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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended Commission file number: 1-3034
December 31, 1998
NORTHERN STATES POWER COMPANY
(Exact name of Registrant as specified in its charter)
MINNESOTA 41-0448030
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
414 NICOLLET MALL, MINNEAPOLIS, MINNESOTA 55401
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 612-330-5500
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, $2.50 Par Value New York Stock Exchange,
Chicago Stock Exchange and
Pacific Stock Exchange
Cumulative Preferred Stock, $100
Par Value each
Preferred Stock $ 3.60 Cumulative New York Stock Exchange
Preferred Stock $ 4.08 Cumulative New York Stock Exchange
Preferred Stock $ 4.10 Cumulative New York Stock Exchange
Preferred Stock $ 4.11 Cumulative New York Stock Exchange
Preferred Stock $ 4.16 Cumulative New York Stock Exchange
Preferred Stock $ 4.56 Cumulative New York Stock Exchange
Trust Originated Preferred Securities 7 7/8% New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K.
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Indicate by check mark whether the Registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the Registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes X No
--- ---
As of March 15, 1999, the aggregate market value of the voting common
stock held by non-affiliates of the Registrant was $4,155,445,652 and there
were 153,135,652 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE
The Registrant's Definitive Proxy Statement for its 1999 meeting of
Shareholders to be held on April 28, 1999, is incorporated by reference
into Part III of Form 10-K.
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INDEX
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Page No.
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PART I
Item 1 - Business.................................................................................................1
RECENT EVENTS - PROPOSED MERGER................................................................................1
UTILITY REGULATION AND REVENUES
General.....................................................................................................2
Revenues....................................................................................................2
General Rate Filings........................................................................................3
Ratemaking Principles in Minnesota and Wisconsin............................................................3
Fuel and Purchased Gas Adjustment Clauses...................................................................3
Resource Adjustment Clauses.................................................................................4
Rate Matters by Jurisdiction................................................................................4
ELECTRIC UTILITY OPERATIONS
Competition.................................................................................................5
Independent Transmission Company............................................................................7
Independent Nuclear Generating Company......................................................................7
Technological Improvements..................................................................................7
Capability and Demand.......................................................................................8
Energy Sources..............................................................................................9
Fuel Supply and Costs.......................................................................................9
Nuclear Power Plants - Licensing, Operation and Waste Disposal.............................................10
Electric Operating Statistics..............................................................................12
GAS UTILITY OPERATIONS
Competition/Regulation.....................................................................................13
Business Growth............................................................................................13
Standards..................................................................................................14
Capability and Demand......................................................................................14
Gas Supply and Costs.......................................................................................14
Viking Gas Transmission Company ...........................................................................15
Gas Operating Statistics ..................................................................................16
NONREGULATED SUBSIDIARIES
NRG Energy, Inc. ..........................................................................................17
Energy Masters International, Inc. ........................................................................19
Eloigne Company............................................................................................19
Seren Innovations, Inc.....................................................................................20
Ultra Power Technologies, Inc..............................................................................20
Nonregulated Business Information..........................................................................20
ENVIRONMENTAL MATTERS.........................................................................................21
CAPITAL SPENDING AND FINANCING................................................................................22
EMPLOYEES AND EMPLOYEE BENEFITS...............................................................................23
EXECUTIVE OFFICERS............................................................................................24
Item 2 - Properties..............................................................................................26
Item 3 - Legal Proceedings.......................................................................................27
Item 4 - Submission of Matters to a Vote of Security Holders.....................................................28
PART II
Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters...................................28
Item 6 - Selected Financial Data.................................................................................28
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations.....................................................................29
Item 7A - Quantitative and Qualitative Disclosures about Market Risk.............................................39
Item 8 - Financial Statements and Supplementary Data.............................................................39
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.....................................................................61
PART III
Item 10 - Directors and Executive Officers of the Registrant.....................................................61
Item 11 - Executive Compensation.................................................................................61
Item 12 - Security Ownership of Certain Beneficial Owners and Management.........................................61
Item 13 - Certain Relationships and Related Transactions.........................................................61
PART IV
Item 14 - Exhibits, Financial Statement Schedules, and Reports on Form 8-K.......................................62
SIGNATURES.......................................................................................................67
EXHIBIT (EXCERPT)
Statement Pursuant to Private Securities Litigation Reform Act of 1995...........................................68
PART I
ITEM 1 - BUSINESS
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Northern States Power Company (NSP-Minnesota) was incorporated in 1909
under the laws of Minnesota. Its executive offices are located at 414 Nicollet
Mall, Minneapolis, Minnesota 55401. (Phone 612-330-5500). NSP-Minnesota has two
significant subsidiaries, Northern States Power Company, a Wisconsin corporation
(NSP-Wisconsin), and NRG Energy, Inc. (NRG). NSP-Minnesota also has several
other subsidiaries, including: Energy Masters International, Inc. (EMI); Viking
Gas Transmission Company (Viking); Eloigne Company (Eloigne); Seren Innovations,
Inc. (Seren); and Ultra Power Technologies, Inc. (Ultra Power). NSP-Minnesota
and its subsidiaries collectively are referred to as NSP.
NSP is predominantly an operating public utility engaged in the
generation, transmission and distribution of electricity throughout an
approximately 49,000-square-mile service area; and the transportation, storage
and distribution of natural gas in approximately 160 communities. NRG operates
several nonregulated energy businesses and is an equity investor in many
nonregulated energy affiliates throughout the world.
NSP-Minnesota serves retail customers in Minnesota, North Dakota, South
Dakota and Arizona. NSP-Wisconsin serves retail customers in Wisconsin and
Michigan. Of the approximately 3.4 million people served by NSP-Minnesota and
NSP-Wisconsin, the majority are concentrated in the Minneapolis-St. Paul
metropolitan area. In 1998, about 63 percent of NSP's electric retail revenue
was from the Minneapolis-St. Paul metropolitan area and about 53 percent of
retail gas revenue came from sales in the St. Paul metropolitan area.
NSP's utility businesses are currently experiencing some of the
challenges common to regulated electric and gas utility companies, namely,
increasing competition, increasing pressure to control costs, uncertainties
in regulatory processes and increasing costs of compliance with environmental
laws and regulations. In addition, there are uncertainties related to
permanent disposal of spent nuclear fuel. A growing portion of NSP's earnings
comes from nonregulated operations. The nonregulated projects can carry a
higher level of risk than NSP's traditional utility businesses. For further
discussion of these matters see Management's Discussion and Analysis under
Item 7 and Notes to Financial Statements under Item 8.
Except for the historical information contained herein, the matters
discussed in this Form 10-K are forward-looking statements that are subject
to certain risks, uncertainties and assumptions as discussed in Management's
Discussion and Analysis under Item 7 and Exhibit 99.01 to this report on Form
10-K.
RECENT EVENTS - PROPOSED MERGER
On March 24, 1999, Northern States Power Company (NSP) and New Century
Energies, Inc., a Delaware corporation (NCE), entered into an Agreement and
Plan of Merger (the Merger Agreement) providing for a strategic business
combination of NCE and NSP. Pursuant to the Merger Agreement, NCE will be
merged with and into NSP with NSP as the surviving corporation in the Merger.
A copy of the Merger Agreement is filed as Exhibit 2.01 to this Form 10-K.
Subject to the terms of the Merger Agreement, at the time of the Merger, each
share of NCE common stock, par value $1.00 per share (NCE Common Stock),
(other than certain shares to be canceled) together with any associated
purchase rights, will be converted into the right to receive 1.55 shares of
NSP common stock, par value $2.50 per share (NSP Common Stock). Cash will be
paid in lieu of any fractional shares of NSP Common Stock which holders of
NCE Common Stock would otherwise receive. The Merger is expected to be a
tax-free stock-for-stock exchange for shareholders of both companies and to
be accounted for as a pooling of interests.
Pursuant to employment agreements, Mr. James J. Howard, Chairman and
Chief Executive Officer of NSP will serve as Chairman of the combined company
for one year following the Merger and Mr. Wayne H. Brunetti, Vice Chairman,
President and Chief Operating Officer of NCE, will be President and Chief
Executive Officer following the Merger and will assume the responsibilities
of Chairman when Mr. Howard retires. A copy of Mr. Howard's employment
agreement is filed as Exhibit 10.14 to this Form 10-K.
Consummation of the Merger is subject to certain closing conditions,
including, among others, approval by the shareholders of NSP and NCE,
approval or regulatory review by certain state utilities regulators, the
Securities and Exchange Commission under the Public Utility Holding Company
Act of 1935, as amended, the Federal Energy Regulatory Commission, the
Nuclear Regulatory Commission, the Federal Communications Commission and
expiration or termination of the waiting period applicable to the Merger
under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.
Each of NCE and NSP have agreed to certain undertakings and limitations
regarding the conduct of their businesses prior to the closing of the
transaction. The Merger is expected to take from 12 to 18 months to complete.
NSP is expected to hold a special shareholders' meeting later this year
to vote on the Merger. All shareholders will receive a detailed proxy
statement prior to the meeting, which will explain in detail the terms of the
Merger, membership on the Board of Directors, employment arrangements and
other matters related to the Merger.
1
UTILITY REGULATION AND REVENUES
GENERAL
Retail sales rates, services and other aspects of NSP-Minnesota's
operations are subject to the jurisdiction of the Minnesota Public Utilities
Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South
Dakota Public Utilities Commission (SDPUC) and the Arizona Corporation
Commission (ACC) within their respective states. The MPUC also possesses
regulatory authority over aspects of NSP-Minnesota's financial activities,
including security issuances, property transfers within the state of Minnesota
when the asset value is in excess of $100,000, mergers with other utilities, and
transactions between NSP-Minnesota and its affiliates. In addition, the MPUC
reviews and approves NSP-Minnesota's electric resource plans and gas supply
plans for meeting customers' future energy needs. NSP-Wisconsin is subject to
regulation of similar scope by the Public Service Commission of Wisconsin (PSCW)
and the Michigan Public Service Commission (MPSC). In addition, each of the
state commissions certifies the need for new generating plants and electric and
retail gas transmission lines of designated capacities to be located within the
respective states before the facilities may be sited and built.
Wholesale rates for electric transmission service and electric energy sold
in interstate commerce, hydro facility licensing, the wholesale gas
transportation rates of Viking, the siting and construction of facilities by
Viking and certain other activities of NSP-Minnesota, NSP-Wisconsin and Viking
are all subject to the jurisdiction of the Federal Energy Regulatory Commission
(FERC). NSP also is subject to the jurisdiction of other federal, state and
local agencies in many of its activities.
The Minnesota Environmental Quality Board (MEQB) is empowered to select
and designate sites for new power plants with a capacity of 50 megawatts (MW) or
more, wind energy conversion plants with a capacity of 5 MW or more, and routes
for electric transmission lines with a capacity of 200 kilovolts (KV) or more,
as well as evaluate such sites and routes for environmental compatibility. The
MEQB may designate sites or routes from those proposed by power suppliers or
those developed by the MEQB. No such power plant or transmission line may be
constructed in Minnesota except on a site or route designated by the MEQB.
NSP is unable to predict the impact on its operating results from the
future regulatory activities of any of the above agencies. NSP strives to comply
with all rules and regulations issued by the various agencies.
REVENUES
NSP's financial results depend, in part, on its ability to obtain adequate
and timely rate relief from the various regulatory bodies, its ability to
control costs and the success of its nonregulated activities. NSP's 1998 utility
operating revenues, excluding non-firm electric sales to other utilities of $127
million and miscellaneous revenues of $86 million, were subject to regulatory
jurisdiction as follows:
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Authorized Return on Common Percent of Total
Equity at Dec. 31,1998 1998 Utility Revenues
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ELECTRIC GAS (ELECTRIC & GAS)
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Retail:
Minnesota Public Utilities Commission 11.47% 11.4%** 75.3%
Public Service Commission of Wisconsin 11.9 11.9 14.1
North Dakota Public Service Commission 11.5 12.0** 5.2
South Dakota Public Utilities Commission * 3.2
Michigan Public Service Commission 12.25 12.62 0.5
Arizona Corporation Commission 11.5 0.2
Sales for Resale - Wholesale, Viking Gas and Interstate
Transmission: Federal Energy Regulatory Commission * * 1.5
Total 100.0%
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* Settlement proceeding, based upon revenue levels granted with no specified
return.
** Reflects return on equity underlying various rate settlements.
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2
GENERAL RATE FILINGS
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General rate increases (other than fuel and resource adjustment rate
changes) requested and granted in the last five years were as follows (represent
annual amounts effective in those years):
Annual Increase/(Decrease)
--------------------------
(Millions of dollars) Year Requested Granted
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1994 (1.0) (1.0)
1995 (0.8) (0.8)
1996 2.2 (2.8)
1997 -- --
1998 29.5 18.8
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RATEMAKING PRINCIPLES IN MINNESOTA AND WISCONSIN
The MPUC accepts the use of a forecast test year that corresponds to the
period when rates are put into effect and allows collection of interim rates
subject to refund. The use of a forecast test year and interim rates minimizes
regulatory lag.
The MPUC must order interim rates within 60 days of a rate case filing.
Minnesota statutes allow interim rates to be set using (1) updated expense and
rate base items similar to those previously allowed, and (2) a return on common
equity equal to that granted in the last MPUC order for the utility. The MPUC
must make a determination on the application within 10 months after filing. If
the final determination does not permit the full amount of the interim rates,
the utility must refund the excess revenue collected, with interest. To the
extent final rates exceed interim rates, the final rates become effective at the
time of the order and retroactive recovery of the difference is not permitted.
Minnesota law allows Construction Work in Progress (CWIP) in a utility's
rate base. The MPUC has generally included Allowance for Funds Used During
Construction (AFC) in revenue requirements for rate proceedings. However, cash
earnings are allowed on small and short-term projects that do not qualify for
AFC.
The PSCW has a biennial filing requirement for processing rate cases and
monitoring utilities' rates. By June 1 of each odd-numbered year, NSP-Wisconsin
must submit filings for calendar test years beginning the following Jan. 1. The
filing procedure and subsequent review generally allow the PSCW sufficient time
to issue an order effective with the start of the test year.
The PSCW reviews each utility's cash position to determine if a current
return on CWIP will be allowed. The PSCW will allow either a return on CWIP or
capitalization of AFC at the adjusted overall cost of capital. NSP-Wisconsin
currently capitalizes AFC on production and transmission CWIP at the FERC
formula rate and on all other CWIP at the adjusted overall cost of capital.
FUEL AND PURCHASED GAS ADJUSTMENT CLAUSES
NSP-Minnesota's retail electric rate schedules, and most of
NSP-Wisconsin's wholesale rate schedules, provide for adjustments to billings
and revenues for changes in the cost of fuel and purchased energy.
NSP-Minnesota's wholesale electric sales customers do not have a fuel clause
provision in their contracts. Instead of fuel clause recovery, the contracts
provide a fixed rate with an escalation factor.
NSP-Wisconsin does not have an automatic electric fuel adjustment clause
for Wisconsin retail customers. In lieu of fuel clause recovery, a procedure is
in place that compares actual monthly and anticipated annual fuel costs with
those costs that were included in the latest retail electric rates. If the
comparison results in a difference outside a prescribed range, the PSCW may hold
hearings limited to fuel costs and revise rates. Any revised rates would be
effective until the next rate case. The adjustment approved is calculated on an
annual basis, but applied prospectively.
Gas rate schedules for NSP-Minnesota, NSP-Wisconsin and Black Mountain Gas
(BMG) in Arizona include a purchased gas adjustment (PGA) clause that provides
for rate adjustments for changes in the current unit cost of purchased gas
compared with the last costs included in rates. The factors in Minnesota and
Wisconsin are calculated for the current month based on the estimated purchased
gas costs for that month. In Arizona, the factor is based on actual gas costs
with a two month lag.
By Sept. 1 of each year, NSP-Minnesota is required to submit to the MPUC
an annual report of the PGA factors used to bill each customer class by month
for the previous year commencing July 1 and ending June 30. The report verifies
whether the utility is calculating the adjustments properly and implementing
them in a timely manner. In addition, the
3
MPUC reviews procurement policies, cost-minimizing efforts, rule variances,
retail transportation gas volumes, independent auditors' reports and the impact
of market forces on gas costs for the coming year. The MPUC has the authority to
disallow certain costs if it finds the utility was not prudent in its gas
procurement activities. In May 1998, the MPUC allowed full recovery of gas costs
for the year ended June 30, 1997. The MPUC's determination regarding the filing
for the year ended June 30, 1998, is pending. Approval is anticipated in
mid-1999.
In 1996, the PSCW conducted a generic hearing to consider alternative gas
cost recovery mechanisms to replace the current PGA. All major gas utilities in
Wisconsin were required to file a proposal to replace their current PGA.
NSP-Wisconsin's proposal was approved February 1999, effective March 1, 1999.
The financial impact of the new gas cost recovery mechanism will be
substantially the same as with the former PGA. Approximately 70 percent of
NSP-Wisconsin's gas revenues represent recovery of gas costs through the PGA
mechanism.
NSP-Wisconsin's gas and retail electric rate schedules for Michigan
customers include Gas Cost Recovery Factors and Power Supply Cost Recovery
Factors (PSCR), which are based on 12-month projections. After each 12-month
period, a reconciliation is submitted whereby over-collections are refunded and
any under-collections are collected from the customers.
Viking provides interstate gas transportation services only and does not
sell gas. Thus, Viking has no need for a PGA mechanism. Natural gas fuel for
Viking's compressor station operations is provided in-kind by transportation
service customers. Viking makes incidental purchases and sales of natural gas to
balance the volumes of gas in the pipeline. In 1998, FERC approved a tariff
change to reflect the costs and revenues from those incidental transactions on a
true-up basis.
RESOURCE ADJUSTMENT CLAUSES
NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent
of Minnesota revenues on conservation improvement programs (CIP). These costs
are recovered through an annual recovery mechanism for electric and gas
conservation and energy management program expenditures, including annual
program costs, reimbursement of gas margins and a portion of electric margins
lost due to conservation activity, and returns on capital used to finance
electric conservation programs. NSP-Minnesota is required to request a new cost
recovery level annually. Read further for a discussion of possible changes to
these recovery mechanisms.
REGULATORY MATTERS BY JURISDICTION
MINNESOTA PUBLIC UTILITIES COMMISSION (MPUC)
During 1998, NSP-Minnesota submitted to the MPUC its annual electric and
gas CIP and Financial Incentive Reports. In June 1998, the Minnesota Department
of Public Service (DPS) recommended the MPUC discontinue recovery of lost
margins, load management discounts and performance incentives for NSP and other
Minnesota public utilities. See Management's Discussion and Analysis under Item
7 for discussion of this issue.
In December 1998, NSP-Minnesota received a final rate order increasing gas
rates. See Management's Discussion and Analysis under item 7 for discussion of
this issue.
In December 1998, NSP-Minnesota submitted a cost separation filing with
the MPUC. See Management's Discussion and Analysis under Item 7 for discussion
of this issue.
Subject to the final MPUC decision regarding recovery of demand side
management (DSM) lost margins and bonuses, no filings requesting a general
electric or gas rate increase are anticipated in Minnesota in 1999.
NORTH DAKOTA PUBLIC SERVICE COMMISSION (NDPSC)
In July 1998, the NDPSC ordered its staff to conduct an investigation of
NSP-Minnesota's North Dakota jurisdictional electric earnings. The purpose of
the investigation is to determine if existing rates are fair and reasonable
given recent earnings results. NDPSC staff has deferred the NSP audit until
first quarter 1999.
In September 1998, NSP-Minnesota filed a proposal with the NDPSC to refund
$714,000 to residential customers and implement a $123,700 annual rate reduction
for commercial and industrial customers in its North Dakota service area. The
refund and reduction proposal stemmed from a favorable decision NSP received in
its dispute with Manitoba Hydro-Electric Board (Manitoba-Hydro) over a 500-MW
power capacity contract. The refund was accrued in 1998. In February 1999, the
NDPSC approved the proposal with reduced rates effective March 1999.
No general rate filings are anticipated in North Dakota in 1999.
SOUTH DAKOTA PUBLIC UTILITIES COMMISSION (SDPUC)
In December 1997, NSP filed a request with the SDPUC for a declaratory
order establishing NSP as a regulated intrastate gas pipeline in South Dakota.
Included in the filing is a request for approval of initial
4
large volume retail intrastate gas transportation rates. NSP has not previously
provided natural gas service in South Dakota. The filing is pending SDPUC final
action.
No general rate filings are anticipated in South Dakota in 1999.
PUBLIC SERVICE COMMISSION OF WISCONSIN (PSCW)
In September 1998, NSP-Wisconsin received a final rate order increasing
electric rates and decreasing gas rates. For more information, see Management's
Discussion and Analysis under item 7.
In June 1997, NSP-Wisconsin filed for a fuel cost surcharge to its
retail electric rates under the fuel rules provisions of the Wisconsin
Statutes. The surcharge was requested because fuel and purchased power costs
had risen beyond the amount included in NSP-Wisconsin's then-current rates.
Effective in September 1997, the PSCW authorized NSP-Wisconsin to charge a
fuel cost surcharge to all Wisconsin retail electric customers, which
produced approximately $574,000 and $1.6 million of additional electric
revenue in 1997 and 1998, respectively. The surcharge continued in effect
until the new rate order for the general rate case was issued in September
1998.
Under the PSCW biennial rate filing rule, NSP-Wisconsin anticipates filing
a general electric and gas rate case by June 1, 1999.
MICHIGAN PUBLIC SERVICE COMMISSION (MPSC)
In August 1997, the MPSC approved NSP-Wisconsin's application to reinstate
a PSCR factor for Michigan electric customers beginning in 1998. An application
for a PSCR factor must be filed annually. The PSCR factors for 1998 and 1999
were approved, resulting in additional revenue of about $250,000 in 1998 and
about $160,000 in 1999.
In January 1999, the MPSC approved a settlement agreement authorizing
NSP-Wisconsin to restructure electric rates for its Michigan customers. The
restructuring does not effect total revenues. Return on equity was set at 11.9
percent.
No general rate filings are anticipated in Michigan in 1999.
ARIZONA CORPORATION COMMISSION (ACC)
In July 1998, the ACC approved the sale of BMG assets and transfer of
BMG's Certificate of Convenience and Necessity to NSP. As part of the approval,
BMG filed an application with the ACC for a 21.6 percent decrease in gas rates.
A decision on the case is expected in late 1999.
Also as part of the approval and transfer process, BMG's Cave Creek
operations are required to file a rate application within 18 months of the
approval date. The specific timeline for the filing is not known at this time,
but the filing must be made no later than January 2000.
FEDERAL ENERGY REGULATORY COMMISSION (FERC)
In April 1996, the FERC issued two final rules, 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. See Management's Discussion and Analysis under Item 7 for discussion on
these rules.
In February and March of 1998, NSP-Minnesota and NSP-Wisconsin filed joint
wholesale electric point-to-point and network integration transmission service
(NTS) rate cases with the FERC. See Management's Discussion and Analysis under
Item 7 for further discussion of this filing.
