Current Liabilities $ 514 $ 397
Other Liabilities 6 109 2 798
Equity 1 972 1 011
----- ------
Total Liabilities and Equity $8 595 $4 206
====== ======
NSP's Equity Investment in
Unconsolidated Affiliates $ 741 $410
11. Financial Instruments
FAIR VALUES The estimated Dec. 31 fair values of NSP's recorded financial
instruments are as follows:
<TABLE>
<CAPTION>
1997 1996
- ------------------------------------------------------------------------------------------------------------------
CARRYING FAIR Carrying Fair
(Thousands of dollars) AMOUNT VALUE Amount Value
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash, cash equivalents and short-term investments $54 765 $54 765 $51 118 $51 118
Long-term decommissioning investments $344 491 $344 491 $260 756 $260 756
Long-term debt, including current portion $2 043 295 $2 079 123 $1 853 786 $1 838 408
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
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 forward foreign currency exchange contracts
with counterparties to hedge certain exposures to currency fluctuations.
Pursuant to these contracts, transactions have been executed that are designed
to protect the economic value in U.S. dollars of selected known and anticipated
NRG cash flows denominated in Australian dollars and German deutsche marks. As
of Dec. 31, 1997, NRG had in place contracts with a notional value of $10
million to hedge foreign currency denominated known future cash flows. In
addition, NRG has in place forward foreign currency exchange contracts with a
net notional value of $8.6 million to hedge projected construction expenditures,
which do not qualify for hedge accounting and consequently result in currency
fluctuations that can affect earnings. The effect on 1997 earnings from these
contracts was immaterial. The forward foreign currency exchange contracts
terminate in 1998. If all of the contracts had been terminated at Dec. 31, 1997,
$1.0 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.
<PAGE>
NRG also has two agreements in place, with a notional amount of $80 million, to
fix the interest rate at a rate based on U.S. Treasury obligations for known
future borrowings related to project investment commitments. If the agreements
had been terminated at Dec. 31, 1997, $4.2 million would have been payable by
NRG based on the underlying U.S. Treasury interest rate on that date.
EMI has entered into natural gas futures contracts in the notional amount of $23
million at Dec. 31, 1997. The original contract terms range from one month to
two 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 EMI's natural gas reserves. EMI's
futures contracts hedge $24 million in anticipated natural gas sales in
1998-1999. Margin balances of $3 million at Dec. 31, 1997, 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, investment banks 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, 1997, $0.7 million would have been
payable by EMI for natural gas price fluctuations to date.
NSP has two interest rate swap agreements with notional amounts totaling $220
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 the six-month London
Interbank Offered Rate (LIBOR), with the rates changing semiannually.
Term of Net Effective
Notional Amount Swap Interest Cost at
Series (millions of dollars) Agreement at Dec. 31, 1997
- --------------------------------------------------------------------------------
5 1/2% Series due Feb. 1, 1999 $200 Maturity 5.49%
7 1/4% Series due March 1, 2023 $ 20 March 1, 1998 7.96%
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, 1997, $0.6 million would
have been payable by the Company, while the present value of the related fixed
rate debt was $0.6 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 EMI natural gas purchases, generally with terms of
one year which are automatically renewed, unless prior written notice of
cancellation is provided to NSP and the beneficiary by the issuing bank. In
addition, NRG uses letters of credit for nonregulated equity commitments, as
collateral for credit agreements, for fuel purchase and operating commitments
and bids on development projects. At Dec. 31, 1997, letters of credit of $101
million were outstanding, of which $48 million related to NRG commitments. 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 part owner of an 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, 1997 and 1996, was $603.9 million and $588.0 million, respectively. The
corresponding accumulated provisions for depreciation were $196.2 million and
$168.6 million.
<PAGE>
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 $10.1 million, $11.3 million and $12.3
million in 1997, 1996 and 1995, respectively. The cumulative amount of such
assessments paid by NSP to the DOE through Dec. 31, 1997, was approximately $250
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. 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.
The Company and other affected parties have commenced lawsuits against the DOE
to require the DOE to meet its statutory and contractual obligations, which can
include damages for nonperformance. NSP and other utilities are currently
analyzing claims against the DOE for the costs incurred as a result of the DOE's
failure to meet its statutory and contractual obligations. 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 Prairie Island nuclear plant until at least 2007. 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. 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.