In June 1998, the FERC issued an order in the transmission rate case
requiring NSP to interrupt service to its own native retail sales customers
proportionally with curtailment of wholesale transmission-only customers taking
service under NSP's Order No. 888 transmission tariff. When NSP's transmission
lines are constrained or about to become overloaded, the FERC order would
require NSP to reduce or curtail service to retail customers on a comparable
basis with curtailment of wholesale transactions. In August 1998, NSP filed an
appeal of the FERC orders with the U.S. Court of Appeals, Eighth Circuit. NSP
believes the FERC exceeded its legal authority because service to retail
customers is subject to state regulation, not FERC regulation. In addition, NSP
believes the FERC has issued inconsistent orders with which NSP cannot fully
comply and which places reliability of service to NSP's retail customers at
risk. NSP believes a final decision will be issued in 1999.
ELECTRIC UTILITY OPERATIONS
COMPETITION
NSP's electric sales are subject to competition in some areas from
municipally owned systems, cooperatives, other utilities and independent power
producers. Electric service also increasingly competes with other forms of
energy. The degree of competition may vary from time to time. Although NSP
cannot predict the extent to which its future business may be affected by
supply, relative cost or promotion of other electricity or energy suppliers, NSP
believes it will be in a position to compete effectively.
5
WHOLESALE COMPETITION (ENERGY MARKETING)
The Energy Policy Act of 1992 (Energy Act) is designed to promote
competition in the development of wholesale power generation in the electric
utility industry.
In compliance with FERC Orders No. 888 and 889, NSP has separated
personnel who perform the merchant function, which includes power and energy
marketing, from personnel who perform the transmission system operation
function. NSP's merchant function, Energy Marketing, performs power and energy
marketing (both sales and purchases). The sales and revenue provided by this
function is classified as sales for resale. Because of Orders No. 888 and 889,
NSP Energy Marketing must pay the same rates as other utilities for use of NSP's
transmission system.
In April 1998, NSP announced an initiative to expand its wholesale energy
marketing efforts by formally establishing an Energy Marketing division. Energy
Marketing is responsible for meeting the requirements of NSP's retail and
wholesale electric customers for low-cost energy while optimizing earnings from
NSP's generation resources. Energy Marketing is no longer competing with only
regional utilities when it buys and sells excess power to wholesale customers,
but with power marketers from all over the United States. As more participants
join the market, margins are expected to decline. Energy Marketing is developing
its wholesale power marketing capabilities to compete on a national basis.
Energy Marketing significantly increased its presence in regional markets,
including those surrounding Minneapolis, Cincinnati, Chicago and New Orleans. By
participating in these markets, Energy Marketing was able to locate low-cost
energy purchasing opportunities for NSP's wholesale and retail customers. See
Management's Discussion and Analysis under item 7 for further discussion.
Even though NSP has contracts with several municipal customers, because of
competition, NSP must remain competitive in the entire wholesale market because
many parties, including power marketers, are now able to use NSP's transmission
lines to transport electricity. Rate discounts and negotiated rates are being
offered to current and potential municipal power supply customers. In the past
several years, these customers have been evaluating a variety of energy sources
to provide their electric supply. NSP Energy Marketing reserves transmission
service on the transmission systems of many entities, in the same manner as
other wholesale market participants. The process of making a wholesale energy
sale is now much more competitive and can be contingent upon the availability of
transmission service.
RETAIL COMPETITION
Some states, such as Michigan, have begun to allow retail customers to
choose their electricity suppliers, and many other states are considering
proposals to increase competition in the supply of electricity. NSP supports
fair and equal treatment for all competitors. Of particular importance are the
recovery of utilities' investments made under traditional regulation and
resolution of Minnesota's property tax issues. NSP, an investor owned utility,
pays property taxes in Minnesota that are significantly higher than they would
be in neighboring states, and than those paid by other types of utilities within
Minnesota. NSP advocates tax reform to eliminate the severe interstate and
intrastate disparities as a prerequisite to opening access to retail customers.
Electric industry restructuring has not yet emerged as a major issue in
Minnesota. In 1998, the Minnesota Legislature directed the Legislative Electric
Energy Task Force (LEETF) to study restructuring. The LEETF solicited comments
from NSP and other interested parties on four topics: bulk power systems;
distribution reliability, safety and maintenance; energy prices and price
protection mechanisms; and universal service. Based on those comments, the LEETF
filed a report with the Legislature in January 1999, concluding that additional
study was necessary. The Legislature is not expected to act on electric
restructuring in 1999, and NSP cannot determine whether the issue will advance
in 2000.
In 1997, the PSCW revised its restructuring plan previously issued in
1996, delaying the start of competition to 2002. However, due to the summer of
1997's electrical reliability concerns in eastern Wisconsin, the PSCW turned its
focus on the development of a utility infrastructure necessary to assure
reliable electric service. In 1998, reliability legislation introduced by
Wisconsin Governor Thompson passed and Act 204, "the Reliability Act," became
law. The Reliability Act contains a number of steps necessary for industry
restructuring. At present, a definite timetable has not yet been established for
retail competition.
In 1997, the NDPSC adopted the National Association of Regulatory Utility
Commissioners' Principles to Guide the Restructuring of the Electric Industries,
which suggest that industry changes should only occur when they result in
economic efficiency and serve the broader public interest. Specific principles
address protecting network reliability, providing customers with meaningful
choice, sharing benefits and stranded costs between ratepayers and shareholders,
protecting the environment and reaffirming state commission responsibility for
determining restructuring policies. Since that time, the NDPSC has taken no
further action on restructuring.
6
Also in North Dakota, the 1997 legislature established a committee of
six legislators charged with studying the impact of competition on the
electric industry. By statute, the committee has six years to study the
impact of competition on the electric energy industry in the state. This
committee is to assess the current law governing electric distribution
service territories and present legislation, if necessary, to the 2001
legislature.
In January 1998, the MPSC reaffirmed its order to open Michigan's retail
electricity market to competition. The initial order directed large Michigan
utilities to open 2.5 percent of their electric load to competition each year
from 1997 to 2001, and that all Michigan electric customers would have access to
a competitive market in 2002. The larger Michigan utilities continue to
challenge the order. The lower courts have upheld the MPSC's authority to
implement retail competition and a final decision by the state supreme court is
expected in 1999. The smaller Michigan utilities, including NSP-Wisconsin, have
continued their settlement discussions with the MPSC to allow full retail
customer choice on January 1, 2002.
In December 1998, Koch Refining Company (Koch), one of NSP's largest
retail electric customers, announced that it had arranged for NSP to purchase
a 10 year electric supply contract from EnPower Services Inc. to serve the
refinery needs beginning in October 2000. A 1996 Minnesota statute allowed
Koch to seek electric capacity and energy from suppliers other than NSP. This
supply arrangement for Koch is not expected to have a material impact on NSP.
Koch will continue to purchase electric transmission and distribution
services from NSP.
NSP has proposed to fill future needs for new generation through
competitive bid solicitations. The use of competitive bidding to select future
generation sources allows NSP to take advantage of the developing competition in
this sector of the industry. NSP's proposal, which has been approved by the
MPUC, allows NRG and NSP's generation business unit to bid in response to
company solicitations for proposals. The PSCW also allows this process through
the granting of waivers.
NSP plans to continue to be a low-cost supplier of electricity and an
active participant in the more competitive market for electricity expected in
the future. NSP will continue to work with regulators to complete the tariff and
infrastructure that will support a competitive electric environment. NSP is
positioning itself for the competitive environment by offering: value-added
services tied to our core businesses; creative partnership solutions with
strategic customers, including communities; competitive pricing alternatives;
improved reliability and customer service; metering automation; centralization
of common services: and aggressive cost management. In addition, NSP will
compete to provide service outside its traditional service area. This process
has begun via NSP's Energy Marketing division, and its NRG and EMI subsidiaries.
INDEPENDENT TRANSMISSION COMPANY (ITC)
In April 1998, NSP announced its intention to divest its electric
transmission business to form an independent company unaffiliated with the rest
of its utility operations.
Also in April 1998, the 1997 Wisconsin Act 204 became law. Act 204
includes provisions that require a public utility to relinquish control of its
transmission facilities.
See Management's Discussion and Analysis under Item 7 for discussion of
these issues.
INDEPENDENT NUCLEAR GENERATING COMPANY
In February 1999, NSP, Wisconsin Electric Power Co. and Wisconsin Public
Service formalized a cooperative nuclear alliance by establishing a nuclear
management company. The fourth member of the alliance, Alliant Energy, is
seeking approval from the SEC to join the company at a later date. See further
discussion in Management's Discussion and Analysis under Item 7.
TECHNOLOGICAL IMPROVEMENTS
To improve customer service, increase productivity and respond to the
changing needs of both the electric and gas markets, NSP has made, or is in the
process of making, several major technological improvements.
In 1996, NSP-Minnesota implemented a new customer service system that
supports customer information and billing.
In 1996, NSP implemented a feeder management system to monitor, control
and communicate with its electric distribution system. It allows NSP to perform
engineering studies quickly and restore lost service faster. It also assists NSP
in increasing the utilization of its facilities and avoiding damaging equipment.
This system is interfaced with a new energy management system, which controls
NSP's electric transmission, distribution and generation facilities. The system
became fully operational in 1997.
In 1997, NSP began implementing a new geographic information system (GIS).
GIS is a design and automated mapping tool providing a single system for
updating maps of gas and electric facilities. Current and accurate information
will be available on-line. NSP expects to complete implementation in 1999.
Also in 1997, NSP began installing a wireless automated meter reading
system that will allow NSP to
7
remotely read customer meters in the Minneapolis - St. Paul metro area, which
will minimize estimated customer bills. More than 1 million electric and gas
meters are expected to be automated by the year 2000. As part of the project,
NSP has contracted with an affiliate of CellNet Data Systems, Inc. (CellNet),
which owns the technology. CellNet will own and operate a communication network
that can provide daily meter readings to NSP for automated electric and gas
meters.
NSP is also making system modifications to address the Year 2000 (Y2K)
issue. See Management's Discussion and Analysis under Item 7, for further
discussion of Y2K.
CAPABILITY AND DEMAND
NSP's 1998 maximum demand of 7,660 MW occurred on July 14, 1998. Resources
available at that time included 7,149 MW of company-owned capability and 1,871
MW of purchased capability, net of contracted sales. To avoid the Mid-Continent
Area Power Pool's (MAPP) penalty for reserve margin shortfalls and to be
prepared for weather uncertainty at the lowest overall cost, NSP carried a
reserve margin for 1998 of 18.1 percent. The minimum reserve margin requirement,
which is determined by the members of the MAPP, including NSP, is 15 percent.
Assuming normal weather, NSP expects its 1999 summer electric peak demand
to be 7,623 MW. NSP expects to meet its summer peak and the MAPP reserve
requirements through a combination of internal generation and purchases.
See Note 14 of Notes to Financial Statements under Item 8 for more
discussion of power agreement commitments.
NSP, in conjunction with Dairyland Power Cooperative, proposes to
construct, operate and maintain 230- and 115-kilovolt (KV) transmission lines
and substations to improve and maintain electric service to northwestern
Wisconsin and eastern Minnesota. There is a need for additional electrical
service to eastern Minnesota and a critical need to construct facilities to
prevent potential blackouts in northwestern Wisconsin. The major issue is the
location and aesthetics of crossing the St. Croix River, which is a designated
National Scenic Riverway. State agencies in Minnesota and Wisconsin are expected
to issue decisions on the proposal by mid-1999. Assuming regulatory approvals,
the companies expect the project to be in service by 2003.
NSP filed its most recent electric resource plan with the MPUC in January
1998, for the period 1998 to 2012. The plan shows how NSP intends to meet the
energy needs of its electric customers and includes an approximate schedule of
the timing of resource solicitation to meet such needs. The plan contains
conservation programs to reduce NSP's peak demand and conserve overall
electricity use, an approximate schedule of power purchase solicitations to meet
increasing demand, and programs and plans to maintain the reliable operation of
existing resources. In summary, the plan:
- - - Forecasts 1.7 percent annual growth in NSP's energy and peak demand
requirements.
- - - Outlines NSP's demand side management and conservation programs.
- - - Shows a need for 140 MW of new capacity in 2003.
- - - Shows a need for 2,400 MW of new capacity by 2012.
- - - Describes the programs for achieving the mandated renewable energy sources
of 425 MW of wind and 125 MW of biomass.
- - - Updates the MPUC on the status of spent nuclear fuel at the Prairie Island
plant and describes how it can continue to operate until the year 2007 with
the number of casks that have been authorized.
The resource plan proposes to satisfy NSP resource needs through a
combination of the following energy source options:
- - - Continued operation of existing generation facilities.
- - - Demand reduction of an additional 1,080 MW by 2012 through conservation and
load management.
- - - 425 MW of wind energy and 125 MW of biomass energy under contract by 2002.
- - - Acquisition, by competitive bidding, of competitively priced resources to
meet changing needs.
In January 1999, the MPUC voted to approve most aspects of the resource
plan. However, the MPUC voted to require NSP to acquire an additional 400 MW of
wind generation by 2012; however, this order is subject to further MPUC
consideration.
Minnesota utilities are required under a 1993 Minnesota law to use values
established by the MPUC, which assign a range of environmental costs for each
method of electricity generation that is not a part of the price of electricity,
when evaluating and selecting generation resource options. These values are
known as environmental externalities. The high end of the range of externality
values ordered by the MPUC add about 0.55 cents per kilowatt hour (KWH) to a
typical new coal plant and about 0.15 cents per KWH to a natural gas fired
plant. The carbon dioxide value comprises about 60 percent to 80 percent of
these amounts
NSP continues to implement various DSM programs designed to improve load
factor and reduce NSP's power production cost and system peak demands, thus
reducing or delaying the need for additional investment in new generation and
8
transmission facilities. NSP currently offers a broad range of DSM programs to
all customer sectors, including information programs, rebate and financing
programs and rate incentive programs. These programs are designed to respond to
customer needs, increase the value of NSP's service and help NSP's customer base
become more energy efficient and competitive. Since 1982, NSP's DSM programs
have reduced system peak demand by approximately 1,209 MW, which is equivalent
to 16 percent of its 1998 summer peak demand.
ENERGY SOURCES
During 1998, 44 percent of NSP's KWH requirements were obtained from coal
generation and 25 percent were obtained from nuclear generation. Purchased and
interchange energy provided 27 percent, including 12 percent from Manitoba
Hydro; NSP's hydro and other fuels provided the remaining 4 percent.
The following is a summary of NSP's electric power output in millions of
KWH for the past three years:
1998 1997 1996
---- ---- ----
Thermal plants 32,902 31,896 32,657
Hydro plants 696 1,015 1,194
Purchased and
interchange 12,529 10,661 9,065
------ ------ -------
Total 46,127 43,572 42,916
------ ------ -------
------ ------ -------
Many of NSP's power purchases from other utilities are coordinated through
the regional power organization MAPP. The MAPP agreement provides for members to
coordinate the installation and operation of generating plants and transmission
line facilities. The terms and conditions of the MAPP agreement and transactions
between MAPP members are subject to the jurisdiction of the FERC.
FUEL SUPPLY AND COSTS
Coal and nuclear fuel will continue to dominate NSP's regulated utility
fuel requirements for generating electricity by NSP-owned generating capacity.
The actual fuel mix for 1998 and the estimated fuel mix for 1999 and 2000 are as
follows:
Fuel Use on Btu Basis
---------------------
(Est) (Est)
1998 1999 2000
----- ----- ----
Coal 60.3% 58.8% 59.5%
Nuclear 35.0% 37.6% 37.0%
Other 4.7% 3.6% 3.5%
NSP normally maintains between 20 and 40 days of coal inventory, depending
on the plant site. NSP has long-term contracts providing for the delivery of up
to 100 percent of its 1999 coal requirements. Coal delivery may be subject to
short-term interruptions or reductions due to transportation problems, weather
and availability of equipment.
Based on existing coal contracts, NSP expects more than 97 percent of the
coal it burns in 1999 will have a sulfur content of less than one percent. NSP
has contracts with two Montana coal suppliers (Westmoreland Resources and Big
Sky Coal Company) and four Wyoming suppliers (Rochelle Coal Company, Antelope
Coal Company, Black Thunder Coal Company and Jacobs Ranch Mine) for a maximum of
27 million tons of low-sulfur coal for the next two years. These arrangements
are sufficient to meet approximately 100 percent of the requirements of existing
coal-fired plants in 1999 and 2000.
NSP will purchase approximately 20 percent of its coal requirements in a
large active spot market if prices are more favorable than the prices
contracted. NSP has options from suppliers for more than 100 million tons of
coal with a sulfur content of less than 1 percent that could be available for
future generating needs. The plants in the Minneapolis-St. Paul area are about
800 miles from the mines in Montana and 1,000 miles from the mines in Wyoming.
Coal delivered by rail provides NSP with an economical source of fuel.
Estimated coal requirements at NSP's major coal-fired generating plants
and the coal supply for such requirements are:
Maximum Amount Contract
Annual Covered by Expiration
Plant Requirements Contract in 1999 Date
- - ---------------------------------------------------------
(Tons) (Tons)
Black Dog 1,000,000 1,000,000 (1)
High Bridge 800,000 800,000 (1)
Allen S. King 2,000,000 2,000,000 (1)
Riverside 1,400,000 1,400,000 (1)
Sherco 7,700,000 7,700,000 (1)
----------- -----------
12,900,000 12,900,000(2)
Notes:
(1) Contract expiration dates vary between 1999 and 2005 for western coal. Spot
market purchases of other western coal and other fuels will provide the
remaining fuel requirements after 1999.
(2) Annual requirements are expected to range from 11.4 to 12.9 million tons.
NSP's current fuel oil inventory is adequate to meet anticipated 1999
requirements. Additional oil may be provided through spot purchases.
To operate NSP's nuclear generating plants, NSP secures contracts for
uranium concentrates, uranium conversion, uranium enrichment and fuel
fabrication. The contract strategy involves a portfolio of spot purchases and
medium and long-term contracts for uranium, conversion and enrichment.
9
Current contracts are flexible and cover 100 percent of uranium,
conversion and enrichment requirements through the year 2000. These contracts
expire at varying times between 1999 and 2005. The overlapping nature of
contract commitments will allow NSP to maintain 50 percent to 100 percent
coverage beyond 1999. NSP expects sufficient uranium, conversion and enrichment
to be available for the total fuel requirements of its nuclear generating
plants. Fuel fabrication is 100 percent committed through the year 2003 and 30
percent covered through 2010. NSP expects the unit cost of fuel to produce
electricity at these nuclear facilities will be lower than the comparable cost
of fuel to produce electricity with any other currently available fuel sources
for the sustained operation of a generation facility. The cost of nuclear fuel,
including disposal, is recovered in the customer price of the electricity sold
by NSP.
NSP's average electric fuel costs for the past three years are shown
below:
Fuel Costs * Per Million Btu
----------------------------
1996 1997 1998
---- ---- ----
Coal** $ 1.02 $ 1.05 $1.00
Nuclear .47 .47 .47
Composite All Fuels .83 .88 .85
* Fuel adjustment clauses enable NSP to adjust for fuel cost changes.
** Includes refuse-derived fuel and wood.
NUCLEAR POWER PLANTS - LICENSING, OPERATION AND WASTE DISPOSAL
NSP operates two nuclear generating plants: the Monticello plant and the
Prairie Island plant. Monticello is a single unit plant with a 1999 summer
capacity of 578 MW, while Prairie Island is a two unit plant with a 1999 summer
capacity of 1,052 MW. Monticello began operation in 1971 and is licensed to
operate until 2010. Prairie Island Units 1 and 2 began operation in 1973 and
1974 and are licensed to operate until 2013 and 2014, respectively.
In September 1998, NSP received approval from the Nuclear Regulatory
Commission for an amendment to the Monticello operating license to increase the
power level as a result of improvements in technology, equipment and plant
performance. This change increases Monticello's summer generating capacity from
545 MW to 578 MW, while avoiding the expense of building new generating units.
In its most recent ratings of NSP nuclear facilities, the NRC rated the
overall performance of both Prairie Island and Monticello as excellent. On a
scale of 1 to 3 (1 being the highest), Monticello was rated 1.25 and Prairie
Island, 1.5. These ratings of the NRC's Systematic Assessment of Licensee
Performance (SALP) place the plants in the top quartile of the 18 plants located
in the Midwest.
Prairie Island and Monticello currently hold the Institute of Nuclear
Power Operations' (INPO) top rating for plant operations and training. In
addition, INPO has awarded both of the plants the INPO Excellence Award, the
result of a rigorous peer review process that recognizes plants with the highest
levels of excellence in operational safety and reliability and no significant
weaknesses.
NSP previously operated the Pathfinder plant near Sioux Falls, South
Dakota, as a nuclear plant from 1964 until 1967, after which it was converted to
an oil and gas-fired peaking plant. The nuclear portions were placed in a safe
storage condition in 1971. Most of the plant's nuclear material, which was
contained in the reactor building and fuel handling building, was removed during
1991. A few millicuries of residual contamination remain at the operating plant
site.
Nuclear power plant operation produces gaseous, liquid and solid
radioactive wastes. The discharge and handling of such wastes are controlled by
federal regulation. For commercial nuclear power plants, high-level radioactive
waste includes used nuclear fuel. Low-level radioactive wastes are produced from
other activities at a nuclear plant. They consist principally of demineralizer
resins, paper, protective clothing, rags, tools and equipment that has become
contaminated through use in the plant.
A 1980 federal law places responsibility on each state for disposal of its
low-level radioactive waste. Low-level radioactive waste from NSP's Monticello
and Prairie Island nuclear plants is currently disposed of at the Barnwell
facility, located in South Carolina (all classes of low-level waste), and the
Clive facility, located in Utah (class A low-level waste only). Chem Nuclear is
the owner and operator of the Barnwell facility, which has been given
authorization by South Carolina to accept low-level radioactive waste from out
of state. Enrvirocare, Inc. operates the Clive facility. NSP and Barnwell
currently operate under an annual contract, while NSP uses the Envirocare
facility through various low-level waste processors. NSP has low-level storage
capacity available at Prairie Island and Monticello that would allow both plants
to continue to operate until the end of their licensed life, if low-level
disposal facilities were no longer available to NSP.
The federal government has the responsibility to dispose of, or
permanently store, domestic spent nuclear fuel and other high-level radioactive
wastes. The Nuclear Waste Policy Act of 1982 requires the Department of Energy
(DOE) to implement a program for nuclear waste management, including the siting,
licensing, construction and operation of a repository for domestically produced
spent nuclear fuel from civilian nuclear power reactors and other high-level
radioactive wastes at a permanent storage or disposal facility by
10
1998. None of NSP's spent nuclear fuel has been accepted by the DOE for
disposal. See Item 3 - Legal Proceedings and Note 13 to the Financial Statements
under Item 8 for further discussion of this matter.
NSP, with regulatory and legislative approval, has been providing on-site
storage at its Monticello and Prairie Island nuclear plants. In 1979, NSP began
expanding the used nuclear fuel storage facilities at its Monticello plant by
replacement of the racks in the storage pool. In 1987, NSP completed the
shipment of 1,058 used fuel assemblies from the Monticello plant to a General
Electric storage facility in Morris, Ill. As a result, the Monticello plant does
not expect to run out of pool storage capacity prior to the end of its current
operating license in 2010.
The Prairie Island spent fuel pool has undergone two storage rack
replacements. The on-site storage pool for spent nuclear fuel at Prairie Island
was nearly filled prior to a scheduled refueling in June 1995, and adequate
space for a subsequent refueling was no longer available. In anticipation of
this, NSP, in 1989, proposed construction of a temporary on-site dry cask
storage facility for spent nuclear fuel at Prairie Island. In May 1994, the
Governor of Minnesota signed into law a bill authorizing NSP to install 17 spent
fuel casks at Prairie Island. NSP has determined 17 casks will allow facility
operation until 2007. NSP executed an agreement with the Governor concerning the
renewable energy and alternative siting commitments contained in the law. The
law authorized immediate installation of the first increment of five casks. The
second increment of four casks was authorized in October 1996 by the MEQB.