Nuclear fuel expenses in 1997, 1996 and 1995 include about $4 million, $4
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 1997 was $3.9
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 $38 million at Dec. 31, 1997, 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, would require the full accrual of
nuclear plant decommissioning and certain other site exit obligations no sooner
than 1999. Using Dec. 31, 1997, estimates, NSP's adoption of the proposed
accounting would result in the recording of the total discounted decommissioning
obligation of $698 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 later.
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.
<PAGE>
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, 1997, primarily consisted of investments in fixed
income securities, such as tax-exempt municipal bonds and U.S. government
securities, which mature in two to 26 years, and common stock of public
companies. The Company plans to reinvest matured securities until
decommissioning commences.
At Dec. 31, 1997, the Company has recorded and recovered in rates cumulative
decommissioning accruals of $465 million. The following table summarizes the
funded status of the Company's decommissioning obligation at Dec. 31, 1997:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997
- ---------------------------------------------------------------------------------------------------------
<S> <C>
Estimated decommissioning cost obligation from most recent approved study (1993 dollars) $750 824
Effect of escalating costs to 1997 dollars (at 4.5% per year) 144 548
- ---------------------------------------------------------------------------------------------------------
Estimated decommissioning cost obligation in current dollars 895 372
Effect of escalating costs to payment date (at 4.5% per year) 949 413
- ---------------------------------------------------------------------------------------------------------
Estimated future decommissioning costs (undiscounted) 1 844 785
Effect of discounting obligation (using risk-free interest rate) (1 147 177)
- ---------------------------------------------------------------------------------------------------------
Discounted decommissioning cost obligation 697 608
External trust fund assets at fair value 344 491
- ---------------------------------------------------------------------------------------------------------
Discounted decommissioning obligation in excess of assets currently held in external trust $353 117
=========================================================================================================
</TABLE>
Decommissioning expenses recognized include the following components:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Annual decommissioning cost accrual reported as depreciation expense:
Externally funded $33 178 $33 178 $33 178
Internally funded (including interest costs) 1 368 1 268 1 174
Interest cost on externally funded decommissioning obligation 7 690 5 246 5 966
Earnings from external trust funds (7 690) (6 294) (5 620)
- -----------------------------------------------------------------------------------------------------
Net decommissioning accruals recorded $34 546 $33 398 $34 698
====================================================================================================
</TABLE>
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
Utility Income and Deductions on the income statement.
The MPUC last approved a nuclear decommissioning study and related nuclear plant
depreciation capital recovery request in April 1997, using cost data from the
1993 study. Although management expects to operate the Prairie Island units
through the end of each unit's licensed life, 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 each unit's licensed life. The approved recovery period for Prairie Island
has been reduced because of the uncertainty regarding used fuel storage, as
discussed previously. The Company believes future decommissioning cost accruals
will continue to be recovered in customer rates.
<PAGE>
14. Commitments and Contingent Liabilities
CAPITAL COMMITMENTS NSP estimates utility capital expenditures, including
acquisitions of nuclear fuel, will be $441 million in 1998 and $2.1 billion for
1998-2002. There also are contractual commitments for the disposal of used
nuclear fuel. (See Note 13.)
As of Dec. 31, 1997, NRG is contractually committed to additional equity
investments of approximately $35 million in 1998 and approximately $172 million
for 1998-2002 for various international power generation projects. In addition,
in 1996, NRG executed an agreement whereby NRG is obligated to provide to NRG
Generating (U.S.) Inc. (NRGG), an unconsolidated affiliate of NRG, 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.
As required by the agreement, NRG provided several investment opportunities to
NRGG in 1997, and, as a result, NRGG purchased the Millennium project from NRG.
NRGG financed the Millennium purchase from sources other than NRG.
LEGISLATIVE RESOURCE COMMITMENTS In 1994, the Minnesota Legislature established
several energy resource and other commitments for NSP to obtain the Prairie
Island temporary nuclear fuel storage facility approval. The commitments, which
can be met by building, purchasing or, in the case of biomass, converting
generation resources, are:
Power Type Megawatts Required Contract Deadline
- ----------------------------------------------------------------------------
Wind 100 (Additional) 12/31/96
Wind 100 (Additional) 12/31/98
Wind 200 (Additional) 12/31/02
Total Wind 400
Biomass 50 (Additional) 12/31/98
Biomass 75 (Additional) 12/31/98
--
Total Biomass 125
The Company is complying with the requirements of these resource commitments as
follows:
Power Type Developer Megawatts Operation Date
- --------------------------------------------------------------------------------
Wind Lake Benton Power Partners LLC (1) 107.25 June 1998 (2)
Wind Northern Alternative Energy, Inc. 22.65 Oct. 1998 (2)
Wind Lake Benton Power Partners II LLC 100.50 Mid-1999 (3)
Wind Woodstock Wind Farm, LLC 10.20 Oct. 1998 (2)
-------
Total Wind 240.60
Biomass Minnesota Valley Alfalfa Producers (4) 75.00 Dec. 2001 (5)
Biomass District Energy St. Paul Inc. 25.00 Summer 2002 (6)
Biomass Lindroc Energy 25.00 Summer 2002 (6)
-------
Total Biomass 125.00
(1) Formerly Zond Minnesota Development Corporation II
(2) Approved by MPUC
(3) Selected after a competitive negotiation process
(4) Formerly Minnesota Agri-Power Project
(5) Agreement signed
(6) Selected after a competitive bid process
<PAGE>
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. The first four casks were available in 1994. In late 1996, the MEQB
certified that NSP has met the requirements necessary to use the sixth through
ninth casks at the Prairie Island nuclear generating facility. The final eight
casks become available in 1999 unless the above resource commitments are not met
and the Minnesota Legislature revokes its approval. As of Dec. 31, 1997, the
Company had loaded seven casks.
Other commitments established by the Legislature include a discount for
low-income 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.
GUARANTEES In 1997 and 1996, the Company sold a portion of its other
receivables, consisting of energy loans made to customers, to a third party. The
portion of the receivables sold consisted of customer loans to local government
entities for energy efficiency improvements under various conservation programs
offered by the Company. Under the sale agreements, the Company is required to
guarantee repayment to the third party of the remaining loan balances. At Dec.
31, 1997, the outstanding balance of the loans was approximately $28 million.
Based on prior collection experience of these loans, the Company believes that
losses under the loan guarantees, if any, would have an immaterial impact on the
results of operations.
LEASES Rentals under operating leases were approximately $32 million, $29
million and $27 million for 1997, 1996 and 1995, 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 1998 and
2013, require minimum purchases and deliveries of fuel, and additional payments
for the right to purchase coal in the future. In total, NSP is committed to the
minimum purchase of approximately $341 million of coal, $29 million of nuclear
fuel and $291 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 developed 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 1998-2005 500
Seasonal Diversity Exchanges:
Summer exchanges from MH 1998-2014 150
1998-2016 200
Winter exchanges to MH 1998-2014 150
1998-2015 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
the 500-megawatt MH agreement is estimated to be approximately $55 million.
There are no capacity payments for the diversity exchanges. These commitments to
MH represent about 17 percent of MH's system capability in 1998 and account for
approximately 10 percent of NSP's 1998 electric system capability. The
<PAGE>
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 1998 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 1998-2000.
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 1998 cost of these commitments for
nonregulated capacity is approximately $46 million for 360 megawatts of summer
capacity. This commitment is expected to remain at this level until 2012, at
which time it will decrease to approximately $39 million annually and then
gradually decrease to approximately $26 million in the year 2027 due to the
expiration of existing agreements.
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 $1.5 billion for each of the Company's two
nuclear plant sites. The coverage consists of $500 million from Nuclear Mutual
Limited (NML) and $1.0 billion from Nuclear Electric Insurance Limited (NEIL).
NEIL also provides business interruption insurance coverage, including the cost
of replacement power obtained during certain prolonged accidental outages of
nuclear generating units. Premiums billed to NSP from NML and NEIL are expensed
over the policy term. All companies insured with NML and NEIL are subject to
retrospective premium adjustments if losses exceed accumulated reserve funds.