In 1998, NSP took steps to fulfill its wind and biomass resource
commitments. Other commitments resulting from the legislation include a discount
for low-income electric customers, additional conservation improvement
expenditures and various study and reporting requirements to a legislative
electric energy task force. The MEQB terminated an alternative siting process,
which was one of the legislative requirements. NSP has implemented programs to
meet the legislative commitments.
The final increment of eight casks is available unless prior to June 1,
1999, the Legislature specifically revokes the authorization for the final eight
casks. As of January 1999, seven storage casks are loaded and stored on the
Prairie Island nuclear generating plant site.
To address the issue of temporary storage of spent nuclear fuel until the
DOE provides for permanent storage or disposal, NSP is leading a consortium of
private parties to establish a private facility for interim storage of spent
nuclear fuel. In June 1997, the Private Fuel Storage LLC (PFS) filed a license
application with the NRC for a national temporary storage site for spent nuclear
fuel. The PFS will undertake the development, licensing, construction and
operation of a storage facility on the Skull Valley Indian Reservation in Utah.
The NRC review process could take up to three years and will consist of formal
evidentiary hearings and opportunity for public input. Storage cask
certification efforts are continuing with the two vendors on track to meet the
project goals. The interim used fuel storage facility could be operational and
able to accept the first shipment of spent nuclear fuel by 2003. However, due to
uncertainty regarding pending regulatory and governmental approvals, it is
possible that this interim storage may be delayed or not available at all.
The NRC has issued a number of regulations, bulletins and orders that
require analyses, modification and additional equipment at commercial nuclear
power plants. The NRC is engaged in various ongoing studies and rulemaking
activities that may impose additional requirements upon commercial nuclear power
plants. Management is unable to predict any new requirements or their impact on
NSP's facilities and operations.
For further discussion of nuclear issues, see Note 13 and Note 14 to the
Financial Statements under Item 8.
11
ELECTRIC OPERATING STATISTICS
The following table summarizes the revenues, sales and customers from
NSP's electric transmission and distribution business:
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
REVENUES (THOUSANDS)
Residential $ 774 803 $ 739 684 $ 727 145 $ 735 743 $ 683 783
Small commercial and industrial 389 744 379 848 376 797 362 521 351 287
Medium commercial and industrial 466 352 433 526 401 137 399 259 *
Large commercial and industrial 483 595 468 404 450 811 448 226 824 195
Streetlighting and other 31 054 30 826 30 033 29 162 28 936
---------- ---------- ---------- ---------- ----------
Total retail 2 145 548 2 052 288 1 985 923 1 974 911 1 888 201
Sales for resale 149 707 107 464 98 961 133 961 146 239
Transmission and other 67 096 58 798 42 529 33 898 32 204
---------- ---------- ---------- ---------- ----------
Total $2 362 351 $2 218 550 $2 127 413 $2 142 770 $2 066 644
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
SALES (MILLIONS OF KILOWATT-HOURS)
Residential 10 127 9 791 9 847 9 956 9 303
Small commercial and industrial 5 999 5 907 6 091 5 763 5 585
Medium commercial and industrial 8 801 8 263 7 470 7 511 *
Large commercial and industrial 11 277 11 059 11 089 10 941 17 874
Streetlighting and other 327 335 336 329 334
---------- ---------- ---------- ---------- ----------
Total retail 36 531 35 355 34 833 34 500 33 096
Sales for resale 6 304 4 658 4 929 6 500 6 733
---------- ---------- ---------- ---------- ----------
Total 42 835 40 013 39 762 41 000 39 829
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
CUSTOMER ACCOUNTS (AT DEC. 31) **
Residential 1 287 080 1 273 161 1 252 476 1 238 576 1 222 628
Small commercial and industrial 155 536 150 103 149 134 144 774 142 858
Medium commercial and industrial 9 510 9 142 7 962 7 906 *
Large commercial and industrial 727 695 669 652 8 172
Streetlighting and other 6 243 6 276 5 030 4 883 4 836
---------- ---------- ---------- ---------- ----------
Total retail 1 459 096 1 439 377 1 415 271 1 396 791 1 378 494
Sales for resale 78 59 54 67 70
---------- ---------- ---------- ---------- ----------
Total 1 459 174 1 439 436 1 415 325 1 396 858 1 378 564
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
* Beginning in 1995, the commercial and industrial customer class was segmented
into small (less than 100 KW in demand per year), medium (100 KW up to 1,000
KW) and large (1,000 KW or more). The medium group, which is an estimate, was
reported as large prior to 1995.
** Customers' accounts for 1996, 1997 and 1998 may not be fully comparable to
prior years due to differences in meter accumulation in a new billing system
implemented in 1996.
12
GAS UTILITY OPERATIONS
COMPETITION/REGULATION
NSP provides retail gas service in the eastern portions of the Twin Cities
metropolitan area, portions of eastern North Dakota and northwestern Minnesota,
and other regional centers in Minnesota (Faribault, St. Cloud and Winona), along
with the cities of Page, Carefree, North Phoenix, North Scottsdale and Cave
Creek in Arizona and the cities of Eau Claire, LaCrosse, Ashland and New
Richmond in Wisconsin.
During 1992 and 1993, the FERC issued a series of orders (together called
Order No. 636) that addressed interstate natural gas pipeline restructuring.
This restructuring required all interstate pipelines to unbundle each of the
services they provide: sales, transportation, storage and ancillary services.
The implementation of Order No. 636 applies additional competitive pressure on
all local distribution companies, (LDCs) including NSP, to keep gas supply and
transmission prices for their large customers competitive. Customers have
expanded ability to buy gas directly from suppliers and arrange pipeline and LDC
transportation service. NSP has provided unbundled transportation service since
1987. Transportation service does not currently have an adverse effect on
earnings because NSP's sales and transportation rates have been designed to make
NSP economically indifferent to sales or transportation of gas. However, some
transportation customers may have greater opportunities or incentives to
physically bypass the LDC distribution system. NSP has arranged its gas supply
and transportation portfolio in the event it may be required to terminate its
retail merchant sales function.
Order No. 636 allows interstate pipelines to negotiate with customers to
recover up to 100 percent of prudently incurred transition costs attributable to
Order 636 restructuring.
NSP's primary gas supplier, Northern Natural Gas Company (Northern), was
allowed to recover certain transition costs as a result of Order No. 636
restructuring. NSP paid approximately $13 million of Northern's transition
costs, spread over a period of approximately five years, which ended Oct. 31,
1998. NSP's regulatory commissions have approved recovery of restructuring
charges in retail gas rates. NSP has no significant Order No. 636 transition
cost responsibilities to its other pipeline suppliers.
In response to the additional competitive pressures as a result of Order
No. 636, NSP has aggressively pursued alternative pricing strategies and service
enhancements to provide additional value to customers.
In 1996, NSP-Minnesota filed a negotiated transportation service tariff
with the MPUC. The tariff, approved in March 1997, provides additional
flexibility in discounting gas rates for customers considering a bypass of NSP's
system.
In 1997, the MPUC approved NSP-Minnesota's proposal for a predictable
commodity price service (PCPS) rider, which would allow firm gas commercial and
industrial customers a choice to purchase firm fixed price gas supplies rather
than gas supplies whose price changes monthly through the PGA clause. The PCPS
will be offered as a two-year pilot program to determine the extent of interest
in the Minnesota service territory. The program began in January 1998.
BUSINESS GROWTH
NSP's gas utility customer base grew by approximately 22,000 customers
during 1998. In addition to exploring new growth opportunities, NSP is also
focusing on conversion of potential customers who are located near NSP's gas
mains, but are not connected to the service.
In July 1998, NSP-Minnesota completed its merger with BMG, located in Cave
Creek, Arizona. BMG is a natural gas and propane distribution company with
natural gas operations in Cave Creek, Carefree, North Phoenix and North
Scottsdale, and propane operations in Page, Ariz. BMG currently serves about
6,500 customers and had 1998 annual revenue of approximately $6 million. Also in
July 1998, NSP-Wisconsin completed its merger with Natural Gas Inc. (NGI) of New
Richmond, Wis. NGI, a privately owned natural gas utility, serves 1,900 natural
gas customers and had annual revenue of approximately $2.3 million in 1998. Both
of these mergers were structured as tax-free reorganizations for income tax
purposes and were accounted for using the pooling of interests method. Prior
period financial statements have not been restated due to immateriality.
In January 1999, NSP filed for MPUC, ACC and NDPSC approval to transfer
the BMG operations into a wholly owned subsidiary of NSP. NSP believes this
structure will provide more efficient management and regulation, and will comply
with the Public Utility Holding Company Act (PUHCA).
NSP-Minnesota's gas operation maintains a nonutility service that sells
service contracts on a variety of home appliances. Working in partnership with
local independent service contractors, NSP Advantage Service offers 24-hour
appliance repair service. This service is offered to individuals within
NSP-Minnesota's service territory.
13
STANDARDS
In July 1996, FERC adopted new rules that adopt by reference 140 standard
natural gas business practices approved by the Gas Industry Standards Board
(GISB). GISB is the independent standards organization of the natural gas
industry. The new rules and standards apply to interstate gas pipelines such as
Viking, and are intended to simplify transportation of natural gas across the
interstate gas pipeline grid. However, NSP's retail natural gas operations must
change their information systems and operations to comply with the pipeline
changes. The new FERC rules went into effect in the second quarter of 1997. GISB
and FERC continue to revise the standards periodically, requiring incremental
expenditures by Viking and NSP.
In January 1997, the PSCW adopted standards of conduct for natural gas
LDCs serving Wisconsin consumers. The standards are similar to, but much more
extensive than, the standards of conduct imposed by FERC. The PSCW standards
require separation of the LDC delivery function from any affiliate that engages
in gas functions and impose extensive reporting and other administrative
requirements. NSP-Wisconsin filed its compliance plan in February 1997.
In 1998, the MPUC voted to establish a work group to develop a work plan
for unbundling retail gas services. The MPUC ordered the work group to submit
its report by June 1999.
The SDPUC and NDPSC also initiated dockets in 1996 to examine whether to
adopt standards of conduct for natural gas LDCs serving the two states. The
rulemaking could create precedent for future rules affecting NSP's retail
electric operations.
CAPABILITY AND DEMAND
NSP categorizes its gas supply requirements as firm (primarily for space
heating customers) or interruptible (commercial/industrial customers with an
alternate energy supply). NSP's maximum daily sendout (firm and interruptible)
of 710,831 mmBtu for 1998 occurred on Jan. 10, 1998.
NSP purchases gas from independent suppliers. The gas is delivered under
gas transportation agreements with interstate pipelines. These agreements
provide for firm deliverable pipeline capacity of approximately 596,400
mmBtu/day. In addition, NSP has contracted with providers of underground natural
gas storage services. Using storage reduces the need for firm pipeline capacity.
These storage agreements provide NSP storage for approximately 19 percent of
annual and 30 percent of peak daily firm requirements. NSP also owns and
operates two LNG plants with a storage capacity of 2.53 Bcf equivalent and four
propane-air plants with a storage capacity of 1.42 Bcf equivalent to help meet
the peak requirements of its firm residential, commercial and industrial
customers. These peak-shaving facilities have production capacity equivalent to
245,400 Mcf of natural gas per day, or approximately 33 percent of peak day firm
requirements. NSP's LNG and propane-air plants provide a cost-effective
alternative to annual fixed pipeline transportation charges to meet the peaks
caused by firm space heating demand on extremely cold winter days and can be
used to minimize daily imbalance fees on interstate pipelines.
Gas utilities in Minnesota are required to file for a change in gas supply
contract levels to meet peak demand, to redistribute demand costs among classes,
or exchange one form of demand for another. NSP-Minnesota filed in August 1998
to increase its demand entitlements due to projected increases in firm customer
count, to decrease the Minnesota jurisdictional allocation of total demand
entitlements, effective Nov. 1, 1998, and to recover the demand entitlement
costs associated with the increase in transportation and storage levels in its
monthly PGAs. In March 1999, the MPUC approved NSP's 1998-99 entitlement levels.
GAS SUPPLY AND COSTS
NSP's natural gas supply commitments have been unbundled from its gas
transportation and storage commitments. NSP's gas utility actively seeks gas
supply, transportation and storage alternatives to yield a diversified portfolio
that provides increased flexibility, decreased interruption and financial risk,
and economical rates. This diversification involves numerous domestic and
Canadian supply sources, with varied contract lengths. NSP has firm gas
transportation contracts with the following pipelines. Approximately 82 percent
of NSP's retail gas customers are served from the Northern pipeline system. The
contracts expire in various years from 1999 through 2013:
Northern Northern Border Pipeline Company
Williston Basin ANR Pipeline Company
Viking TransCanada Gas Pipeline Ltd.
Great Lakes El Paso Natural Gas Pipeline
The agreements with Great Lakes, Northern Border, ANR and TransCanada
provide for firm transportation service upstream of Northern and Viking,
allowing competition among suppliers at supply pooling points and minimizing
commodity gas costs.
In addition to these fixed transportation charge obligations, NSP has
entered into firm gas supply agreements that provide for the payment of monthly
or annual reservation charges irrespective of the volume of gas purchased. The
total annual obligation is approximately $16.1 million. These agreements are
beneficial because they allow NSP to purchase the gas commodity at a high load
factor at
14
rates below the prevailing market price reducing the total cost per mmBtu.
NSP has certain gas supply and transportation agreements that include
obligations for the purchase and/or delivery of specified volumes of gas or to
make payments in lieu of. At Dec. 31, 1998, NSP was committed to approximately
$266.2 million in such obligations under these contracts, which range from the
years 1999-2013. NSP has negotiated market out clauses in its new supply
agreements, which reduce NSP's purchase obligations if NSP no longer provides
merchant gas service.
NSP purchases firm gas supply from approximately 30 domestic and Canadian
suppliers under contracts with durations of one year to 10 years. NSP purchases
no more than 20 percent of its total daily supply from any single supplier. This
diversity of suppliers and contract lengths allows NSP to maintain competition
from suppliers and minimize supply costs. NSP's objective is to be able to
terminate its retail merchant sales function, if necessary to remain competitive
in the marketplace or if mandated by regulatory agencies, with minimal cost to
NSP.
The following table summarizes the average cost per mmBtu of gas purchased
for resale by NSP's regulated retail gas distribution business, which excludes
Viking and EMI:
NSP-Minnesota NSP-Wisconsin
------------- -------------
1994 $2.59 $3.13
1995 $2.29 $2.78
1996 $2.88 $2.93
1997 $3.33 $3.22
1998 $2.87 $2.96
The cost of gas supply, transportation service and storage service is
recovered through the PGA cost recovery adjustment mechanism. The average cost
of gas and propane held in inventory for the latest test year is allowed in rate
base by the MPUC and the PSCW.
Purchases of gas supply or services by NSP-Minnesota from NSP-Wisconsin,
its Viking pipeline affiliate and its EMI gas marketing affiliate are subject to
approval by the MPUC. The MPUC has approved all NSP-Minnesota's transportation
contracts with Viking.
VIKING GAS TRANSMISSION COMPANY
In June 1993, NSP acquired 100 percent of the stock of Viking from Tenneco
Gas. Viking owns and operates a 500-mile interstate natural gas pipeline serving
portions of Minnesota, Wisconsin and North Dakota, with a capacity of
approximately 480 million cubic feet per day. The Viking pipeline currently
serves 10 percent of NSP's gas distribution system needs. Viking operates
exclusively as a transporter of natural gas for third-party shippers under
authority granted by the FERC. In addition to revenue derived from FERC-approved
rates, Viking is receiving intercompany revenues from NSP-Minnesota for its
jurisdictional allocations of the acquisition adjustment paid by NSP (in excess
of Tenneco's pipeline carrying value) to acquire Viking. NSP-Minnesota is not
currently recovering this cost in retail gas rates in Minnesota, but is
recovering this cost in North Dakota. NSP-Wisconsin recovered a portion of the
cost in its retail gas rates through 1998.
As a natural gas pipeline, Viking is subject to FERC standards of conduct
in its transactions with NSP-Minnesota, NSP-Wisconsin and EMI. Viking must
transact with EMI and NSP on a non-discriminatory basis and certain restrictions
are imposed on the retail gas operations of NSP-Minnesota and NSP-Wisconsin.
In 1997, Viking, in partnership with TransCanada PipeLines, Ltd.
(TransCanada) and NICOR, Inc. (NICOR), formed Viking Voyageur Gas Transmission
Company LLC (Voyageur), with 40 percent owned by Viking, 40 percent by
TransCanada and 20 percent by NICOR. The purpose of the Voyageur project was to
install a new 773-mile pipeline parallel to the existing Viking pipeline and
extending into the Chicago area. The proposed pipeline was intended to transport
natural gas to markets in Minnesota, Wisconsin, North Dakota and Illinois. The
anticipated project cost was approximately $1.2 billion.
The Voyageur project did not receive the necessary shipper support to make
the project viable. In April 1998, Viking withdrew from the proposed Voyageur
pipeline project and wrote off $1.4 million in costs related to the Voyageur
project. Viking has eliminated all liabilities to the partnership from its
balance sheet. Viking continues to negotiate the final termination of its
involvement in the partnership and cannot determine if any additional costs will
be incurred related to the Voyageur project.
In June 1998, Viking filed a rate case with the FERC. See Management's
Discussion and Analysis under Item 7 for discussion.
In September 1998, Viking filed an application with the FERC to expand its
transmission system in northwestern and central Minnesota by installing 45 miles
of 24-inch pipeline during 1999. The proposed $21 million expansion is a result
of customers' requests and would create an additional 28,200 dekatherms per day
of winter capacity. If approved, construction could begin in the summer of 1999,
with the pipeline placed in service during the fourth quarter of 1999.
In March 1999, Viking, WICOR and CMS Energy Corp. announced plans to build
an interstate natural gas pipeline to serve the growing needs of
15
northern Illinois and southeastern Wisconsin markets. The three energy companies
will each hold an equal share of the proposed pipeline. The project, called the
Guardian Pipeline, will transport natural gas from a hub near Joliet, Ill. to
the Watertown, Wis., area. The 147-mile pipeline is projected to initially carry
about 750 million cubic feet of natural gas per day, and depending on market
conditions, can be expanded to 1.1 billion cubic feet per day. The total cost of
the project is estimated to be $230 million.
- - --------------------------------------------------------------------------------
GAS OPERATING STATISTICS
The following table summarizes the revenue, sales and customers from NSP's
regulated gas businesses:
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
REVENUE (THOUSANDS)
Residential $226 936 $253 065 $267 130 $215 543 $207 506
Commercial and industrial
Firm 124 099 144 539 146 145 119 863 120 912
Interruptible 61 050 79 135 63 585 48 646 49 384
Other 144 34 153 1 686 3 688
-------- -------- -------- -------- --------
Total Retail 412 199 476 773 477 013 385 738 381 490
Interstate transmission (Viking) 23 375 19 809 17 553 16 328 16 307
Agency, transportation and
off-system sales 23 792 21 287 34 662 26 122 24 338
Elimination of Viking sales to NSP (2 543) (2 673) (2 435) (2 374) (2 232)
-------- -------- -------- -------- --------
Total $456 823 $515 196 $526 793 $425 814 $419 903
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
SALES (THOUSANDS OF MMBTU)
Residential 37 522 42 428 48 149 42 294 38 750
Commercial and industrial
Firm 24 410 28 880 31 748 28 275 27 342
Interruptible 23 201 25 898 23 210 22 408 19 373
Other 48 33 394 772 212
-------- -------- -------- -------- --------
Total retail 85 181 97 239 103 501 93 749 85 677
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
OTHER GAS DELIVERED (THOUSANDS OF MMBTU)
Interstate transmission (Viking) 168 187 166 588 161 972 152 952 147 919
Agency, transportation and
off-system sales 15 609 11 701 17 535 19 679 13 466
Elimination of Viking sales to NSP (14 563) (17 145) (19 311) (20 440) (16 845)
-------- -------- -------- -------- --------
Total other gas delivered 169 233 161 144 160 196 152 191 144 540
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
CUSTOMER ACCOUNTS (AT DEC. 31)*
Residential 430 240 410 773 398 723 386 007 370 734
Commercial and industrial 44 523 41 905 40 244 38 575 37 140
-------- -------- -------- -------- --------
Total retail 474 763 452 678 438 967 424 582 407 874
Other gas delivered 58 36 30 62 18
-------- -------- -------- -------- --------
Total 474 821 452 714 438 997 424 644 407 892
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
* Customer accounts for 1996, 1997 and 1998 may not be fully comparable to
prior years due to differences in meter accumulation in a new billing system
implemented in 1996.
- - --------------------------------------------------------------------------------
16
NONREGULATED SUBSIDIARIES
NRG ENERGY, INC.
NRG develops, builds, acquires, owns and operates several nonregulated,
energy-related businesses. It was incorporated in 1992 and assumed ownership of
the assets of NRG Group, Inc. In 1997, NRG filed an S-1 registration statement
with the SEC. The following summary describes NRG's most significant projects.
Additional information is included in Item 1 of NRG's 1998 Form 10-K, which is
incorporated by reference via Exhibit 99.02.
NRG intends to continue to grow through a combination of acquisitions and
development of power generation, thermal energy production, transmission
facilities and related assets in the United States and abroad. In the United
States, NRG's near-term focus will be primarily on the acquisition of existing
power generation capacity and thermal energy production and transmission
facilities, particularly in situations in which its expertise can be applied to
improve the operating and financial performance of the facilities. In the
international market, NRG will continue to pursue development and acquisition
opportunities in those countries in which it believes the legal, political and
economic environment is conducive to foreign investment.
NRG conducts business domestically and internationally through various
subsidiaries, including: NRG International, Inc.; NEO Corporation; NRG Energy
Center, Inc; NRG Operating Services, Inc.; and other businesses and affiliates.
- - --------------------------------------------------------------------------------
OPERATING BUSINESSES - EQUITY INVESTMENTS
The majority of NRG's energy business holdings are in the form of
less-than-majority investments in jointly owned power projects. The following
table summarizes NRG's significant equity investments operating at Dec. 31,
1998:
Total NRG MW-
Generation Projects Operating Location MW Ownership Equity Operator
- - ----------------------------------------------------------------------------------------------------------------------
Gladstone Power Station Australia 1680 37.50% 630 NRG
Loy Yang Australia 2000 25.37% 507 NRG/CMS Generation
Pacific Generation Company USA/Canada 1093 3.70%-100.00% 174 Various/AES
Schkopau Power Station (1) Germany 960 20.95% 200 Preussen Elektra Kraftwerk A.G.
Cogeneration of America (2) New Jersey, USA 576 45.21% 213 NRG
COBEE Bolivia 188 48.30% 91 COBEE
MIBRAG mbH Germany 233 33.33% 78 MIBRAG
Energy Development Limited Australia 262 33.97% 89 Energy Development Limited
Scudder Latin American Power
Projects (Scudder) (3) Latin America 748 25.00% 45 Stewart & Stevenson/Wartsila
Long Beach Generating California, USA 530 50.00% 265 Southern California Edison
El Segundo Generating California, USA 1020 50.00% 510 Southern California Edison
(1) Through a lease agreement, NRG has ownership of 200 MW.