Capital has been accumulated in the reserve funds of NML and NEIL to the extent
that the Company would have no exposure for retrospective premium assessments in
case of a single incident under the business interruption and the property
damage insurance coverages. However, in each calendar year, the Company could be
subject to maximum assessments of approximately $4.6 million for business
interruption insurance (five times the amount of its annual premium) and $19.0
million for property damage insurance (generally five times the amount of its
annual premium) if losses exceed accumulated reserve funds.
ENVIRONMENTAL CONTINGENCIES Other long-term liabilities include an accrual of
$34 million, and other current liabilities include an accrual of $6 million at
Dec. 31, 1997, for estimated costs associated with environmental remediation.
Approximately $31 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 15 waste
disposal sites to which the Company allegedly sent hazardous materials. Ten of
these 15 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 five unremediated sites, the total remediation costs are currently
estimated to be approximately $11 million. If additional remediation is
necessary or unexpected costs are incurred, the amount
<PAGE>
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 five 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 $750,000 for its share of
future costs for these five sites, including $700,000 that is expected to be
paid in 1998. 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 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. Three sites are solid and hazardous waste landfill sites in Eau
Claire, Rice Lake 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 Wisconsin
Department of Natural Resources (WDNR) named the Wisconsin Company as one of
three Responsible Parties for creosote and coal tar contamination at a fourth
site in Ashland, Wis. 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, 1997, the Company
had recorded an estimated liability of $880,000 for future remediation costs
associated with the Wisconsin Company-owned portion of the Ashland site. Through
Dec. 31, 1997, the Wisconsin Company has incurred approximately $646,000 in
actual expenditures to date. Based on a recent Public Service Commission of
Wisconsin decision to allow recovery of incremental costs incurred for this site
beginning in 1997, 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, Rice Lake 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 at these two sites, which began in 1997. As of Dec. 31, 1997,
the Company has paid $8.1 million for the six active sites and has recorded an
estimated liability of approximately $3.0 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. Environmental remediation costs may be
recovered from insurance carriers, third parties, or in future rates. The MPUC
allowed the Company to defer certain remediation costs of four active sites in
1994 and the Company requested, in its December 1997 gas rate case, recovery of
these accumulated costs. In January 1998, the MPUC allowed the recovery of these
gas site remediation costs in the interim gas rates that went into effect in
February 1998. Accordingly, the Company has recorded an environmental regulatory
asset for these costs (see Note 9). The Company may request recovery of costs to
remedy the other two active sites following the completion of preliminary
investigations.
The Clean Air Act, including the Amendments of 1990 (the Clean Air Act), calls
for reductions in emissions of sulfur dioxide and nitrogen oxides from electric
generating plants. These reductions, which will be phased in, began in 1995. The
majority of the rules implementing this complex legislation have been finalized.
NSP has invested significantly over the years to reduce sulfur dioxide emissions
at its plants. No additional capital
<PAGE>
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 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 $45
million in 1997 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.
15. Segment Information
<TABLE>
<CAPTION>
Year Ended December 31
---------------------------------------
(Thousands of dollars) 1997 1996 1995
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Utility operating income before income taxes
Electric $456 489 $469 321 $444 687
Gas 50 122 58 133 48 340
- -----------------------------------------------------------------------------------------------
Total utility operating income before income taxes $506 611 $527 454 $493 027
===============================================================================================
Utility depreciation and amortization
Electric $299 226 $279 828 $266 231
Gas 26 654 26 604 23 953
- -----------------------------------------------------------------------------------------------
Total utility depreciation and amortization $325 880 $306 432 $290 184
===============================================================================================
Utility capital expenditures
Electric $305 292 $323 532 $317 750
Gas 71 386 42 225 37 215
Common 19 927 20 898 31 057
- -----------------------------------------------------------------------------------------------
Total utility capital expenditures $396 605 $386 655 $386 022
===============================================================================================
Identifiable utility assets
Electric $4 845 306 $4 735 330 $4 751 650
Gas 675 030 649 218 600 738
- -----------------------------------------------------------------------------------------------
Total identifiable utility assets $5 520 336 $5 384 548 $5 352 388
Other corporate assets * 1 623 730 1 252 352 876 197
- -----------------------------------------------------------------------------------------------
Total assets $7 144 066 $6 636 900 $6 228 585
===============================================================================================
</TABLE>
* Includes equity investments for nonregulated energy projects outside of the
United States of $517 million in 1997, $295 million in 1996 and $185 million
in 1995.