(2) Cogeneration of America owns various percentages of projects (33.33%-100%),
making NRG's share of ownership 213 MW.
(3) Scudder owns various percentages of projects (13.1%-35.12%), making NRG's
share of ownership 45 MW.
- - --------------------------------------------------------------------------------
OPERATING BUSINESSES - WHOLLY OWNED
NRG participates in several energy businesses that are managed as a
thermal business group. The Minneapolis Energy Center (MEC) currently provides
91 customers with 1.6 billion pounds of steam per year and 37 customers with
43.5 million ton hours of chilled water per year. NRG acquired MEC in 1993 for
approximately $110 million. The MEC plants have a combined steam capacity of
1,323 mmBtus per hour and cooling capacity of 35,550 tons per hour.
In addition, NRG owns and operates three steam lines in Minnesota that
provide steam from NSP's power plants to the Rock-Tenn Company, the Andersen
Corporation and the Minnesota Correctional Facility. In 1997, NRG purchased San
Diego Power and Cooling (SDPC), serving 13 major customers. SDPC cooling
capacity is 5,250 tons per hour.
NRG operates two refuse-derived fuel (RDF) processing plants and an ash
disposal site in Minnesota. The ownership of one plant was transferred by NSP to
NRG at the end of 1993. NRG manages the operation of the other RDF plant, of
which NSP owns 85 percent, and the ash disposal site. NSP pays NRG a fee to
manage its RDF facility under an operation and maintenance agreement approved by
the MPUC. The RDF plants can each process more than 1,500 tons of municipal
solid waste per day, which is
17
burned at two NSP power plants and at a power plant owned by United Power
Association.
NRG also owns 204 MW of thermal energy production through several
additional wholly owned subsidiaries operating in Minnesota and North Dakota.
NEO is a wholly owned project subsidiary of NRG that was formed to develop
small power generation facilities, ranging in size from 1 to 50 MW, in the
United States. NEO is currently focusing on the development and acquisition of
landfill gas projects and the acquisition of hydroelectric projects. NEO expects
the total capacity of its portfolio to reach 100 MW in 1999. An important factor
in the after-tax return of the landfill gas projects is the eligibility of these
projects for Section 29 tax credits. The Section 29 tax credit is available only
to projects that produce qualified fuels. Landfill gas is a qualified fuel for
purposes of the Section 29 credit. To qualify for the credit, the facility for
producing gas must have been placed in service no later than June 30, 1998.
NEW BUSINESS DEVELOPMENT
NRG is pursuing several energy-related investment opportunities, including
those discussed below, and continues to evaluate other opportunities as they
arise. Potential capital requirements for these opportunities are discussed in
the Management's Discussion and Analysis under Item 7.
In October 1998, NRG agreed to purchase the Somerset power station for
approximately $55 million from Eastern Utilities Association. The Somerset
station, located in Somerset, Mass., includes two coal-fired generating
facilities with a total capacity of 181 MW and two aeroderivative combustion
turbine peaking units with a total capacity of 48 MW. A total of 69 MW of
capacity is on deactivated reserve. NRG will hold a 100 percent interest in the
project and will own, operate and maintain the units. The project's financial
close is expected to occur in the first quarter of 1999, but is contingent on
regulatory approval and consents from a number of government and private
parties.
In December 1998, NRG and Dynegy reached agreement to purchase 1,218 MW of
power generation facilities (located near Carlsbad and San Diego, Calif.) for
$356 million from San Diego Gas & Electric Company. NRG and Dynegy will each own
a 50 percent interest in the assets. The transaction is scheduled to close
during the second quarter of 1999, pending regulatory approval.
In December 1998, NRG reached agreement to purchase two coal-fired plants,
located near Buffalo, New York, with a combined summer capacity of 1,360 MW,
from Niagara Mohawk Power Corp. for $355 million. The acquisition is expected to
close in the second quarter of 1999, pending regulatory approvals.
In January 1999, NRG reached agreement to purchase the Arthur Kill
generating station and the Astoria gas turbine site for $505 million from
Consolidated Edison Company. These facilities, which are located in New York,
have a combined summer capacity rating of 1,456 MW. The acquisition is
expected in the second quarter of 1999, pending regulatory approvals.
NRG, together with two other parties and the Chapter 11 trustees, filed a
plan with the United States Bankruptcy Court for the Middle District of
Louisiana to acquire 1,706 MW of fossil generating assets from Cajun Electric
Power Cooperative of Baton Rouge, La., (Cajun) for approximately $1.2 billion.
The NRG consortium has the support of the Chapter 11 trustee and Cajun's secured
creditors. In September 1998, Enron Capital & Trade Corp. (Enron) withdrew from
the proceedings. Enron's withdrawal left the bankruptcy court with two competing
plans offered by Louisiana Generating LLC and Southwestern Electric Power Co. In
February 1999, the judge denied both remaining plans under consideration. NRG,
its partners and the Trustee, are contemplating submitting a revised plan. Under
any revised plan, NRG will likely hold a 50 percent equity interest in Louisiana
Generating, LLC.
In December 1996, NRG reached agreement with Indeck Energy Services to
purchase a 50 percent equity interest in the Enfield Energy Centre Ltd. (EECL),
a 350-MW natural gas power project located in England. The power station is
planned to begin commercial operations in 1999 and would be jointly developed by
NRG and Indeck. The power station will sell its output to the UK grid. In 1998,
NRG sold one-half of its interest in EECL. NRG continues to hold a 25 percent
interest in EECL.
In December 1996, representatives of the Estonian government, the
state-owned Eesti Energia (EE), and NRG signed a development cooperation
agreement (DCA). The DCA defines the terms under which the parties are to
establish a plan to develop and refurbish the Balti and Eesti power plants. NRG
has stated its willingness to invest up to $67 million of equity in this project
and to assist in obtaining non-recourse debt to fund the required capital
improvements to the Balti and Eesti power plants. A commission has been
established to negotiate all terms and agreements between NRG, EE and the
Estonian Government relating to the purchase of the Balti and Eesti Power
Plants. The negotiation process is expected to be complete by late 1999.
In March 1999, NRG filed a shelf registration with the SEC for up to $500
million in debt securities. The net proceeds will be used for general corporate
purposes, which may include financing the development and construction of new
facilities, working capital, debt reduction and pending or potential
acquisitions.
18
PROJECTS GAINS AND WRITE-DOWNS
In December 1998, NRG sold one-half of its 50 percent interest in EECL to
an affiliate of El Paso International for approximately $26.2 million, resulting
in an after-tax gain to NRG of approximately $16.6 million. This gain increased
1998 fourth quarter earnings by approximately 11 cents per share. NRG continues
to hold a 25 percent interest in EECL.
In 1996, NRG and two other partners formed a joint venture to develop a
400-megawatt coal-fired power generation facility in West Java, Indonesia.
During 1998, NRG recorded a pretax charge of approximately $22 million ($15.2
million after tax) to write down its investment in the West Java project as a
result of the political and economic instability in Indonesia. This write-down
reduced 1998 earnings, primarily in the third quarter, by 10 cents per share.
In 1994, NRG purchased a 50 percent ownership interest in Sunnyside
Cogeneration Associates, a joint venture, which owned a 58-MW waste coal plant
in Utah. In 1997, NRG and its partner's effort to restructure the debt of the
Sunnyside cogeneration project was not successful. NRG's net capitalized
investment in the Sunnyside project was written down by $9 million (4 cents per
share) in the fourth quarter of 1997. During 1998, NRG wrote-off its remaining
$1.9 million investment in the Sunnyside project.
CONTINGENT REVENUES
NRG and Dynegy each own a 50 percent interest in the Long Beach and El
Segundo generating stations (California Projects). During 1998, the first
year of deregulation in the California power industry, the California
Projects accrued certain receivables related to contingent revenues. These
revenues have been deferred, pending resolution of the contingency. Such
amounts relate to items that are subject to contract interpretations,
compliance with processes and filed market disputes. The California Projects
are actively pursuing resolution and/or collection of these amounts, which
totaled approximately $60 million (NRG's share approximates $30 million) as
of Dec. 31, 1998. Upon any final resolutions and/or collection of these
amounts, such deferred revenues will be recognized in NRG's equity income.
ENERGY MASTERS INTERNATIONAL, INC.
EMI began operations in October 1993 through the acquisition from
bankruptcy of selected assets of Centran Corporation, a natural gas marketing
company. EMI primarily offers retrofitting and upgrading facilities for greater
energy efficiency on a national basis. EMI is one of only 18 energy services
companies accredited by the National Association of Energy Services Companies to
provide comprehensive energy retrofits.
In 1995, EMI and Atlantic Energy Enterprises (AEE) established Enerval
LLC. EMI and AEE each owned 50 percent of the joint venture, which provided
natural gas services, primarily in the northeast United States. In June 1998,
EMI sold its interest in Enerval. EMI's investment in Enerval was written down
to an estimate of its net realizable value in 1997.
In 1995, EMI acquired an 80 percent ownership interest in Kansas
City-based Energy Masters Corporation (EMC). In 1997, EMI acquired the remaining
20 percent of EMC. EMC specializes in energy efficiency improvement services for
commercial, industrial and institutional customers.
In 1997, EMI acquired 100 percent of Energy Solutions International Inc.
(ESI). ESI, based in St. Paul, Minn., is a full-service energy management firm.
During 1998, EMI was selected by 20 federal facilities across the United
States to improve energy efficiency and reduce operating costs. These selections
are a result of EMI being awarded a contract, in late 1997, by the Army Corps of
Engineers to pursue up to $150 million of energy efficiency improvements in
government facilities in 46 states. Such government initiatives are due to a
federal mandate to decrease energy consumption by 30 percent by the year 2005.
In addition, during 1998, EMI initiated energy efficiency performance contacts
at 11 schools in Chicago.
In February 1999, EMI transferred its gas supply and marketing function to
NSP's Energy Marketing division.
ELOIGNE COMPANY
In 1993, NSP established Eloigne to identify and develop affordable
housing investment opportunities. Eloigne's principal business is the
acquisition of rental housing projects that qualify for low-income housing tax
credits under current federal tax law. As of Dec. 31, 1998, approximately $63
million had been invested in Eloigne projects, including approximately $17
million in wholly owned properties (at net book value) and approximately $46
million in equity interests in jointly-owned projects. These investments and
related working capital requirements have been financed with approximately $46
million of long-term debt (including current maturities) and the remainder with
equity capital.
Completed Eloigne projects as of Dec. 31, 1998, are expected to generate
tax credits of $80 million over the 10-year period 1999-2008. Tax credits
recognized in 1998 as a result of these investments were approximately $8.7
million.
19
SEREN INNOVATIONS, INC.
Seren was formed in November 1996 to pursue communications and data
services business.
Seren is constructing a combination cable television, telephone and
high-speed Internet access system in the St. Cloud, Minn., area. The first
customer subscribed in December 1998. Seren's expected investment in this
network is $29 million.
Seren is pursuing additional network development opportunities in other
markets.
ULTRA POWER TECHNOLOGIES, INC.
Ultra Power, formed in late 1997, markets a proactive, non-destructive,
power cable testing technology, which NSP helped research and develop. The
predictive tool was developed by Dr. Matt Mashikian of Instrument Manufacturing
Co. Ultra Power has exclusive marketing rights to this technology throughout the
United States and Canada. The diagnostic cable testing package includes the
cable test, data analysis, a comprehensive written report and computer data on
each cable. Ultra Power markets this service to utilities and commercial
customers with underground cable.
- - --------------------------------------------------------------------------------
NONREGULATED BUSINESS INFORMATION
The following table summarizes the aggregate financial position of all NSP's
nonregulated business.
December 31
- - ------------------------------------------------------------------------------------------------------------
- - ------------------------------------------------------------------------------------------------------------
(Thousands of dollars) 1998 1997
- - ------------------------------------------------------------------------------------------------------------
Equity investment by nonregulated businesses in unconsolidated projects
(Including undistributed earnings and capitalized development costs)
Australian projects $327 841 $320 069
European projects 134 197 105 925
South American and Latin American projects 95 173 81 712
Other international projects 0 9 534
Affordable housing projects (U.S.) 45 411 38 230
Other U.S. projects 259 974 185 264
- - ------------------------------------------------------------------------------------------------------------
Total equity investment in unconsolidated nonregulated projects $862 596 $740 734
Nonregulated property of consolidated subsidiaries
(net of accumulated depreciation) - primarily U.S. projects 282 349 256 726
Notes receivable from unconsolidated projects, including current portion 110 886 133 426
Current assets 107 541 110 218
Other assets 126 110 108 229
- - ------------------------------------------------------------------------------------------------------------
Total assets of nonregulated businesses $1 489 482 $1 349 333
- - ------------------------------------------------------------------------------------------------------------
- - ------------------------------------------------------------------------------------------------------------
Long-term debt, including current maturities $578 233 $555 843
Short-term debt 126 236 122 637
Other current liabilities 36 183 47 775
Other liabilities 69 072 66 283
- - ------------------------------------------------------------------------------------------------------------
Total liabilities of nonregulated businesses 812 724 792 538
NSP's equity investment in nonregulated businesses 759 355 619 682
Cumulative currency translation adjustments (82 597) (62 887)
- - ------------------------------------------------------------------------------------------------------------
Total equity of nonregulated businesses 676 758 556 795
- - ------------------------------------------------------------------------------------------------------------
Total liabilities and equity of nonregulated businesses $1 489 482 $1 349 333
- - ------------------------------------------------------------------------------------------------------------
- - ------------------------------------------------------------------------------------------------------------
20
ENVIRONMENTAL MATTERS
NSP regularly and proactively monitors its operations to ensure the
environment is not adversely affected and takes timely corrective actions if
past practices have had a negative impact on the environment. Significant
resources are dedicated to environmental training, monitoring and compliance.
NSP strives to maintain compliance with all applicable environmental laws.
As discussed in Note 14 to the Financial Statements under Item 8,
NSP-Wisconsin may be involved in the cleanup and remediation at a site in
Ashland, Wis. In March 1999, NSP-Wisconsin's consultant submitted a feasibility
study (FS) relating to the potential remediation of the Ashland site. The
options in the FS describe cost alternatives in the range of $10 million to $20
million. These options represent lower cost alternatives than those presented by
the Wisconsin Department of Natural Resource's (WDNR) consultant. Although the
range of options described by NSP-Wisconsin's consultant is somewhat higher than
NSP-Wisconsin's previous estimate, it is not materially different than
information considered in determining NSP-Wisconsin's environmental accrual
levels as of Dec. 31, 1998.
NSP is potentially liable for remediation of waste disposal sites owned by
others, and for decommissioning and restoration of present and former plant
sites. For further discussion of environmental matters, see "Environmental
Matters" under Management's Discussion and Analysis under Item 7, and Note 14 to
the Financial Statements under Item 8.
PERMITS
NSP's regulated businesses are required to renew environmental operating
permits for their facilities at least every five years. NSP believes that it is
in compliance, in all material respects, with environmental permitting
requirements.
WASTE DISPOSAL
Spent nuclear fuel storage and disposal issues are discussed in "Electric
Utility Operations - Nuclear Power Plants - Licensing, Operation and Waste
Disposal and Capability and Demand," in Management's Discussion and Analysis
under Item 7 and in Notes 13 and 14 of Notes to Financial Statements under Item
8.
NSP has met or exceeded the state and federal removal and disposal
requirements for polychlorinated biphenyl (PCB) equipment. NSP has removed
nearly all known PCB capacitors from its distribution system. NSP also has
removed nearly all known network transformers and equipment in power plants
containing PCBs. NSP continues to test and dispose of PCB-contaminated mineral
oil and equipment in accordance with regulations. PCB-contaminated mineral oil
is detoxified and reused or burned for energy recovery at permitted facilities.
Any future cleanup or remediation costs associated with past PCB disposal
practices are unknown at this time.
AIR EMISSIONS CONTROL AND MONITORING
In 1994, the U.S. Environmental Protection Agency (EPA) proposed new air
emission guidelines for municipal waste combustors. The state of Minnesota has
finalized the waste combustor rule. This rule is more restrictive than the
federal guidelines. To meet the new federal and state requirements,
NSP-Minnesota is in the process of installing additional pollution-control and
monitoring equipment at the Red Wing plant and additional monitoring equipment
at the Wilmarth plant. NSP-Minnesota has evaluated equipment to meet the
requirements. The required equipment will likely cost between $8 million and $11
million.
The Clean Air Act calls for reductions in emissions of sulfur dioxide and
nitrogen oxides from electric generating plants. NSP has expended significant
amounts over the years to reduce sulfur dioxide emissions at its plants. Other
expenditures will be necessary on the NSP system for compliance with the Phase
II nitrogen oxides limitations, which become effective in the year 2000.
Evaluations are currently under way to determine if changing operating
procedures could reduce or eliminate future capital expenditures to meet Phase
II requirements.
As part of its Clean Air Act compliance effort, testing of a full-scale
prototype wet electrostatic precipitator (wet ESP) was completed at Sherco in
1996. The wet ESP equipment was installed in 1995 in one of the plant's existing
scrubber modules to determine its effectiveness in reducing particulate
emissions and lowering opacity. Based on operating test results, NSP has chosen
to convert multiple scrubber modules on Sherco units 1 and 2 to the wet ESP
design. Capital investment to date for the prototype has been $3 million. NSP
estimates total capital expenditures for this project of $46 million through
2002.
In 1997, the EPA revised the National Ambient Air Quality Standards for
ozone and fine particulate matter. It is anticipated, based on historical
monitoring, that NSP will be in compliance with the new standards. However, if
an area is determined to not comply with the new standards, reductions in
emissions of sulfur dioxide and oxides of nitrogen could be required.
NSP has conducted air toxics tests at its major facilities and has shared
these results with state and federal agencies. NSP also researched ways to
further reduce mercury emissions. This information has also been shared with
state and federal agencies. The
21
Clean Air Act requires the EPA to investigate the impact of air toxic emissions
from utilities and, if appropriate, recommend regulations to control those
emissions. The EPA delivered a report to Congress in early 1998 that recommended
additional investigation of air toxics emissions. The report did not recommend
any controls on utility boilers at this time. In 1997, NSP worked proactively
with the Minnesota Pollution Control Agency (MPCA) and key legislators to pass
legislation requiring the annual reporting of mercury emissions from utility
boilers to the MPCA. NSP is also working with the MPCA on its Mercury Reduction
Initiative. The initiative is evaluating various strategies to reduce mercury
contamination in fish.
During 1996, NSP-Wisconsin received two notices of violation (NOV) from
the WDNR stating that emissions from unit 2 at NSP-Wisconsin's French Island
generating facility had exceeded allowable levels for dioxin. Corrective
action brought dioxin emissions within acceptable levels by the end of 1997.
NSP-Wisconsin expects that the WDNR will close the NOV when it issues a new
operating permit and forego any fines.
In December 1997, nearly 160 nations adopted the Kyoto Protocol to the
United Nations Framework Convention on Climate Change (Kyoto Protocol). The
Kyoto Protocol obligates developed nations to meet certain emissions targets;
specific limits vary from country to country. If approved internationally and if
the U.S. is a party, the Kyoto Protocol would impose, during the first
commitment period of 2008-2012, a binding obligation on the U.S. to reduce its
emissions of carbon dioxide, methane and nitrous oxide to a level of 7 percent
below 1990 levels and its emissions of hydrofluorocarbons, perfluorocarbons and
sulfur hexaflouride by 7 percent below 1990 or 1995 levels. Although the U.S.
has signed the Kyoto Protocol, it must be ratified by the U.S. Senate for the
U.S. to become a party to the protocol. In November 1998, a plan was adopted
that sets timetables and schedules for developing mechanisms to implement the
Kyoto Protocol. Until they are developed, the impact on NSP cannot be
determined.
WATER QUALITY MONITORING
To comply with federal and state laws and state regulatory permit
requirements, and with NSP's corporate environmental policy, NSP has installed
environmental monitoring systems at all coal and RDF ash landfills and coal
stockpiles to assess and monitor the impact of these facilities on the quality
of ground and surface waters. Degradation of water quality in the state is
prohibited by law and requires remedial action for restoration to an
agreed-upon, acceptable clean-up level. The cost of overall water quality
monitoring is not material in relation to NSP's operating results.
ELECTROMAGNETIC FIELDS
Electric and magnetic fields (EMF) surround electric wires and conductors
of electricity such as electrical tools, household wiring, appliances, electric
distribution lines, electric substations and high-voltage electric transmission
lines. Some studies have found statistical associations between surrogates of
EMF and some forms of cancer. The nation's electric utilities, including NSP,
have participated in the sponsorship of research to determine the possible
health effects of EMF. Through its participation with several agencies, NSP
continues its investigation and research with regard to possible health effects
posed by exposure to EMF. No litigation has been commenced or material claims
asserted against NSP for adverse health effects or diminution of property values
due to EMF.
CONTINGENCIES
Both regulatory requirements and environmental technology change rapidly.
Accordingly, NSP cannot presently estimate the extent to which it may be
required by law, in the future, to make additional capital expenditures or incur
additional operating expenses for environmental purposes. NSP also cannot
predict whether future environmental regulations might result in significant
reductions in generating capacity or efficiency or otherwise affect NSP's
income, operations or facilities.
CAPITAL SPENDING AND FINANCING
NSP's capital spending program is designed to assure that there will be
adequate generating, transmission and distribution capacity to meet the future
needs of its utility service area, and to fund investments in nonregulated
businesses. NSP continually reassesses needs and, when necessary, appropriate
changes are made in the capital expenditure program. Current year capital
spending activity and future financing requirements and sources are discussed in
the Management's Discussion and Analysis under Item 7.
In March 1998, NSP-Minnesota issued $100 million of 5.875 percent First
Mortgage Bonds due March 1, 2003, and $150 million of 6.5 percent First Mortgage
Bonds due March 1, 2028. The proceeds were used to redeem its: $50 million 7.375
percent and $50 million 7.5 percent First Mortgage Bonds on April 27, 1998;
300,000 shares of its cumulative preferred stock adjustable rate series A and
650,000 shares of its cumulative preferred stock adjustable rate series B, both
at $100 per share, plus accrued dividends on March 31, 1998; and to reduce
short-term debt balances.
22
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1998 the total number of full- and part-time NSP employees was
7,907 and the total number of benefit employees was 6,945. Of this number,
approximately 2,636 employees are represented by five local IBEW labor unions
under a three-year collective bargaining agreement, which expires Dec. 31, 1999.
WAGE INCREASES: NSP uses salary surveys that indicate how other relevant
companies pay their employees for comparable positions. In January 1998,
nonbargaining employees received an average wage increase of 3.4 percent, and
bargaining employees received a 2.0 percent base wage scale increase. In July
1998, bargaining employees received a 2.0 percent base wage increase. In January
1999, nonbargaining employees received an average wage increase of 3.9 percent.
Base wage scale increases for bargaining employees in 1999 were 2.0 percent.
RETIREMENT PLAN CHANGES: Effective January 1999, NSP revised its
retirement plans for nonbargaining employees as follows:
- - - The retiree medical plan was discontinued for employees retiring after
Dec. 31, 1998.
- - - The qualified pension plan was enhanced to provide a Retirement Spending
Account and enhanced Social Security supplement to use for medical coverage
or to supplement pension benefits.
- - - The 401(k) plan was enhanced, increasing the amount of employee
contributions matched by NSP.