Note: The gas utility segment includes Viking.
<PAGE>
16. Summarized Quarterly Financial Data (Unaudited)
<TABLE>
<CAPTION>
Quarter Ended
- ------------------------------------------------------------------------------------------------------------------
(Thousands of dollars) March 31, 1997 June 30, 1997* Sept. 30,1997 Dec. 31, 1997*
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Utility operating revenues $742 496 $594 323 $697 443 699 484
Utility operating income 88 456 65 586 118 540 89 174
Net income 65 773 18 253 87 912 65 382
Earnings available for common stock 61 816 15 882 85 541 63 010
Earnings per average common share:
Basic $0.90 $0.23 $1.23 $0.85
Assuming dilution $0.90 $0.23 $1.23 $0.85
Dividends declared per common share $0.690 $0.705 $0.705 $0.705
Stock prices---high $49 1/8 $52 $52 15/16 $58 7/8
---low $45 1/2 $44 1/2 $48 $48 7/16
Quarter Ended
- ------------------------------------------------------------------------------------------------------------------
(Thousands of dollars) March 31, 1996 June 30, 1996 Sept. 30, 1996 Dec. 31, 1996
- ------------------------------------------------------------------------------------------------------------------
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:
Basic $0.94 $0.59 $1.18 $1.12
Assuming dilution $0.94 $0.59 $1.18 $1.11
Dividends declared per common share $0.675 $0.690 $0.690 $0.690
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
</TABLE>
* 1997 results include two nonrecurring items: a $29 million pretax charge,
which reduced second quarter earnings by 25 cents per share, for the
write-off of merger costs; and a $9 million pretax charge, which reduced
fourth quarter earnings by 8 cents per share, for the write-down of an NRG
cogeneration project.
<PAGE>
REPORTS OF MANAGEMENT AND INDEPENDENT ACCOUNTANTS
REPORT OF MANAGEMENT
Management is responsible for the preparation and integrity of NSP's financial
statements. The financial statements have been prepared in accordance with
generally accepted accounting principles and necessarily include some amounts
that are based on management's estimates and judgment.
To fulfill its responsibility, management maintains a strong internal control
structure, supported by formal policies and procedures that are communicated
throughout NSP. Management also maintains a staff of internal auditors who
evaluate the adequacy of and investigate the adherence to these controls,
policies and procedures.
Our independent public accountants have audited the financial statements and
have rendered an opinion as to the statements' fairness of presentation, in all
material respects, in conformity with generally accepted accounting principles.
During the audit, they obtained an understanding of NSP's internal control
structure, and performed tests and other procedures to the extent required by
generally accepted auditing standards.
The Board of Directors pursues its oversight role with respect to NSP's
financial statements through the Audit Committee, which is comprised solely of
nonmanagement directors. The Committee meets periodically with the independent
public accountants, internal auditors and management to assure that all are
properly discharging their responsibilities. The Committee approves the scope of
the annual audit and reviews the recommendations the independent public
accountants have for improving the internal control structure. The Board of
Directors, on the recommendation of the Audit Committee, engages the independent
public accountants, subject to shareholder approval.
Both the independent public accountants and the internal auditors have
unrestricted access to the Audit Committee.
/s/
James J. Howard
Chairman of the Board, President
and Chief Executive Officer
/s/
Edward J. McIntyre
Vice President and Chief
Financial Officer
NORTHERN STATES POWER COMPANY
MINNEAPOLIS, MINNESOTA
FEB. 2, 1998
<PAGE>
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, 1997 and 1996, and the results of
their operations and their cash flows for each of the three years in the period
ended Dec. 31, 1997, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
/s/
PRICE WATERHOUSE LLP
MINNEAPOLIS, MINNESOTA
FEB. 2, 1998