Bargaining employee benefit plans are unchanged for 1999.
23
EXECUTIVE OFFICERS *
Present Positions and Business Experience
Name Age During the Past Five Years
- - -------------------------------------------------------------------------------------------------------------------
JAMES J HOWARD 63 Chairman of the Board, President and Chief Executive
Officer since 12/01/94; and previously Chairman of the
Board and Chief Executive Officer.
- - -------------------------------------------------------------------------------------------------------------------
PAUL E ANDERS 55 Vice President and Chief Information Officer since
5/01/97; and previously Vice President - Information
Services at Chrysler Financial Corporation.
- - -------------------------------------------------------------------------------------------------------------------
GRADY P BUTTS 52 Vice President - Human Resources since 7/01/97; Area
Leader - Human Resources Management Services
from 8/01/93 to 6/30/97; and previously Director of
Human Resources - Electric Utility.
- - -------------------------------------------------------------------------------------------------------------------
GARY R JOHNSON 52 Vice President and General Counsel since 11/01/91.
- - -------------------------------------------------------------------------------------------------------------------
CYNTHIA L LESHER 50 President - NSP Gas since 7/01/97; and previously
Vice President - Human Resources.
- - -------------------------------------------------------------------------------------------------------------------
EDWARD J MCINTYRE 48 Vice President and Chief Financial Officer since
1/01/93.
- - -------------------------------------------------------------------------------------------------------------------
THOMAS A MICHELETTI 52 Vice President - Public and Government Affairs since
11/1/94; Vice President - General Counsel and
Secretary of NRG Energy, Inc. from 5/11/94 to
10/31/94; and previously Vice President-General
Counsel, NRG from 9/15/93 to 5/10/94.
- - -------------------------------------------------------------------------------------------------------------------
JOHN P MOORE, JR 52 Corporate Secretary since 7/01/97; and previously
General Counsel and Corporate Secretary for
NSP-Wisconsin.
- - -------------------------------------------------------------------------------------------------------------------
* As of 3/01/99
24
EXECUTIVE OFFICERS *
Present Positions and Business Experience
Name Age During the Past Five Years
- - -------------------------------------------------------------------------------------------------------------------
JOHN A NOER 52 President - NSP Combustion and Hydro Generation
since 6/16/98; President and Chief Executive
Officer of NSP-Wisconsin from 1/1/93 to 6/15/98.
- - -------------------------------------------------------------------------------------------------------------------
PAUL E PENDER 44 Vice President - Finance and Treasurer since 5/01/97;
Assistant Treasurer and Director, Corporate Finance
from 7/01/94 to 4/30/97; Director, Corporate Finance
from 2/01/93 to 6/30/94; and previously Manager,
Financial and Investment Analysis.
- - -------------------------------------------------------------------------------------------------------------------
ROGER D SANDEEN 53 Vice President and Controller since 7/01/89; and
previously Chief Information Officer from 5/01/92
to 4/30/97.
- - -------------------------------------------------------------------------------------------------------------------
DAVID M SPARBY 44 Vice President - Regulatory Services since 9/1/98; and
previously Director - Regulatory Services.
- - -------------------------------------------------------------------------------------------------------------------
LOREN L TAYLOR 52 President - NSP Electric since 10/27/94; and
previously Vice President - Customer Operations.
- - -------------------------------------------------------------------------------------------------------------------
MICHAEL D WADLEY 42 President - Nuclear Generation since 6/16/98; Vice
President - Nuclear Generation from 2/03/97 to
6/15/98; Nuclear Plant Manager - Prairie Island
from 10/26/95 to 2/02/97; Plant Manager - Prairie
Island from 2/01/93 to 10/25/95; and previously
General Superintendent of Operations - Prairie
Island.
- - -------------------------------------------------------------------------------------------------------------------
* As of 3/01/99
25
ITEM 2 - PROPERTIES
- - --------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------
NSP's major electric generating facilities consist of the following:
1998
Summer
Capability 1998 Output
Station and Unit Fuel Installed (MW) (Millions of KWH)
---------------- ---- --------- ---------- -----------------
Sherburne
Unit 1 Coal 1976 712 3 810.9
Unit 2 Coal 1977 721 4 429.2
Unit 3 Coal 1987 514 3 696.8
Prairie Island
Unit 1 Nuclear 1973 527 4 209.1
Unit 2 Nuclear 1974 513 3 335.3
Monticello Nuclear 1971 545 4 118.9
King Coal 1968 571 2 646.2
Black Dog
4 Units Coal/Natural 1952-1960 462 1 492.9
Gas
High Bridge
2 Units Coal 1956-1959 263 1 521.5
Riverside
2 Units Coal 1964-1987 372 2 567.8
Other Various Various 1 949 1 769.4
NSP's electric generating facilities provided 73 percent of its KWH
requirements in 1998. The current generating facilities are expected to be
adequate base load sources of electric energy until 2003-2006, as detailed in
NSP-Minnesota's electric resource plan filed with the MPUC in 1998. All of NSP's
major generating stations are located in Minnesota on land owned by
NSP-Minnesota.
- - --------------------------------------------------------------------------------
At Dec. 31, 1998, NSP had overhead and underground transmission and
distribution lines as follows:
Voltage Length (Pole Miles)
------- -------------------
500KV 265
345KV 732
230KV 283
161KV 339
115KV 1,622
Less than 115KV 48,998
NSP also has approximately 281 transmission and distribution substations
with capacities greater than 10,000 kilovoltamperes (KVA) and approximately 285
with capacities less than 10,000 KVA.
Manitoba Hydro, Minnesota Power Company and NSP completed the construction
of a 500-KV transmission interconnection between Winnipeg, Manitoba, Canada, and
the Minneapolis-St Paul, Minnesota, area in 1980. NSP has a contract with
Manitoba Hydro for 500 MW of firm power utilizing this transmission line. In
addition, NSP is interconnected with Manitoba Hydro through a 230 KV
transmission line completed in 1970. In 1995, a project was completed to
increase the Manitoba-US transmission interconnection by a nominal 400 MW to
1,900 MW.
The electric delivery system utilization has increased during recent years
due to better analytical methods and enhanced energy management system
monitoring and control capability. This increased utilization has been achieved
while continuing to operate within reliability parameters established by MAPP
and North American Electric Reliability Council (NERC).
Plans are currently being implemented for electric delivery system
upgrades to accommodate load growth expected in the Minneapolis-St. Paul area
through 2010. As the least cost option to accommodate the load growth, portions
of the 69 KV transmission facilities, especially those located on the outskirts
of the Twin Cities, are being reconductored and operated at 115 KV; distribution
development in these areas has been converted to 34.5 KV. By reconductoring on
existing right-of-ways and increasing distribution voltage, the requirements for
new right-of-ways and substation sites are minimized compared with other
alternatives for serving the load growth.
NSP natural gas mains include approximately 116 miles of transmission
mains and approximately 9,598 miles of distribution mains. In addition, Viking
owns a 500-mile interstate natural gas pipeline serving portions of Minnesota,
Wisconsin and North Dakota.
26
Virtually all of the utility plant of NSP-Minnesota and NSP-Wisconsin are
subject to the lien of their first mortgage bond indentures pursuant to which
they have issued first mortgage bonds.
For discussion and information concerning nonregulated properties, see
"Nonregulated Subsidiaries" under Item 1, incorporated by reference.
ITEM 3 - LEGAL PROCEEDINGS
- - --------------------------------------------------------------------------------
In the normal course of business, various lawsuits and claims have arisen
against NSP. Management, after consultation with legal counsel, has recorded an
estimate of the probable cost of settlement or other disposition for such
matters.
On June 8, 1998, NSP filed a complaint in the Court of Federal Claims
against the DOE requesting damages for the DOE's partial breach of the Standard
Contract. NSP requests damages in excess of $1 billion, which consists of the
costs of storage of spent nuclear fuel at the Prairie Island nuclear generating
plant, as well as anticipated costs related to the Private Fuel Storage, LLC and
the 1994 state legislation limiting the number of casks that can be used to
store spent nuclear fuel at Prairie Island. On June 8, 1998, Indiana Michigan
Power Company, Duke Energy and Florida Power and Light filed similar complaints
in the Court of Federal Claims against the DOE requesting damages for the DOE's
partial breach of the Standard Contract. On June 17, 1998, the four utilities
filed a motion to consolidate the complaints. On June 26, 1998, the Court of
Federal Claims determined that briefing on jurisdictional issues in NSP's case
would proceed, while the other cases are stayed. Essentially, NSP's case
requesting damages of $1.4 billion will proceed as the lead case on
jurisdictional issues.
On Aug. 7, 1998, a group of residential and commercial customers brought a
class action lawsuit against the DOE in the Federal District Court in
Minneapolis, Minn. The suit demands the return of monies paid by customers into
the nuclear waste fund and other damages, based on the failure of the DOE to
meets its unconditional obligation to accept spent nuclear fuel by Jan. 31,
1998. NSP is named as nominal defendant because NSP has the contract with the
DOE under which payments are made into the fund.
On Sept. 15, 1997, NSP sought a determination in which the City of
Oakdale, Minn. (Oakdale) must abide by NSP-Minnesota's tariffs filed with the
MPUC in the Washington County District Court. The tariffs require Oakdale to
pay the additional cost of undergrounding electrical facilities prior to
installation. On Feb. 2, 1999, the Minnesota Court of Appeals ruled that a
city can require NSP to place underground the overhead electric facilities
along city streets and that the MPUC did not have the authority to require
the city to pay for the additional cost of undergrounding. However, the court
confirmed the authority of the MPUC to allow or require NSP to collect the
added cost of undergrounding from customers within the city. Any cost
recovery would be at the discretion of the MPUC; otherwise, NSP would have to
include the additional costs of undergrounding facilities in future rate
cases or the costs would reduce earnings.
As discussed in Legal Claims in Note 14 to the Financial Statement under
Item 8, on Nov. 24, 1998, Wisconsin Electric Power Co. (WEPCO) filed a complaint
against NSP with FERC, relating to transmission service curtailments. In March
1999, NSP and WEPCO reached a settlement in principle. NSP and WEPCO will file
the agreement with the FERC and anticipate a FERC decision before the summer.
For a discussion of other legal claims, see "Legal Claims" in Note 14 of
Notes to the Financial Statements under Item 8, incorporated by reference. For a
discussion of environmental proceedings, see "Environmental Matters" under Item
1, incorporated by reference. For a discussion of proceedings involving NSP's
utility rates, see "Utility Regulation and Revenues" and "Gas Utility
Operations" under Item 1, and "Rate Filings" under Item 7, both incorporated by
reference.
27
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- - --------------------------------------------------------------------------------
None during the fourth quarter of 1998.
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- - --------------------------------------------------------------------------------
QUARTERLY STOCK DATA
NSP's common stock is listed on the New York Stock Exchange (NYSE),
Chicago Stock Exchange and the Pacific Stock Exchange. Following are the
reported high and low sales prices based on the NYSE Composite Transactions for
the quarters of 1998 and 1997 and the dividends declared per share during those
quarters. All per share amounts have been adjusted to reflect a two-for-one
stock split effective June 1, 1998, for shareholders of record on May 18, 1998.
1998 1997
---------------------------------- ------------------------------------
High Low Dividends High Low Dividends
---------- ---------- --------- -------- -------- ---------
First Quarter $29 25/32 $26 1/2 $0.3525 $24 9/16 $22 3/4 $0.3450
Second Quarter $30 7/32 $27 11/32 $0.3575 $26 $22 1/4 $0.3525
Third Quarter $29 3/16 $25 11/16 $0.3575 $26 15/32 $24 $0.3525
Fourth Quarter $30 13/16 $26 3/16 $0.3575 $29 7/16 $24 7/32 $0.3525
1998 1997 1996 1995 1994
------ ------ ------ ------ ------
Shareholders of record
at year-end 81 990 83 232 86 337 83 902 85 263
Book value per share
at year-end $16.25 $15.89 $15.47 $14.87 $14.18
Shareholders of record as of March 15, 1999, were 82,001.
NSP's Restated Articles of Incorporation and First Mortgage Bond Trust
Indenture provide for certain restrictions on the payment of cash dividends on
common stock. At Dec. 31, 1998, the payment of cash dividends on common stock
was not restricted except as described in Note 4 to the Financial Statements
under Item 8.
ITEM 6 - SELECTED FINANCIAL DATA
- - --------------------------------------------------------------------------------
(Dollars in millions except per share data) 1998 1997 1996 1995 1994
------ ------ ------ ------ ------
Utility operating revenues $2 819 $2 734 $2 654 $2 569 $2 487
Utility operating expenses $2 455 $2 372 $2 288 $2 223 $2 178
Net income $282 $237 $275 $276 $243
Earnings available for common stock $277 $226 $262 $263 $231
Average number of common shares
outstanding (000's) 150 502 140 594 137 121 134 646 133 550
Average number of common and
potentially dilutive shares outstanding (000's) 150 743 140 870 137 358 134 832 133 689
Earnings per Share-Basic $1.84 $1.61 $1.91 $1.96 $1.73
Earnings per Share-Diluted $1.84 $1.61 $1.91 $1.96 $1.73
Dividends declared per share $1.425 $1.403 $1.373 $1.343 $1.313
Total assets $7 396 $7 144 $6 637 $6 229 $5 950
Long-term debt $1 851 $1 879 $1 593 $1 542 $1 463
Ratio of earnings (excluding undistributed
equity income and including AFC) to fixed
charges 3.0 2.9 3.8 3.9 4.0
28
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
- - -------------------------------------------------------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
Northern States Power Company, a Minnesota corporation (NSP-Minnesota), has two
significant subsidiaries: Northern States Power Company, a Wisconsin corporation
(NSP-Wisconsin), and NRG Energy, Inc., a Delaware corporation (NRG).
NSP-Minnesota also has several other subsidiaries, including Viking Gas
Transmission Company (Viking), Energy Masters International, Inc. (EMI), Eloigne
Company (Eloigne), Seren Innovations, Inc. (Seren) and Ultra Power Technologies,
Inc. (Ultra Power). NSP-Minnesota and its subsidiaries collectively are referred
to as NSP.
All financial information pertaining to per share amounts and number of common
shares outstanding has been adjusted to reflect a two-for-one stock split that
occurred on June 1, 1998.
FINANCIAL OBJECTIVES AND RESULTS
NSP'S FINANCIAL OBJECTIVES ARE:
TO ACHIEVE A RETURN ON EQUITY IN THE TOP ONE-FOURTH OF THE UTILITY INDUSTRY
BASED ON A THREE-YEAR AVERAGE.
- NSP's average return on common equity for the three years ending in 1998
was 11.4 percent, which places NSP below the top quarter of the industry,
which was approximately 12.75 percent, and above the median industry
average of approximately 11.0 percent.
- The total return to investors (measured by dividends plus stock price
appreciation) on NSP common stock for the last five years averaged 11.2
percent per year, matching the total average return for the electric
industry.
- NSP's stock price fell 4.7 percent in 1998, while the Standard & Poor's
(S&P) electric utilities group increased in price by 10.2 percent.
TO INCREASE DIVIDENDS ON A REGULAR BASIS AND MAINTAIN A LONG-TERM AVERAGE PAYOUT
RATIO OF 65 TO 75 PERCENT. NSP has increased its dividend for 24 consecutive
years. In June 1998, NSP's annualized common dividend rate was increased by 2
cents per share, or 1.4 percent, from $1.41 to $1.43. The dividend payout ratio
was 77.7 percent in 1998, slightly outside the long-term objective range.
TO MAINTAIN LONG-TERM AVERAGE ANNUAL EARNINGS PER SHARE GROWTH OF 5 PERCENT.
NSP's earnings per share have grown by an average annual rate of 4.0 percent
since 1993.
TO PROVIDE AT LEAST 20 PERCENT OF NSP EARNINGS FROM NRG BY THE YEAR 2000. NRG
provided:
- 28 cents, or 15 percent, of NSP's earnings per share in 1998
- 16 cents, or 10 percent, of NSP's earnings per share in 1997
TO MAINTAIN CONTINUED FINANCIAL STRENGTH WITH A AA RATING FOR UTILITY BONDS.
NSP-Minnesota's first mortgage bonds were rated:
- AA by Fitch Investors Service, Inc.
- AA by S&P
- Aa3 by Moody's Investors Services (Moody's)
- AA by Duff & Phelps, Inc.
These ratings reflect the views of rating agencies, which can provide an
explanation of the significance of the ratings. A security rating is not a
recommendation to buy, sell or hold securities and is subject to revision or
withdrawal at any time by the rating agency. First mortgage bonds issued by
NSP-Wisconsin carry comparable ratings.
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. During
1998, NSP developed the following 10-Point Game Plan to achieve this mission:
GROW NRG NSP expects NRG to provide 20 percent of NSP earnings in 1999, one year
ahead of schedule. In addition, NRG's goal is to become a top independent power
producer in each of its core markets: North America, Europe and Asia-Pacific.
NRG expects to achieve these goals by profitably growing existing businesses and
adding new businesses.
POSITION NSP'S GENERATION BUSINESS FOR LONG-TERM VALUE NSP's conventional plants
include coal-fired, hydro, refuse-derived fuel, natural gas and oil-fired
facilities. To ensure these assets remain valuable, NSP will make careful
investments in these facilities to keep them reliable, efficient and
competitive. NSP is preparing to operate its generation facilities as a
stand-alone business in a competitive market.
CREATE AN INDEPENDENT NUCLEAR GENERATING COMPANY NSP's Monticello and Prairie
Island nuclear plants are extremely valuable assets. With increasing regulation
and associated costs in the nuclear industry, NSP believes the best way to
enhance NSP's nuclear assets is to combine our plants with other well-run
nuclear plants and create a free-standing nuclear generating company.
EXPAND ENERGY MARKETING To enhance NSP's position in the increasingly
competitive electric market, NSP expanded its wholesale energy marketing efforts
by establishing Energy Marketing within its Generation business unit. Energy
Marketing is responsible for meeting the requirements of NSP's retail and
wholesale electric customers for low-cost energy, while optimizing margins from
NSP's generation resources.
CREATE AN INDEPENDENT TRANSMISSION COMPANY To foster competition in the
wholesale electricity market, the Federal Energy Regulatory Commission (FERC)
requires the transmission portion of a utility's business to be functionally
separate from the utility's generation facilities. The state of Wisconsin also
calls for a separate transmission operating structure. NSP believes the best way
to ensure a reliable, efficient, customer-focused and investor-responsive
electric transmission network is to create a for-profit, independent
transmission company.
EXPAND NSP'S CORE ELECTRIC AND GAS DISTRIBUTION BUSINESS To expand our core
business, NSP will actively seek to acquire and merge with other energy
companies.
DEVELOP SEREN Seren has moved into the telecommunications business, with plans
to deliver high-speed Internet access, video-on-demand, telephone service and
cable TV. Seren is currently constructing a broadband network in St. Cloud,
Minn. Further expansion and development is anticipated.
GROW VIKING NSP's goal is to continue the growth of Viking through pipeline
expansion.
29
DRIVE EMI TO PROFITABILITY EMI is moving toward profitability by reducing costs
and narrowing its focus to concentrate on retrofitting and upgrading customer
facilities for greater energy efficiency. As part of its effort to concentrate
on federal facilities, EMI has been selected as a qualified vendor by the U.S.
Department of Energy and Department of Defense.
MANAGE NSP'S ENTIRE BUSINESS AS A PORTFOLIO NSP will manage its collective
businesses as a portfolio of assets with a focus on growth. NSP will acquire or
divest businesses and assets if it will increase shareholder value.
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 1998 and 1997, or are expected to have a material impact in
the future. It should be read in conjunction with the accompanying Financial
Statements and Notes.
Except for the historical statements contained in this report, 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
- issues relating to Year 2000 remediation efforts
- the higher risk associated with NSP's nonregulated businesses as
compared with NSP's regulated business
- the items described under "Factors Affecting Results of Operations"
- the other risk factors listed from time to time by NSP in reports filed
with the Securities and Exchange Commission (SEC), including Exhibit 99.01
to NSP's 1998 report on Form 10-K
RESULTS OF OPERATIONS
1998 COMPARED WITH 1997 AND 1996
NSP's earnings per share for the past three years were as follows:
EARNINGS PER SHARE - DILUTED 1998 1997 1996
- - ---------------------------------------------------------------
Regulated utility operations
(excluding merger costs) $ 1.58 $ 1.62 $ 1.79
Nonregulated operations 0.26 0.11 0.12
- - ---------------------------------------------------------------
Subtotal excluding merger costs $ 1.84 $ 1.73 $ 1.91
Write-off of merger costs (0.12)
- - ---------------------------------------------------------------
TOTAL $ 1.84 $ 1.61 $ 1.91
- - ---------------------------------------------------------------
- - ---------------------------------------------------------------
Revenue and expense items affecting earnings in these periods are discussed
later. In addition, average common shares outstanding increased due to stock
issuances, mainly a public offering in September 1997. In comparison with
average share levels in the prior year, dilution from increased average shares
decreased earnings per share by approximately 13 cents in 1998.
REGULATED UTILITY OPERATING RESULTS
ELECTRIC REVENUES The table below summarizes the principal reasons for the
electric revenue changes during the past two years:
(MILLIONS OF DOLLARS) 1998 VS.1997 1997 VS.1996
- - ---------------------------------------------------------------
Retail sales growth
(excluding weather impact) $ 63 $ 47
Estimated impact of weather
on retail sales volume 3 (23)
Sales for resale 42 8
Conservation cost recovery 11 10
Fuel cost recovery 19 31
Transmission and other 6 18
- - ---------------------------------------------------------------
TOTAL REVENUE INCREASE $144 $ 91
- - ---------------------------------------------------------------
- - ---------------------------------------------------------------
Electric sales growth for 1998 and 1997 is listed in the table below on both
an actual and weather-normalized basis. NSP's weather-normalization process
removes the estimated impact on sales of temperature variations from
historical averages.
(SALES GROWTH) 1998 VS. 1997 1997 VS. 1996
- - ------------------------------------------------------------------------
Weather- Weather-
Actual Normalized Actual Normalized
- - ------------------------------------------------------------------------
Residential 3.4% 3.7% (0.6)% 1.7%
Commercial and industrial 3.3% 3.1% 2.3% 2.9%
Total retail 3.3% 3.3% 1.5% 2.6%
Sales for resale 35.3% na (5.5)% na
TOTAL ELECTRIC SALES 7.1% 7.0% 0.6% 1.6%
- - ------------------------------------------------------------------------
- - ------------------------------------------------------------------------
na = not applicable
Retail electric sales accounted for 91 percent of NSP's electric revenue in 1998
and 93 percent in 1997. Retail electric sales growth for 1999 is estimated to be
2.4 percent over 1998, or 1.9 percent on a weather-adjusted basis.
Electric retail sales growth increased in 1998 due to strong economic conditions
in NSP's service territory. Electric retail sales growth increased in 1997 due
to economic conditions, partially offset by unfavorable average temperatures
compared with favorable average temperatures in 1996.
Sales for resale volumes and revenues increased in 1998 due to the expansion of
NSP's energy marketing operations. Sales for resale volumes decreased in 1997
due to constraints on NSP's system from unscheduled plant outages and storms.
Revenues from sales to other utilities increased in 1997 due to higher market
prices.
ELECTRIC MARGIN As shown in the table below, electric margin equals electric
revenue minus related production expenses, which includes electric fuel and
power purchase costs.
(MILLIONS OF DOLLARS) 1998 1997 1996
- - -------------------------------------------------------------
Electric revenue $2 362 $2 218 $2 127
Fuel for electric generation (311) (310) (301)
Purchased and interchange power (378) (286) (244)
- - ------------------------------------------------------------
ELECTRIC MARGIN $1 673 $1 622 $1 582
- - ------------------------------------------------------------
- - ------------------------------------------------------------
30
Electric production expenses tend to vary with changing retail and wholesale
sales requirements and unit cost changes in fuel and purchased power. However,
due to fuel clause cost recovery mechanisms for retail customers and the ability
to vary wholesale prices with changing market conditions, most fluctuations in
production expenses do not affect electric margin, as shown below. The table
below summarizes the principal reasons for electric margin changes during the
past two years:
(MILLIONS OF DOLLARS) 1998 VS. 1997 1997 VS. 1996
- - ----------------------------------------------------------------------
Retail sales growth
(excluding weather impact) $51 $34
Estimated impact of weather
on retail sales volume 3 (19)
Sales for resale 11 (5)
Conservation cost recovery 11 10
Transmission and other (8) 24
Demand expenses (17) (4)
- - ----------------------------------------------------------------------
TOTAL ELECTRIC MARGIN INCREASE $51 $40
- - ----------------------------------------------------------------------
- - ----------------------------------------------------------------------
GAS REVENUES The table below summarizes the principal reasons for the gas
revenue changes during the past two years:
(MILLIONS OF DOLLARS) 1998 VS. 1997 1997 VS. 1996
- - -----------------------------------------------------------------------
Sales growth
(excluding weather impact) $ 7 $ 13
Estimated impact of weather
on firm sales volume (46) (41)
Purchased gas adjustment
clause recovery (40) 28
Rate changes
and conservation cost recovery 9 (1)
Black Mountain Gas Company
acquisition 6
Transportation and other 6 (11)
- - ----------------------------------------------------------------------
TOTAL REVENUE DECREASE $(58) $(12)
- - ----------------------------------------------------------------------
- - ----------------------------------------------------------------------
Gas sales growth for 1998 and 1997 is listed in the tables below on both an
actual and weather-normalized basis. 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).
(SALES GROWTH) 1998 VS. 1997 1997 VS. 1996
- - --------------------------------------------------------------------------------
WEATHER- WEATHER-
ACTUAL NORMALIZED ACTUAL NORMALIZED
- - --------------------------------------------------------------------------------
Total firm (13.1)% 2.9% (10.8)% 2.2%
Interruptible (10.4)% na 11.6% na
Total retail (12.4)% (0.6)% (6.1)% 4.1%
Transportation
and other 33.4% na (33.3)% na
Viking (external sales) 2.8% na 4.8% na
TOTAL GAS SALES
AND DELIVERY (1.5)% 2.4% (2.0)% 1.9%
- - --------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------
na = not applicable
Firm gas sales in 1999 are estimated to be 23.1 percent higher than 1998 sales,
or 2.1 percent higher on a weather-adjusted basis.
The 1998 firm sales decrease was due to more unfavorable weather in 1998,
compared with 1997, partially offset by sales growth. Also, interruptible sales
declined in 1998 because favorable alternate fuel prices, as compared with
natural gas, caused interruptible customers to purchase less natural gas. The
1998 interruptible sales decrease also was due to the ability of customers to
switch to transportation-only service.
The decrease in firm sales in 1997 was primarily due to the impacts of favorable
weather in 1996 and unfavorable weather in 1997, partially offset by sales
growth. The weather-adjusted sales growth was partially offset by lost gas sales
as a result of flooding in the Grand Forks area. Interruptible sales increased
in 1997 because favorable gas prices, compared with alternate fuels, caused
interruptible customers to purchase more natural gas.
GAS MARGIN As shown in the table below, gas margin equals gas revenue less the
cost of gas sold.
(MILLIONS OF DOLLARS) 1998 1997 1996
- - -------------------------------------------------------------
Gas revenue $457 $515 $527
Cost of gas purchased
and transported (267) (331) (336)
- - -------------------------------------------------------------
GAS MARGIN $190 $184 $191
- - -------------------------------------------------------------
- - -------------------------------------------------------------
The cost of gas tends to vary with changing sales requirements and unit cost of
gas purchases. However, due to purchased gas cost recovery mechanisms for retail
customers, nearly all fluctuations in the cost of gas have no effect on gas
margin, as shown below. The table below summarizes the principal reasons for gas
margin changes during the past two years:
(MILLIONS OF DOLLARS) 1998 VS. 1997 1997 VS. 1996
- - --------------------------------------------------------------------------------
Retail and transportation sales growth
(excluding weather impact) $ 7 $ 6
Estimated impact of weather
on firm sales volume (16) (12)
Rate changes 9 (1)
Black Mountain Gas Company
acquisition 4
Other 2
- - --------------------------------------------------------------------------------
TOTAL GAS MARGIN INCREASE (DECREASE) $ 6 $(7)
- - --------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------
UTILITY OPERATING EXPENSES Total utility operating expenses, including fuel,
energy purchases and the cost of gas, increased by $82.9 million in 1998
compared with 1997, and by $83.8 million in 1997 compared with 1996. Increases
in electric production costs, partially offset by decreases in cost of gas
purchased, together account for $28.8 million of the 1998 increase and $47.3
million of the 1997 increase. In addition, variations in income taxes are
primarily attributable to fluctuations in pretax income.
OTHER OPERATION, MAINTENANCE AND ADMINISTRATIVE AND GENERAL Expenses increased
in 1998 by $48.3 million, or 7.2 percent, compared with 1997. The higher costs
in 1998 are primarily due to increased expenses associated with plant outages,
nuclear regulatory costs, system reconstruction due to extensive storm damage,
Year 2000 remediation, energy marketing activities, customer growth, an
insurance refund in 1997 and Black Mountain Gas Company, which was acquired in
1998.
31
In 1997, the total of these expenses increased by $37.4 million, or 5.9 percent,
compared with 1996. The higher 1997 costs were primarily due to increased
expenses associated with business interruptions, customer service, network
integration transmission service (NTS), scheduled plant maintenance outages and
technology improvements. Business interruptions in 1997 included flooding in
NSP's service area, an unscheduled baseload nuclear plant outage and storm
damage to transmission lines. Technology improvements included development of
customer information, automated meter reading and other systems, including Year
2000 remediation. Cost increases were partially offset by a $6.9 million
decrease in administrative and general expenses, reflecting decreases in
insurance and employee benefit costs.
DEPRECIATION AND AMORTIZATION Costs increased $12.3 million in 1998 and $19.4
million in 1997 primarily due to higher levels of depreciable plant, including
new information systems and equipment with relatively short useful lives.
NONOPERATING ITEMS RELATED TO UTILITY BUSINESSES
UTILITY FINANCING COSTS Interest costs recognized for NSP's utility businesses,
including amounts capitalized to reflect the financing costs of construction
activities, were $115.8 million in 1998, $120.3 million in 1997 and $123.1
million in 1996. In addition to interest expense, beginning in 1997, financing
costs of NSP's utility businesses include distributions on redeemable preferred
securities, which were $15.8 million in 1998 and $14.4 million in 1997.
The 1998 decrease is largely due to lower average short-term debt levels,
partially offset by increased long-term debt levels. (For more information see
the Statement of Capitalization.) 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 average short-term debt balance for utility
operations was $58.9 million in 1998, $208.3 million in 1997 and $265.4 million
in 1996.
MERGER COSTS In May 1997, NSP and Wisconsin Energy Corporation (WEC) mutually
terminated their plans to merge. NSP's earnings for 1997 include a pretax charge
to nonoperating expense of $29 million, or 12 cents per share, to write off its
cumulative merger-related costs incurred.
PREFERRED DIVIDENDS Dividends paid to preferred shareholders declined by
$5.5 million in 1998 and $1.2 million in 1997 due to the redemption of several
series of preferred stock during those years.
NONREGULATED BUSINESS RESULTS
NSP anticipates that the earnings from nonregulated operations will experience
more variability than regulated utility businesses, due to the nature of these
nonregulated businesses. A description of NSP's primary nonregulated businesses
and their earnings contribution is summarized below.
- NRG is primarily involved in independent power production, commercial and
industrial heating and cooling, and energy-related refuse-derived fuel
production. NRG's business strategy includes holding a portfolio of
nonregulated energy projects on both a wholly owned and joint venture
basis. The divestitures of partial or entire interests in projects when
the economics maximize shareholder value is a continuing part of NRG's
strategy.
- EMI is primarily an energy services company.
- Eloigne invests in affordable housing.
- Seren provides broadband communication services.
CONTRIBUTION TO NSP'S EARNINGS PER SHARE 1998 1997 1996
- - --------------------------------------------------------------------------------
NRG $0.28 $0.16 $0.15
EMI (0.05) (0.08) (0.06)
Eloigne 0.04 0.03 0.02
Seren (0.02) (0.01) 0.00
Other 0.01 0.01 0.01
- - --------------------------------------------------------------------------------
TOTAL $0.26 $0.11 $0.12
- - --------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------
NRG NRG's earnings increased in 1998, compared with 1997, primarily due to
income from new projects, including: El Segundo, Long Beach, certain Pacific
Generation Company (PGC) operations, an increase in NRG's holdings in Energy
Developments Limited and higher earnings from Loy Yang. In addition, NRG's
landfill gas subsidiary, NEO, entered into projects in 1997 and 1998 that are
generating higher levels of energy tax credits. Increased earnings were
partially offset by higher interest costs due to the $250 million senior notes
issued in mid-1997, interest on NRG's revolving line of credit and new debt
obtained for certain NEO projects and the purchase of PGC. Also, NRG's earnings
in 1998 were adversely affected by declines in the value of the Australian
dollar and German deutsche mark in relation to the U.S. dollar. If exchange
rates throughout 1998 had stayed the same as the beginning of the year, NRG's
1998 earnings would have been approximately 1 cent per share higher.
In December 1998, NRG sold one-half of its 50 percent interest in Enfield Energy
Centre Ltd. (EECL) to an affiliate of El Paso International for approximately
$26.2 million, resulting in an after-tax gain to NRG of approximately $16.6
million. This gain increased 1998 earnings by approximately 11 cents per share.
NRG continues to hold a 25 percent interest in EECL. Also in 1998, NRG recorded
a charge of approximately $22 million ($15.2 million after tax) to write down
its investment in a 400-megawatt, coal-fired power station in Cilegon, West
Java, due to the political and economic instability in Indonesia. This
write-down reduced 1998 earnings by approximately 10 cents per share.
NRG's 1997 earnings increased compared with 1996 largely due to income from new
projects, including tax credits from NEO. New projects contributing to NRG's
earnings include: Bolivian Power Company Ltd. (COBEE), PGC, Schkopau and Loy
Yang. NRG's earnings also included gains on the sale of equity interests in two
projects late in 1997, offset by a write-down of NRG's Sunnyside project. NRG's
increased earnings in 1997 were partially offset by increased interest costs and
declines in the value of the Australian dollar and German deutsche mark in
relation to the U.S. dollar. If exchange rates throughout 1997 stayed the same
as the beginning of the year, NRG's 1997 earnings would have been approximately
2 cents per share higher.
In the past, NSP has reported gains from divestitures of NRG projects and losses
from write-downs of NRG projects as nonrecurring items. Since its inception,
NRG's investment in nonregulated energy projects has grown substantially. NRG
manages these projects as a portfolio and evaluates earnings enhancement
opportunities and risks from unsuccessful ventures on an ongoing basis. As such,
NSP expects gains and losses to occur periodically. Therefore, while NSP will
continue to disclose significant NRG gains and losses, we will no longer report
these transactions as nonrecurring events.
Further information on NRG's financial results may be obtained from NRG's annual
report on Form 10-K filed with the SEC.
32
EMI EMI's losses for 1998 were lower than 1997, due to increased margins and
1997 losses incurred by Enerval, a joint venture previously held by EMI. In June
1998, EMI sold its interest in Enerval. EMI's investment in Enerval was written
down in the fourth quarter of 1997 and, as a result, the transaction had no
material impact on 1998 earnings.
EMI's losses for 1997 were higher than 1996 losses, 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. and Energy Masters
Corporation, 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
negatively affected operating margins during the first half of 1996.
OTHER Eloigne's earnings grew in 1997 and 1998, due to new investments in
affordable housing projects. Seren is experiencing losses as it develops its
broadband communication services network in St. Cloud, Minn.
FACTORS AFFECTING RESULTS OF OPERATIONS
NSP's results of operations during 1998, 1997 and 1996 primarily were dependent
on its electric and gas utility businesses. NSP's utility revenues depend on
customer usage, which varies with weather conditions, general business
conditions 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, Arizona and Michigan. Rates are designed to recover
plant investment, 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 requested
infrequently 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.
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
restructuring 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, 1998, NSP reported on its
balance sheet regulatory assets of approximately $210 million and regulatory
liabilities of approximately $149 million that would need to be recognized in
the income statement in the absence of regulation. Included in these regulatory
assets are $73 million of conservation expenditures that are expected to be
recovered by the year 2000. In addition to a potential write-off of regulatory
assets and liabilities, deregulation and competition may require recognition of
certain "stranded costs" not recoverable under market pricing. NSP currently
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. (See Notes 1 and 9 to the Financial Statements for further discussion.)
In June 1998, the Minnesota Department of Public Service recommended the
Minnesota Public Utilities Commission (MPUC) discontinue recovery of lost
margins, load management discounts and performance incentives from conservation
programs for NSP-Minnesota and other Minnesota public utilities. In November
1998, the MPUC approved continued recovery of lost margins, discounts and
performance bonuses for 1998. However, the MPUC put Minnesota utilities on
notice that there may be significant changes, including elimination of rate
recovery, pending the outcome of a 1999 study. A commission round table will
study the issue and report its findings by May 1, 1999. In 1998, NSP-Minnesota
recorded approximately $33 million, primarily in electric revenue, from the
conservation incentives under review by the MPUC.
RATE FILINGS The status of NSP's recent rate and cost-of-service filings with
regulators is summarized below:
- In December 1997, NSP-Minnesota filed an annual natural gas rate increase
request of approximately $18.5 million in Minnesota. An interim rate
increase totaling $13.9 million on an annualized basis was approved
effective Feb. 1, 1998, subject to refund. On Dec. 11, 1998, the MPUC
issued its final order granting NSP-Minnesota a gas rate increase of $13.4
million, or 4.0 percent, on an annualized basis.
- In November 1997, NSP-Wisconsin filed a retail electric and gas rate case
with the Public Service Commission of Wisconsin (PSCW), requesting an
annual increase of approximately $12.7 million, or 4.3 percent, in retail
electric rates and an annual decrease of $1.7 million, or 1.9 percent, in
retail gas rates. On Sept. 15, 1998, the PSCW issued an order granting an
electric rate increase of $7.3 million, or 2.5 percent, and a gas rate
decrease of $1.9 million, or 2.2 percent, on an annual basis.
- In February and March of 1998, NSP filed wholesale electric point-to-point
and NTS rate cases with the FERC. The proposed point-to-point rates would,
if approved, increase third party transmission service revenue by
approximately $3 million and ancillary service revenues by $1 million,
annually. The NTS tariff change would, if approved, reduce NTS costs from
1997 levels. During April 1998, the FERC voted to allow the proposed
increases in point-to-point and ancillary service rates effective Oct. 1,
1998, subject to refund, and to consolidate the cases. In late 1998, NSP
reached a settlement in principle with the parties to the case. The
settlement is expected to be filed in the first quarter of 1999 and is
subject to FERC approval.
33
- In June 1998, Viking filed a rate case with the FERC, requesting a $3
million annual rate increase. In December 1998, Viking arrived at a
settlement in principle with parties to the case. The final settlement
will be filed in the first quarter of 1999 and is subject to FERC
approval.
- In December 1998, NSP-Minnesota submitted a voluntary cost separation
filing with the MPUC, which outlines the method NSP proposes to use to
assign costs of its electric operations to business segments and state
jurisdictions. Because of changes and increased competition in the
electric industry, NSP wants to separate or "unbundle" its generation,
transmission and distribution costs. This filing does not propose to
change electric rates for any of NSP's customers in Minnesota. An
administrative law judge has been assigned to convene a technical
conference of interested parties to discuss the merits of NSP's cost
separation proposal. A report is expected to be issued in the second
quarter of 1999.
COMPETITION The Energy Policy Act of 1992 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.
In 1996, the FERC issued Orders No. 888 and 889 to foster competition in the
electric utility industry. These orders give competing wholesale suppliers the
ability to transmit electricity through a utility's transmission system. Order
No. 888 grants nondiscriminatory access to transmission service. Order No. 889
seeks to ensure a fair market by imposing standards of conduct on transmission
system owners, by requiring separation of the wholesale power supply - or
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 open access transmission tariff filings and compliance
filings with the FERC and believes it is taking the proper steps to comply with
the new rules as they become effective.
Some states have begun to allow retail customers to choose their electricity
supplier, and many other states are considering retail access proposals. The
Minnesota Legislature continues to study the issues, but has determined that
further study is necessary before any action can be taken. The PSCW revised its
restructuring plan, delaying the start of retail competition to 2002. The
Michigan Public Service Commission approved a plan to begin offering a choice of
suppliers to retail customers in selected markets in 1998. The timing of
regulatory actions regarding restructuring and their impact on NSP cannot be
predicted at this time and may be significant.
INDEPENDENT TRANSMISSION COMPANY (ITC) In April 1998, NSP announced its
intention to divest its electric transmission business to form an independent
company unaffiliated with the rest of its utility operations.
Several developments have occurred since this commitment was made.
- In April 1998, the 1997 Wisconsin Act 204 became law. Act 204 includes
provisions that require the PSCW to order a public utility that owns
transmission facilities in Wisconsin to transfer control of its
transmission acilities to an independent system operator (ISO) or
divest the public utility's interest in its transmission facilities to
an independent transmission owner (ITO) if the public utility has not
already transferred control to an ISO or divested to an ITO by June 30,
2000. Under certain circumstances, the PSCW has authority to waive
imposition of such an order on June 30, 2000. At Dec. 31, 1998, the net
book value of NSP-Wisconsin's transmission assets was approximately
$148 million.
- In November 1998, NSP and Alliant Energy (Alliant) announced plans to
develop an ITC to provide transmission services to the Upper Midwest. The
two companies are developing a relationship by which NSP will create an
ITC, which will lease the transmission assets of Alliant. Lease terms have
not been finalized. The ITC is intended to be a publicly traded entity and
not an affiliate of NSP or Alliant. NSP and Alliant plan to seek the
necessary approvals from state and federal regulators in 1999, with the
ITC proposed to be operational in 2000.
- In November 1998, the members of Mid-Continent Area Power Pool (MAPP)
rejected a proposal to establish a MAPP ISO. In December 1998, Minnesota
Power Company (MP) filed a complaint with the FERC, alleging that NSP
violated its duty in a settlement agreement to work cooperatively to form
an ISO by voting against the MAPP ISO. MP also wants NSP's transmission
rate structure to be declared unreasonably discriminatory. MP is
requesting the FERC to order NSP to join the newly formed Midwest ISO, or
to order NSP to charge the Midwest ISO regional rate and to revoke NSP's
market rate authority.
- Due to the need for regulatory approval and other factors outside NSP's
control, there is no guarantee that NSP will be successful in forming an
ITC, or that if an ITC is formed it will include Alliant. In the event
that NSP is successful in forming an ITC, NSP would ultimately divest its
electric transmission assets. At Dec. 31, 1998, the net book value of
NSP's transmission assets was approximately $647 million. If NSP is not
successful in forming an ITC, Act 204 currently would require the transfer
of control of NSP-Wisconsin's transmission assets to an ISO, unless a
waiver is granted.
INDEPENDENT NUCLEAR GENERATING COMPANY In April 1998, NSP announced its
intention to divest its nuclear generation business to form an independent
company unaffiliated with the rest of its utility operations.
- During 1998, in the first step toward this commitment, NSP, Alliant, WEC
and Wisconsin Public Service Corp. agreed to form a cooperative nuclear
alliance to improve plant performance and reliability, strengthen
operational efficiency, maintain high safety levels and reduce costs.
Working teams are being organized to implement cooperative alliances in
several areas, including: fuel management, Year 2000 initiatives,
inventory management, information exchange and self-assessment programs.
The four companies operate seven nuclear units at five sites with a total
generation capacity exceeding 3,650 megawatts.
34
- NSP continues to work with regulators and potential business partners
toward the divestiture of its nuclear generation business. At Dec. 31,
1998, the net book value of NSP's nuclear assets (excluding
decommissioning investments and obligations) was approximately $737
million.
ENERGY MARKETING In April 1998, NSP announced an initiative to expand its
wholesale energy marketing efforts by formally establishing an Energy Marketing
division within NSP's Generation business unit. During 1998, Energy Marketing:
- Established a comprehensive risk management program. Since electricity
cannot be stored, there is potential for extreme price volatility. Strict
risk management is an integral element of Energy Marketing's business
activity.
- Led the development of the Minneapolis Grain Exchange (MGE) electricity
futures and option contracts. The MGE contracts provide NSP and the region
an opportunity to hedge against the price volatility inherent in the
electric market.
- Obtained market-based rate approval from the FERC in June 1998. This
enables Energy Marketing to sell energy at market prices in addition to
selling under traditional cost-based rates.
- Expanded the scale of NSP's electric sales for resale, increasing sales
volume by approximately 35 percent.
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 NSP's Prairie Island nuclear generating facility. Through
the use of longer fuel cycles and utilization of temporary storage racks in the
spent fuel pools, NSP 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). NSP had loaded seven of the casks as of Dec.
31, 1998. As a condition of the authorization, the Minnesota Legislature
established several resource commitments for NSP, including wind and biomass
generation sources as well as other requirements. NSP is complying with these
requirements. The MEQB has terminated an alternative siting process, which had
been one of the original legislative requirements.
NSP and other utilities have an ongoing dispute with the U.S. Department of
Energy (DOE) regarding the DOE's statutory and contractual obligations to
provide permanent storage and disposal facilities for nuclear fuel by Jan. 31,
1998, as required by the Nuclear Waste Policy Act of 1982. (See Notes 13 and 14
to the Financial Statements for more information.)
YEAR 2000 (Y2K) READINESS To the extent allowed, the information in the
following section is designated as a "Year 2000 Readiness Disclosure." NSP is
incurring 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 Y2K. A committee made up of senior management is
leading NSP's initiatives to identify Y2K related issues and remediate business
processes as necessary.
NSP's Y2K program covers not only NSP's 2,000 computer applications, consisting
of about 75,000 programs and totaling more than 30 million lines of code, but
also the thousands of hardware and embedded system components in use throughout
NSP. Embedded systems perform mission-critical functions in all parts of
operations, including power generation, transmission, distribution,
communications and business operations. NSP has implemented a Y2K methodology
consistent with state-of-the-art best practices and standards within the utility
industry. This seven-step process includes:
- Discovery of possible date-related logic in components, systems
and processes
- Assessment of potential problems
- Development of a plan to address the problem
- Remediation to resolve the problem
- Testing to verify that the solutions are workable
- Implementation of the solution into production
- Closure through retesting and documentation and review by a separate
internal due diligence committee
NSP's timetable for Y2K completion is:
- As of Dec. 31, 1998, 70 percent of NSP's mission-critical systems and
processes were Y2K ready.
- By March 31, 1999, completion of all Y2K efforts on 90 percent of
mission-critical systems and processes.
- By June 30, 1999, completion of all Y2K efforts on mission-critical
systems and processes, completion of all nuclear plant remediation in
accordance with Nuclear Regulatory Commission guidelines and finalization
of all contingency planning.
- By Dec. 31, 1999, complete remediation of low-priority applications,
complete all testing and implementation, and final closure.
NSP is communicating with its key suppliers and business partners regarding
their Y2K progress, particularly in software and embedded component areas, to
determine the areas in which NSP's operations may be vulnerable to those
parties' failure to complete their remediation efforts. NSP is currently
evaluating and initiating follow-up actions regarding the responses from these
parties as appropriate. NSP is also working closely with the Electric Power
Research Institute, MAPP, the Nuclear Energy Institute, the North American
Electric Reliability Council (NERC) and other utilities to enhance coordination,
system reliability and compliance with industry and regulatory requirements. In
its fourth quarter 1998 report, NERC stated, "findings continue to indicate that
transition through critical Y2K dates is expected to have minimal impact on
electric operations in North America."
NSP has made significant progress implementing its Y2K plan. Based upon the
information currently known regarding its internal operations and assuming
successful and timely completion of its remediation plan, NSP does not
anticipate significant business disruptions from its internal systems due to the
Y2K issue. However, NSP may possibly experience limited interruptions to some
aspects of its activities, relating to information technology, operations and
administrative functions. NSP is considering such potential occurrences in
planning for its most reasonably likely worst case scenarios.
In addition, risk exists regarding the noncompliance of third parties with
key business or operational importance to NSP. Y2K problems affecting key
customers, interconnected utilities, fuel suppliers and transporters,
telecommunications providers or financial institutions could result in lost
power or gas sales, reductions in power production or transmission, or
internal functional and administrative difficulties on the part of NSP. NSP
is not presently aware of any such situations; however, occurrences of this
type, if severe, could have material adverse impacts upon the business,
operating results or financial condition of NSP. Consequently, there can be
no assurance that NSP will be able to identify and correct all aspects of the
Y2K problem that affect it in sufficient time, or that the costs of achieving
Y2K readiness will not be material.
35
NSP is currently updating contingency plans for all material Y2K risk and is
on track to meet the contingency planning schedule set forth by NERC. Among
the areas contingency planning will address are delays in completion of NSP's
remediation plans, failure or incomplete remediation results and failure of
key third party contacts to be Y2K compliant.
Through 1998, NSP had spent approximately $13.1 million for Y2K efforts, which
primarily is expensed as incurred. The additional development and remediation
costs necessary for NSP to prepare for Y2K is estimated to be approximately
$11.3 million.
ENVIRONMENTAL MATTERS NSP incurs several types of environmental costs, including
nuclear plant decommissioning, storage and ultimate disposal of spent nuclear
fuel, disposal of hazardous materials and wastes, remediation of contaminated
sites and monitoring of discharges into the environment. Because of greater
environmental awareness and increasingly stringent regulation, NSP has
experienced 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 spent nuclear fuel disposal expenses,
costs charged to NSP's operating expenses for environmental monitoring and
disposal of hazardous materials and wastes were approximately:
- $32 million in 1998
- $31 million in 1997
- $31 million in 1996
NSP expects to average approximately $34 million per year for the five-year
period 1999-2003. However, the precise timing and amount of environmental costs,
including those for site remediation and disposal of hazardous materials, are
currently unknown.
Capital expenditures on environmental improvements at its utility facilities,
which include the costs of constructing spent nuclear fuel storage casks, were
approximately:
- $21 million in 1998
- $19 million in 1997
- $10 million in 1996
NSP expects to incur approximately $32 million in capital expenditures for
compliance with environmental regulations in 1999 and approximately $100 million
for the five-year period 1999-2003.
(See Notes 13 and 14 to the Financial Statements for further discussion of these
and other environmental contingencies.)
WEATHER NSP's earnings can be significantly affected by unusual weather.
Very hot summers and very cold winters increase electric and gas sales.
Unseasonably mild weather reduces electric and gas sales. The following
summarizes the estimated impact on NSP's earnings due to temperature variations
from historical averages.
- Weather in 1998 decreased earnings by an estimated 11 cents per share
- Weather in 1997 decreased earnings by an estimated 6 cents per share
- Weather in 1996 increased earnings by an estimated 8 cents per share
IMPACT OF NONREGULATED INVESTMENTS A significant portion of NSP's earnings comes
from nonregulated operations. NSP expects to continue investing in nonregulated
projects, including domestic and international power production projects through
NRG. The nonregulated projects in which NSP or its subsidiaries have invested
and may invest in the future carry a higher level of risk than NSP's traditional
utility businesses due to a number of factors, including:
- competition, operating risks, dependence on certain suppliers and
customers and domestic and foreign environmental and energy regulations;
- partnership and government actions and foreign government, political,
economic and currency risks; and
- development risks, including uncertainties prior to final legal closing.
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.
USE OF DERIVATIVES AND MARKET RISK NSP uses derivative financial instruments to
mitigate the impact of changes in: foreign currency exchange rates on NRG's
international project cash flows, natural gas prices on EMI's margins,
electricity prices on Energy Marketing's margins and interest rates on the cost
of borrowing.
The fair value of NRG's foreign currency contracts is sensitive to market risk
as a result of changes in foreign currency exchange rates. As of Dec. 31, 1998,
a 10 percent appreciation in foreign exchange rates from prevailing market rates
would decrease the market value of NRG's foreign currency contracts by
approximately $0.3 million. Conversely, a 10 percent depreciation in these
currencies from the prevailing market rates would increase the market value by
approximately $0.3 million.
EMI is exposed to market risk through changes in market prices of natural gas
forward and futures contracts. As of Dec. 31, 1998, a 10 percent increase in
natural gas forward and futures prices would result in a gain on these contracts
of approximately $0.5 million. Conversely, a 10 percent decrease in natural gas
forward and futures prices would result in a loss on these contracts of
approximately $0.5 million. These hypothetical gains and losses on natural gas
forward and futures contracts would be offset by the gains and losses on the
underlying commodities being hedged.
NSP's Energy Marketing division is exposed to market risk of changes in market
prices of electricity. The market risk of these energy futures contracts is
immaterial.
Market risk associated with NSP's interest rate swap agreement results from
short-term interest rate fluctuations. This market risk is not material since
this swap expired on Feb. 1, 1999. (See Notes 1 and 11 to the Financial
Statements for further discussion of NSP's financial instruments and
derivatives.)
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.)
36
In June 1998, the FASB issued Statement of Financial Accounting Standards (SFAS)
No. 133 - Accounting for Derivative Instruments and Hedging Activities. This
statement requires that all derivatives be recognized at fair value in the
balance sheet and all changes in fair value be recognized currently in earnings
or deferred as a component of other comprehensive income, depending on the
intended use of the derivative, its resulting designation and its effectiveness.
NSP is required to adopt this standard in 2000, but can elect to adopt it
earlier. NSP has not determined the potential impact of implementing this
statement or its expected adoption date.
INFLATION Inflation at its current level is not expected to materially affect
NSP's prices or returns to shareholders.
LIQUIDITY AND CAPITAL RESOURCES
1998 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. In 1998:
- Total utility capital expenditures (including AFC) were $411 million.
- Of that amount, $332 million related to replacements and improvements of
NSP's electric system and nuclear fuel, and $49 million involved
construction of natural gas facilities, including Viking.
- NSP companies (mainly NRG and Eloigne) invested approximately $279 million
for equity interests in and loans to nonregulated projects, for the
acquisition of existing businesses and for additions to nonregulated
property.
1998 FINANCING ACTIVITY During 1998, NSP's sources of capital included
internally generated funds and external financings. The allocation of financing
requirements between these capital resources is based on the relative cost of
each resource, regulatory restrictions and NSP's long-range capital structure
objectives. A capital structure consisting of 47.3 percent common equity at
year-end 1998 contributes to NSP's financial flexibility and strength. The
following summarizes the financing sources used in 1998.
- Internal funds - Funds generated internally from operating cash flows in
1998 remained sufficient to meet working capital needs, debt service,
dividend payout requirements and construction expenditures, as well as to
fund a significant portion of nonregulated investment commitments. NSP's
stated goal for its pretax interest coverage ratio for utility operations
is 3.5-5.0. The utility pretax interest coverage ratio, excluding AFC, was
3.8 in 1998, 3.6 in 1997 and 4.4 in 1996, which falls within the range.
Internally generated funds from utility operations could have provided
financing for more than 100 percent of NSP's utility capital expenditures
for 1998 and approximately 93 percent of the $2.0 billion in utility
capital expenditures incurred for the five-year period 1994-1998. The
pretax interest coverage ratio, excluding AFC, for all NSP operations was
2.9 in 1998, 2.8 in 1997 and 3.7 in 1996.
- External financing - NSP's short-term debt availability and usage is
described in Note 2 to the Financial Statements. In general, short-term
borrowings are used to provide temporary financing, mainly for
NSP-Minnesota and NRG, for utility capital expenditures, nonregulated
projects and other short-term cash needs. NSP's long-term debt and capital
stock activity are shown on the Statements of Capitalization and
Stockholders' Equity. These sources are used to provide permanent
financing for both regulated and nonregulated business activities. In
addition to funding current year capital needs, external financing
activities also reflect NSP's management of its capital structure to
maintain desired capitalization ratios.
NSP's 1998 nonregulated construction expenditures and equity investments
in nonregulated projects were primarily financed through internally generated
funds and the issuance of debt by nonregulated subsidiaries. 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.
FUTURE FINANCING REQUIREMENTS NSP currently estimates that its utility capital
expenditures will be $450 million in 1999 and $2.1 billion for the five-year
period 1999-2003. Of the 1999 amount, approximately $369 million is scheduled
for electric utility facilities and approximately $69 million for natural gas
facilities, including Viking. In addition to utility capital expenditures,
expected financing requirements for the five-year period 1999-2003 include
approximately $825 million to retire long-term debt and fund principal
maturities.
If NSP carries out its game plan to divest transmission and nuclear generation
assets, capital expenditures would be significantly lower. Another game plan
item, expansion of NSP's utility distribution, includes possible business
combinations that may require substantial issuance of capital.
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. Potential capital
requirements for nonregulated projects and property, which include acquisitions
and project investments, are estimated to be approximately $1.3 billion in 1999
and approximately $1.7 billion for the five-year period 1999-2003. The 1999
nonregulated capital requirements reflect NRG's expected acquisitions of
existing generation facilities, including: Arthur Kill, Astoria, Somerset,
Dunkirk, Huntley and Encina. A significant portion of these capital requirements
is expected to be financed by nonrecourse project debt.
37
NSP and its subsidiaries continue 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 financing may be
required for such investments.
NSP 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 meet future financing requirements by
periodically issuing long-term debt, short-term debt, common stock and preferred
securities to maintain desired capitalization ratios. Over the long term, NSP's
equity investments in and acquisitions of 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 partners, are expected to be
fulfilled through project or subsidiary debt. Decommissioning expenses not
funded by an external trust are expected to be financed through a combination of
internally generated funds, long-term debt and common stock. The extent of
external financing to be required for nuclear decommissioning costs is unknown
at this time.
The following summarizes the financing sources expected to be available to NSP
in the near future:
- Internal funds - Internally generated funds from utility operations are
expected to equal approximately 80 percent of anticipated utility capital
expenditures for 1999 and approximately 85 percent of the $2.1 billion in
anticipated utility capital expenditures for the five-year period
1999-2003. Because NRG 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.
- Short-term debt - NSP's board of directors has approved short-term
borrowing levels up to 10 percent of capitalization. NSP has received
regulatory approval for up to $604 million in short-term borrowing levels
and plans to keep its credit lines at or above its average level of
commercial paper borrowings. NSP credit lines (as discussed in Note 2 to
the Financial Statements) make short-term financing available in the form
of bank loans, letters of credit and support for commercial paper for
utility operations.
- Long-term debt - NSP-Minnesota's and NSP-Wisconsin'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, 1998, with an assumed interest rate of 6.25 percent, NSP-Minnesota
could have issued about $2.4 billion of additional first mortgage bonds
under its indenture and NSP-Wisconsin could have issued about $326 million
of additional first mortgage bonds under its indenture. In November 1998,
NSP filed with the SEC a $400 million universal debt shelf registration.
NSP currently has $50 million of registered, but unissued, bonds remaining
from its $300 million first mortgage bond shelf registration, which was
filed in October 1995. Depending on market conditions, NSP expects to
issue the bonds to raise additional capital for general corporate purposes
or to redeem or retire outstanding securities. In 1999, NRG anticipates
issuing approximately $300 million of corporate debt to finance several
acquisitions that are expected to close during the year.
- Common stock - NSP's Articles of Incorporation authorize an additional
197.3 million shares of common stock in excess of shares issued at Dec.
31, 1998. In 1996, NSP 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 NSP's Dividend Reinvestment and Stock Purchase Program (DRSPP)
and Executive Long-term Incentive Award Stock Plan. NSP may issue new
shares or purchase shares on the open market for its stock-based plans.
(See Note 4 to the Financial Statements for discussion of stock awards
outstanding.) NSP plans to issue new shares for its DRSPP, Employee Stock
Ownership Plan (ESOP) and Executive Long-term Incentive Award Stock Plans
in 1999. Also, NSP may consider a general common stock offering in 1999,
depending on corporate needs and opportunities.
- Preferred stock - NSP's Articles of Incorporation authorize the maximum
amount of preferred stock that may be issued. Under these provisions, NSP
could have issued all $595 million of its remaining authorized, but
unissued, preferred stock at Dec. 31, 1998, and remained in compliance
with all interest and dividend coverage requirements.
38
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- - -------------------------------------------------------------------------------
See Management's Discussion and Analysis under Item 7, incorporated by
reference.
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- - -------------------------------------------------------------------------------
See Item 14(a)-1 in Part IV for index of financial statements included herein.
See Note 16 of Notes to Financial Statements for summarized quarterly financial
data.
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE SHAREHOLDERS OF NORTHERN STATES POWER COMPANY:
In our opinion, the accompanying consolidated balance sheets and statements of
capitalization and the related consolidated statements of income, of common
stockholders' equity and of cash flows present fairly, in all material respects,
the financial position of Northern States Power Company (NSP), a Minnesota
corporation, and its subsidiaries at Dec. 31, 1998 and 1997, and the results of
their operations and their cash flows for each of the three years in the period
ended Dec. 31, 1998, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of NSP'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/
PRICEWATERHOUSECOOPERS LLP
MINNEAPOLIS, MINNESOTA
FEB. 1, 1999
39
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA) 1998 1997 1996
- - -----------------------------------------------------------------------------------------------------------------------------
UTILITY OPERATING REVENUES
Electric: Retail $2 145 548 $2 052 288 $1 985 923
Sales for resale and other 216 803 166 262 141 490
Gas 456 823 515 196 526 793
- - -----------------------------------------------------------------------------------------------------------------------------
Total 2 819 174 2 733 746 2 654 206
- - -----------------------------------------------------------------------------------------------------------------------------
UTILITY OPERATING EXPENSES
Fuel for electric generation 311 368 309 999 301 201
Purchased and interchange power 377 907 286 239 243 562
Cost of gas purchased and transported 267 050 331 296 335 453
Other operation 392 054 368 545 333 010
Maintenance 181 066 164 542 155 830
Administrative and general 150 078 141 802 148 656
Conservation and energy management 71 134 70 939 69 784
Depreciation and amortization 338 225 325 880 306 432
Property and general taxes 220 620 227 893 232 824
Income taxes 145 383 144 855 161 410
- - -----------------------------------------------------------------------------------------------------------------------------
Total 2 454 885 2 371 990 2 288 162
- - -----------------------------------------------------------------------------------------------------------------------------
Utility operating income 364 289 361 756 366 044
- - -----------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Income from nonregulated businesses - before interest and taxes 51 171 12 078 18 543
Allowance for funds used during construction - equity 8 509 6 401 7 595
Merger costs (29 005)
Other utility income (deductions) - net (3 697) (2 886) (1 544)
Income taxes on nonregulated operations and nonoperating items - benefit 40 588 48 145 14 600
- - -----------------------------------------------------------------------------------------------------------------------------
Total 96 571 34 733 39 194
- - -----------------------------------------------------------------------------------------------------------------------------
Income before financing costs 460 860 396 489 405 238
- - -----------------------------------------------------------------------------------------------------------------------------
FINANCING COSTS
Interest on utility long-term debt 104 171 101 250 101 177
Other utility interest and amortization 11 612 19 063 21 950
Nonregulated interest and amortization 54 261 34 627 18 834
Allowance for funds used during construction - debt (7 307) (10 208) (11 262)
- - -----------------------------------------------------------------------------------------------------------------------------
Total interest charges 162 737 144 732 130 699
Distributions on redeemable preferred securities of subsidiary trust 15 750 14 437
- - -----------------------------------------------------------------------------------------------------------------------------
Total financing costs 178 487 159 169 130 699
- - -----------------------------------------------------------------------------------------------------------------------------
NET INCOME 282 373 237 320 274 539
Preferred stock dividends and redemption premiums 5 548 11 071 12 245
- - -----------------------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON STOCK $ 276 825 $ 226 249 $ 262 294
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
Average number of common shares outstanding (000's) 150 502 140 594 137 121
Average number of common and potentially dilutive shares outstanding (000's) 150 743 140 870 137 358
EARNINGS PER AVERAGE COMMON SHARE - BASIC $ 1.84 $ 1.61 $ 1.91
EARNINGS PER AVERAGE COMMON SHARE - DILUTED $ 1.84 $ 1.61 $ 1.91
Common dividends declared per share $ 1.4250 $ 1.4025 $ 1.3725
- - -----------------------------------------------------------------------------------------------------------------------------
SEE NOTES TO FINANCIAL STATEMENTS
40
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31
(THOUSANDS OF DOLLARS) 1998 1997 1996
- - -----------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $282 373 $237 320 $274 539
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization 379 397 358 928 335 605
Nuclear fuel amortization 43 816 40 015 45 774
Deferred income taxes (1 017) (5 902) (30 561)
Deferred investment tax credits recognized (9 432) (10 061) (9 352)
Allowance for funds used during construction - equity (8 509) (6 401) (7 595)
Undistributed equity in earnings of unconsolidated affiliates (22 753) (5 364) (25 976)
Write-off of prior year merger costs 25 289
Cash provided by (used for) changes in certain working capital
items (see below) (13 673) 36 117 (58 634)
Cash provided by changes in other assets and liabilities 51 863 19 844 20 664
- - -----------------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 702 065 689 785 544 464
- - -----------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures:
Utility plant additions (including nuclear fuel) (411 113) (396 605) (386 655)
Additions to nonregulated property (44 918) (35 928) (25 807)
Increase (decrease) in construction payables 5 270 2 563 (3 716)
Allowance for funds used during construction - equity 8 509 6 401 7 595
Investment in external decommissioning fund (41 360) (41 261) (40 497)
Equity investments, loans and deposits for nonregulated projects (234 214) (395 495) (299 173)
Collection of loans made to nonregulated projects 109 530 87 128 116 126
Business acquisitions (159 600)
Other investments - net 1 307 (15 692) (15 873)
- - -----------------------------------------------------------------------------------------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES (606 989) (948 489) (648 000)
- - -----------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Change in short-term debt - net issuances (repayments) (20 522) (108 023) 152 173
Proceeds from issuance of long-term debt - net 290 626 299 779 197 824
Repayment of long-term debt, including reacquisition premiums (135 183) (141 681) (67 628)
Proceeds from issuance of preferred securities - net 193 315
Proceeds from issuance of common stock - net 72 348 267 965 41 725
Redemption of preferred stock, including reacquisition premiums (95 000) (41 278)
Dividends paid (219 746) (207 726) (198 234)
- - -----------------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED FOR) FINANCING ACTIVITIES (107 477) 262 351 125 860
- - -----------------------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (12 401) 3 647 22 324
Cash and cash equivalents at beginning of period 54 765 51 118 28 794
- - -----------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 42 364 $ 54 765 $ 51 118
- - -----------------------------------------------------------------------------------------------------------------------------
CASH PROVIDED BY (USED FOR) CHANGES IN CERTAIN WORKING CAPITAL ITEMS
Customer accounts receivable and unbilled utility revenues $ (1 583) $ 47 745 $ (31 925)
Federal income tax and other receivables (19 853) 133 (9 570)
Materials and supplies inventories (5 385) (8 547) (9 891)
Payables and accrued liabilities (excluding construction payables) 7 845 (7 342) 1 179
Other 5 303 4 128 (8 427)
- - -----------------------------------------------------------------------------------------------------------------------------
NET $ (13 673) $ 36 117 $ (58 634)
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest (net of amount capitalized) $220 424 $144 062 $121 697
Income taxes (net of refunds received) $ 74 005 $113 009 $165 146
- - -----------------------------------------------------------------------------------------------------------------------------
SEE NOTES TO FINANCIAL STATEMENTS
41
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
(THOUSANDS OF DOLLARS) 1998 1997
- - -----------------------------------------------------------------------------------------------------------------------------
ASSETS
UTILITY PLANT
Electric - including construction work in progress: 1998, $120,095; 1997, $92,302 $7 199 843 $6 964 888
Gas 884 182 821 119
Other 365 101 343 950
- - -----------------------------------------------------------------------------------------------------------------------------
Total 8 449 126 8 129 957
Accumulated provision for depreciation (4 155 641) (3 868 810)
Nuclear fuel - including amounts in process: 1998, $16,744; 1997, $23,381 975 030 932 335
Accumulated provision for amortization (873 281) (832 162)
- - -----------------------------------------------------------------------------------------------------------------------------
Net utility plant 4 395 234 4 361 320
- - -----------------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 42 364 54 765
Customer accounts receivable - net of accumulated provisions
for uncollectible accounts: 1998, $5,176; 1997, $10,406 253 559 269 455
Unbilled utility revenues 139 098 121 619
Notes receivable from nonregulated projects 4 460 55 787
Other receivables 100 656 80 803
Materials and supplies inventories - at average cost:
Fuel 58 806 56 434
Other 110 267 107 254
Prepayments and other 44 855 55 674
- - -----------------------------------------------------------------------------------------------------------------------------
Total current assets 754 065 801 791
- - -----------------------------------------------------------------------------------------------------------------------------
OTHER ASSETS
Equity investments in nonregulated projects 862 596 740 734
External decommissioning fund and other investments 479 402 400 290
Regulatory assets 331 940 340 122
Nonregulated property - net of accumulated depreciation: 1998, $122,445; 1997, $105,526 282 524 256 726
Notes receivable from nonregulated projects 106 427 77 639
Other long-term receivables 29 796 42 600
Long-term prepayments and deferred charges 58 398 30 015
Intangible assets - net of accumulated amortization 95 915 92 829
- - -----------------------------------------------------------------------------------------------------------------------------
Total other assets 2 246 998 1 980 955
- - -----------------------------------------------------------------------------------------------------------------------------
TOTAL $7 396 297 $7 144 066
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND EQUITY
CAPITALIZATION (SEE CONSOLIDATED STATEMENTS OF CAPITALIZATION)
Common stockholders' equity $2 481 246 $2 371 728
Preferred stockholders' equity 105 340 200 340
Mandatorily redeemable preferred securities of subsidiary trust 200 000 200 000
Long-term debt 1 851 146 1 878 875
- - -----------------------------------------------------------------------------------------------------------------------------
Total capitalization 4 637 732 4 650 943
- - -----------------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year 227 600 22 820
Other long-term debt potentially due within one year 141 600 141 600
Short-term debt 239 830 260 352
Accounts payable 271 799 249 813
Taxes accrued 170 274 186 369
Interest accrued 38 836 28 724
Dividends payable on common and preferred stocks 55 650 54 778
Accrued payroll, vacation and other 86 673 89 562
- - -----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1 232 262 1 034 018
- - -----------------------------------------------------------------------------------------------------------------------------
OTHER LIABILITIES
Deferred income taxes 814 983 792 569
Deferred investment tax credits 128 444 138 509
Regulatory liabilities 372 239 305 765
Postretirement and other benefit obligations 129 514 135 612
Other long-term obligations and deferred income 81 123 86 650
- - -----------------------------------------------------------------------------------------------------------------------------
Total other liabilities 1 526 303 1 459 105
- - -----------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENT LIABILITIES (SEE NOTES 13 AND 14)
- - -----------------------------------------------------------------------------------------------------------------------------
TOTAL $7 396 297 $7 144 066
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
SEE NOTES TO FINANCIAL STATEMENTS
42
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
ACCUMULATED
OTHER TOTAL
RETAINED SHARES HELD COMPREHENSIVE STOCKHOLDERS'
(THOUSANDS OF DOLLARS) PAR VALUE PREMIUM EARNINGS BY ESOP INCOME EQUITY
- - -----------------------------------------------------------------------------------------------------------------------------------
Balance at Dec. 31, 1995
(as previously reported) $170 440 $599 094 $1 266 026 $(10 657) $ 2 488 $2 027 391
Restatement for June 1, 1998
two-for-one stock split 170 440 (170 440)
- - -----------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DEC. 31, 1995 (AS RESTATED) $340 880 $428 654 $1 266 026 $(10 657) $ 2 488 $2 027 391
- - -----------------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------------
Net income 274 539 274 539
Currency translation adjustments 306 306
--------
--------
Comprehensive income for 1996 274 845
Dividends declared:
Cumulative preferred stock (12 245) (12 245)
Common stock (187 521) (187 521)
Issuances of common stock - net 4 438 37 037 41 475
Tax benefit from stock options exercised 369 369
Loan to ESOP to purchase shares* (15 000) (15 000)
Repayment of ESOP loan* 6 566 6 566
- - -----------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DEC. 31, 1996 $345 318 $466 060 $1 340 799 $(19 091) $ 2 794 $2 135 880
- - -----------------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------------
Net income 237 320 237 320
Currency translation adjustments (65 681) (65 681)
--------
--------
Comprehensive income for 1997 171 639
Dividends declared:
Cumulative preferred stock (9 923) (9 923)
Common stock (202 173) (202 173)
Premium on redeemed preferred stock (1 148) (1 148)
Issuances of common stock - net 27 774 240 112 267 886
Tax benefit from stock options exercised 1 009 1 009
Repayment of ESOP loan* 8 558 8 558
- - -----------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DEC. 31, 1997 $373 092 $707 181 $1 364 875 $(10 533) $(62 887) $2 371 728
- - -----------------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------------
Net income 282 373 282 373
Unrealized loss from marketable
securities, net of income tax of $4,417 (6 416) (6 416)
Currency translation adjustments (19 711) (19 711)
--------
--------
Comprehensive income for 1998 256 246
Dividends declared:
Cumulative preferred stock (5 548) (5 548)
Common stock (215 069) (215 069)
Issuances of common stock - net 8 650 66 294 74 944
Retained earnings of acquired businesses 6 065 6 065
Tax benefit from stock options exercised 850 850
Loan to ESOP to purchase shares* (15 000) (15 000)
Repayment of ESOP loan* 7 030 7 030
- - -----------------------------------------------------------------------------------------------------------------------------------
BALANCE AT DEC. 31, 1998 $381 742 $774 325 $1 432 696 $(18 503) $(89 014) $2 481 246
- - -----------------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------------
* Did not affect NSP cash flows
SEE NOTES TO FINANCIAL STATEMENTS
43
CONSOLIDATED STATEMENTS OF CAPITALIZATION
DECEMBER 31
(THOUSANDS OF DOLLARS) 1998 1997
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
COMMON STOCKHOLDERS' EQUITY
Common stock - authorized 350,000,000 shares of $2.50 par value;
issued shares: 1998, 152,696,971; 1997, 149,236,764 $ 381 742 $ 373 092
Premium on common stock 774 325 707 181
Retained earnings 1 432 696 1 364 875
Leveraged common stock held by Employee Stock Ownership Plan (ESOP) -
shares at cost: 1998, 641,884; 1997, 460,506 (18 503) (10 533)
Accumulated other comprehensive income (89 014) (62 887)
- - -----------------------------------------------------------------------------------------------------------------------------
TOTAL COMMON STOCKHOLDERS' EQUITY $2 481 246 $2 371 728
- - -----------------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK - authorized 7,000,000 shares of $100 par value;
outstanding shares: 1998, 1,050,000; 1997, 2,000,000
NSP-Minnesota
$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
Variable Rate series A, 300,000 shares 30 000
Variable Rate series B, 650,000 shares 65 000
- - -----------------------------------------------------------------------------------------------------------------------------
Total 105 000 200 000
Premium on preferred stock 340 340
- - -----------------------------------------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCKHOLDERS' EQUITY $ 105 340 $ 200 340
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST - holding as its sole asset
junior sub-ordinated deferrable debentures of NSP-Minnesota 7 7/8% series, 8,000,000 shares,
due Jan. 31, 2037 (See Note 8) $ 200 000 $ 200 000
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT
First Mortgage Bonds - NSP-Minnesota
Series due:
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
Feb. 1, 2003, 7 1/2% 50 000
April 1, 2003, 6 3/8% 80 000 80 000
Dec. 1, 2005, 6 1/8% 70 000 70 000
Dec. 1, 1998-2006, 6.68% 16 900** 18 400**
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* 60 000*
March 1, 2019, Variable Rate 27 900* 27 900*
Sept. 1, 2019, Variable Rate 100 000* 100 000*
March 1, 2003, 5 7/8% 100 000
March 1, 2028, 6 1/2% 150 000
- - -----------------------------------------------------------------------------------------------------------------------------
Total 1 318 500 1 170 000
- - -----------------------------------------------------------------------------------------------------------------------------
Less redeemable bonds classified as current (See Note 3) (141 600) (141 600)
Less current maturities (201 600) (1 500)
- - -----------------------------------------------------------------------------------------------------------------------------
Net $ 975 300 $1 026 900
- - -----------------------------------------------------------------------------------------------------------------------------
* Pollution control financing
** Resource recovery financing
SEE NOTES TO FINANCIAL STATEMENTS
44
CONSOLIDATED STATEMENTS OF CAPITALIZATION
DECEMBER 31
(THOUSANDS OF DOLLARS) 1998 1997
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT - CONTINUED
First Mortgage Bonds - NSP-Wisconsin
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 - NSP-Minnesota
Series due:
Feb. 1, 1998-2003, 5.41% $ 5 100* $ 5 300*
May 1, 1998-2003, 5.70% 22 750* 23 250*
Feb. 1, 2003, 7.40% 3 500* 3 500*
- - -----------------------------------------------------------------------------------------------------------------------------
Total 31 350 32 050
Less current maturities (700) (700)
- - -----------------------------------------------------------------------------------------------------------------------------
Net $ 30 650 $ 31 350
- - -----------------------------------------------------------------------------------------------------------------------------
OTHER LONG-TERM DEBT
City of Becker Pollution Control Revenue Bonds - Series due
Dec. 1, 2005, 7.25% $ 9 000* $ 9 000*
Anoka County Resource Recovery Bond - Series due
Dec. 1, 1998-2008, 7.10% 20 600** 21 850**
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% 20 978 23 111
Nov. 30, 2011, 7.1% 4 650 5 010
Sept. 30, 2012, 7.31% 12 833 13 767
NRG Energy, Inc. Senior Notes - Series due
Feb. 1, 2006, 7.625% 125 000 125 000
June 15, 2007, 7.5% 250 000 250 000
NRG Energy Center, Inc. (Minneapolis Energy Center)
Senior Secured Notes - Series due June 15, 2013, 7.31% 71 783 74 481
Pacific Generation Company debt due 2000-2007, 4.7%-9.9% 28 586 33 424
Various NEO Corporation debt due Oct. 30, 2000, 6.9%-9.4% 17 792 5 618
United Power & Land Notes due
March 31, 2000, 7.62% 6 041 6 875
Black Mountain Gas Industrial Development Bond due
June 1, 2004, May 1, 2005, 6% 3 000
Various Eloigne Company Affordable Housing Project Notes due
1998-2024, 1.0%-9.9% 46 024 27 223
Employee Stock Ownership Plan Bank Loans due
1998-2005, Variable Rate 18 504 10 535
Miscellaneous 9 122 7 385
- - -----------------------------------------------------------------------------------------------------------------------------
Total 662 513 631 879
Less current maturities (25 300) (20 620)
- - -----------------------------------------------------------------------------------------------------------------------------
Net $ 637 213 $ 611 259
- - -----------------------------------------------------------------------------------------------------------------------------
Unamortized discount on long-term debt - net (7 017) (5 634)
- - -----------------------------------------------------------------------------------------------------------------------------
TOTAL LONG-TERM DEBT $1 851 146 $1 878 875
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION $4 637 732 $4 650 943
- - -----------------------------------------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------------------------------------
* Pollution control financing
** Resource recovery financing
SEE NOTES TO FINANCIAL STATEMENTS
45
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS NSP-Minnesota is primarily a public utility serving
customers in Minnesota, North Dakota, South Dakota and, since the merger with
Black Mountain Gas, Arizona. NSP-Wisconsin serves utility customers in
Wisconsin and Michigan. Viking operates a 500-mile interstate natural gas
pipeline. All of the utility companies' accounting records conform to the
Federal Energy Regulatory Commission (FERC) uniform system of accounts or to
systems required by various state regulatory commissions, which are the same
in all material aspects.
PRINCIPLES OF CONSOLIDATION The following wholly owned subsidiaries of
NSP-Minnesota are included in the consolidated financial statements. In this
report, we refer to these companies collectively as NSP.
- NSP-Wisconsin
- NRG Energy, Inc. (NRG)
- Viking Gas Transmission Co. (Viking)
- Energy Masters International, Inc. (EMI)
- Eloigne Co. (Eloigne)
- Seren Innovations, Inc. (Seren)
- Ultra Power Technologies, Inc. (Ultra Power)
NSP uses the equity method of accounting for its investments in partnerships,
joint ventures and certain projects, mainly at NRG and Eloigne. We record our
portion of earnings from international investments after subtracting foreign
income taxes. In the consolidation process, we eliminate all significant
intercompany transactions and balances except for intercompany and
intersegment profits for sales among the electric and gas utility businesses
of NSP-Minnesota, NSP-Wisconsin and Viking, which are allowed in utility
rates.
REVENUES NSP records utility revenues based on a calendar month, but reads
meters and bills customers according to a cycle that doesn't necessarily
correspond with the calendar month's end. To compensate, we estimate and
record unbilled revenues from the monthly meter-reading dates to the month's
end. NSP-Minnesota's rates include monthly adjustments for:
- changes in the average cost of fuel, including electricity and gas that
NSP purchases, from base levels approved in the most recent rate case
- conservation and energy management program costs in Minnesota
Because of a Public Service Commission of Wisconsin (PSCW) rule,
NSP-Wisconsin's rates include a cost-of-energy adjustment clause for
purchased gas, but not for purchased electricity or electric fuel. We can
recover those electric costs through the rate review process, which normally
occurs every two years in Wisconsin, and an interim fuel cost hearing process.
UTILITY PLANT AND RETIREMENTS Utility plant is stated at original cost. The
cost of utility plant includes direct labor and materials, contracted work,
overhead costs and applicable interest expense. The cost of utility plant
retired, plus net removal cost, is charged to accumulated 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,
represents the cost of capital used to finance utility construction activity.
AFC is computed by applying a composite pretax rate to qualified construction
work in progress. The AFC rate was 8.0 percent in 1998, 5.75 percent in 1997
and 5.5 percent in 1996. The amount of AFC capitalized as a construction cost
is credited to other income (for equity capital) and interest charges (for
debt capital). AFC amounts capitalized are included in NSP's 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 NSP determines the depreciation of its plant by spreading the
original cost equally over the plant's useful life. Every five years, NSP
submits an average service life filing to the Minnesota Public Utilities
Commission (MPUC) for electric and gas property. The most recent filing
occurred in 1997. Depreciation expense as a percentage of the average utility
plant in service was 3.77 percent in 1998, 3.78 percent in 1997 and 3.68
percent in 1996.
DECOMMISSIONING NSP accounts for the future cost of decommissioning - or
permanently retiring - its nuclear generating plants through annual
depreciation accruals using an annuity approach designed to provide for full
rate recovery of the future decommissioning costs. Our decommissioning
calculation covers all expenses, including decontamination and removal of
radioactive material, and extends over the estimated lives of the plants. The
calculation assumes that NSP will recover those costs through rates. (See
Note 13 for more information on decommissioning.)
NUCLEAR FUEL EXPENSE Nuclear fuel expense, which is expensed as the plant
uses fuel, includes the cost of:
- nuclear fuel used
- future nuclear fuel disposal, based on fees established by the U.S.
Department of Energy (DOE)
- NSP's portion of the cost of decommissioning or shutting down the
DOE's fuel enrichment facility
ENVIRONMENTAL COSTS We record environmental costs when it is probable that
NSP is liable for the costs and we can reasonably estimate the liability. We
may defer costs as a regulatory asset based on our expectation that we will
recover these costs from customers in future rates. Otherwise, we expense the
costs.
If an environmental expense is related to facilities we currently use, such
as pollution control equipment, we capitalize and depreciate the costs over
the life of the plant. We record estimated remediation costs, excluding
inflationary increases and possible reductions for insurance coverage and
rate recovery. The estimates are based on our experience, our assessment of
the current situation and the technology currently available to assist in the
remediation.
We regularly adjust the recorded costs as we revise estimates and as
remediation proceeds. If we are one of several designated responsible
parties, we estimate and record only our share of the cost. We treat any
future costs of restoring sites, where operation may extend indefinitely, as
a capitalized cost of plant retirement. The depreciation expense levels we
can recover in rates include a provision for these estimated removal costs.
INCOME TAXES Based on the liability method, NSP defers income taxes for all
temporary differences between pretax financial and taxable income and between
the book and tax bases of assets and liabilities.
We use the tax rates that are scheduled to be in effect when the temporary
differences are expected to turn around, or reverse.
Due to the effects of past regulatory practices, when deferred taxes were not
required to be recorded, we account for the reversal of some temporary
differences as current income tax expense. We defer investment tax credits
and spread their benefits over the estimated lives of the related property.
Utility rate regulation also has created certain regulatory assets and
liabilities related to income taxes, which we summarize in Note 9. We discuss
our income tax policy for international operations in Note 7.
46
FOREIGN CURRENCY TRANSLATION NSP's foreign operations generally use the local
currency as their functional currency in translating international operating
results and balances to U.S. currency. Foreign currency denominated assets
and liabilities are translated at the exchange rates in effect at the end of
a reporting period. Income, expense and cash flows are translated at weighted
average exchange rates for the period. We accumulate the resulting currency
translation adjustments and report them as a separate component of
stockholders' equity.
When we convert cash distributions made in one currency to another currency,
we include those gains and losses in the results of operations as a component
of income from nonregulated businesses before interest and taxes. We do the
same for foreign currency derivative arrangements that do not qualify for
hedge accounting.
DERIVATIVE FINANCIAL INSTRUMENTS To preserve the U.S. dollar value of
projected foreign currency cash flows, NRG hedges - or protects - those cash
flows if appropriate foreign hedging instruments are available. NRG hedges
foreign currency transactions by using forward foreign currency exchange
agreements with terms of less than one to three years. The gains and losses
on those agreements offset the effect of exchange rate fluctuations on NRG's
known and anticipated cash flows. NRG defers gains on agreements that hedge
firm commitments of cash flows, and accounts for them as part of the relevant
foreign currency transaction when the transaction occurs. NRG defers losses
on these agreements the same way, unless it appears that the deferral would
result in recognizing a loss later.
While NRG is not hedging investments involving foreign currency currently,
NRG will hedge such investments when it 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. Before July 1997, NRG hedged investments
involving foreign currency as they were made to preserve their U.S. dollar
value. Gains and losses on those agreements offset the effects of exchange
rate fluctuations on the value of the investments underlying the hedges. We
reported hedging gains and losses on those agreements, net of income tax
effects, with other currency translation adjustments as a separate component
of stockholders' equity.
From time to time NRG also uses interest rate hedging instruments to protect
against increases in the cost of borrowing at both the corporate and project
level. NRG defers gains and losses on interest rate hedging instruments,
which are included and reported as part of the underlying equity investments.
EMI uses natural gas future and forward contracts 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
operating expenses. In February 1999, EMI transferred its gas supply and
marketing function to NSP's Energy Marketing Division.
NSP's Energy Marketing Division uses future and forward contracts to manage
the risk of electric price fluctuations. The cost or benefit of futures or
forward contracts is recorded when related sales commitments are fulfilled as
a component of Energy Marketing's operating expenses. NSP does not speculate
in electric or natural gas futures.
A final derivative instrument used by NSP is interest rate swaps. 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. (For information on derivatives see Note 11.)
USE OF ESTIMATES In recording transactions and balances resulting from
business operations, NSP uses estimates based on the best information
available. We use estimates for such items as plant depreciable lives, tax
provisions, uncollectible amounts, environmental costs, unbilled revenues and
actuarially determined benefit costs.
We revise the recorded estimates when we get better information or when we
can determine actual amounts. Those revisions can affect operating results.
Each year, we also review the depreciable lives of certain plant assets and
revise them if appropriate.
CASH EQUIVALENTS NSP considers investments in certain debt instruments - with
a remaining maturity of three months or less at the time of purchase - to be
cash equivalents. Those debt instruments are primarily commercial paper and
money market funds.
REGULATORY DEFERRALS As regulated entities, NSP-Minnesota, NSP-Wisconsin and
Viking account for certain income and expense items using Statement of
Financial Accounting Standards (SFAS) No. 71 - Accounting for the Effects of
Regulation. Under SFAS No. 71:
- we defer certain costs, which would otherwise be charged to expense, as
regulatory assets based on our expected ability to recover them in
future rates
- we defer certain credits, which would otherwise be reflected as income,
as regulatory liabilities based on our expectation that they will be
returned to customers in future rates
We base our estimates of recovering deferred costs and returning deferred
credits on specific ratemaking decisions or precedent for each item. We
amortize regulatory assets and liabilities consistent with the period of
expected regulatory treatment.
STOCK-BASED EMPLOYEE COMPENSATION NSP has several stock-based compensation
plans, which are described in Note 4. NSP accounts for those plans using the
intrinsic value method. We do not record compensation expense for stock
options because there is no difference between the market price and the
purchase price at grant date. We do, however, record compensation expense for
restricted stock that NSP awards to certain employees, but holds until the
restrictions lapse or the stock is forfeited. We do not use the optional
accounting under SFAS No. 123 - Accounting for Stock-Based Compensation. If
we had used the SFAS No. 123 method of accounting, the reduction of earnings
for 1998, 1997 and 1996 would have been immaterial.
DEVELOPMENT COSTS As NRG develops projects, it expenses the development costs
it incurs until a sales agreement or letter of intent is signed and the
project has received NRG board approval. NRG capitalizes additional costs
incurred at that point as part of equity investments in projects. When a
project begins to operate, NRG amortizes the capitalized costs over either
the life of the project's related assets or the revenue contract period,
whichever is less.
INTANGIBLE ASSETS Goodwill results when NSP purchases an entity at a price
higher than the underlying fair value of the net assets. We amortize the
goodwill and other intangible assets over periods of up to 40 years. We
periodically evaluate the recovery of goodwill based on an analysis of
estimated undiscounted future cash flows. At Dec. 31, 1998, NSP's intangible
assets included $44 million of goodwill, net of accumulated amortization.
Intangible and other assets also included deferred financing costs, net of
amortization, of approximately $23 million at Dec. 31, 1998. We are
amortizing these financing costs over the remaining maturity period of the
related debt.
47
RECLASSIFICATIONS AND STOCK SPLIT We reclassified certain items in the 1996
and 1997 income statements to conform to the 1998 presentation. These
reclassifications had no effect on net income or earnings per share. In
addition, all financial information pertaining to per share amounts and
number of common shares outstanding has been adjusted to reflect a
two-for-one stock split effective June 1, 1998, for shareholders of record on
May 18, 1998.
2. SHORT-TERM BORROWINGS
Short-term debt outstanding at Dec. 31 consisted of:
(MILLIONS OF DOLLARS) 1998 1997
- - ---------------------------------------------------------------------------
Commercial paper borrowings $114 $138
Bank loans 126 122
- - ---------------------------------------------------------------------------
TOTAL SHORT-TERM DEBT $240 $260
- - ---------------------------------------------------------------------------
- - ---------------------------------------------------------------------------
Weighted average interest rate - Dec. 31 5.6% 6.2%
At the end of 1997 and 1998, NSP-Minnesota 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. NSP did not borrow or issue any letters of credit
against this facility in 1997 or 1998.
In addition, banks provided lines of credit to NSP wholly owned subsidiaries,
of $318 million at Dec. 31, 1998. The short-term bank loans listed previously
reduced the amounts available under these subsidiary credit lines. Also, $34
million of letters of subsidiary credit were outstanding at Dec. 31, 1998 (as
discussed in Note 11), which further reduced amounts available under the
lines.
3. LONG-TERM DEBT
Except for minor exclusions, all real and personal property of NSP-Minnesota
and NSP-Wisconsin is subject to the liens of the first mortgage indentures,
which are contracts between the companies and their bond holders. A lien on
the related real or personal property secures other debt securities, as we
indicate on the Consolidated Statements of Capitalization.
The annual sinking-fund requirements of NSP-Minnesota and NSP-Wisconsin'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:
- series issued for pollution control and resource recovery financings
- certain other series totaling $1 billion
NSP-Minnesota and NSP-Wisconsin may apply property additions in lieu of cash
for sinking fund requirements on all series, as permitted by their first
mortgage indenture.
NSP-Minnesota'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 4.3 percent
and 3.1 percent, respectively, at Dec. 31, 1998. The 2011 series bonds are
redeemable upon seven days notice at the option of the bondholder.
NSP-Minnesota 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 are:
1999 $227.8 million 2002 $ 24.0 million
2000 $127.9 million 2003 $273.5 million
2001 $172.0 million
4. COMMON STOCK AND INCENTIVE STOCK PLANS
NSP's Articles of Incorporation and first mortgage indenture include certain
restrictions on paying cash dividends on common stock. Even with these
restrictions, NSP could have paid more than $1.4 billion in additional cash
dividends on common stock at Dec. 31, 1998.
NSP grants nonqualified stock options and restricted stock under our
Executive Long-term Incentive Award Stock Plan. The awards granted in any
year cannot exceed 1 percent of the number of outstanding shares of NSP
common stock at the end of the previous year. When options are exercised or
when we grant restricted stock, we may either issue new shares or purchase
market shares.
The weighted average number of common and potentially dilutive shares
outstanding includes the dilutive effect of stock options and other stock
awards based on the treasury stock method. Stock options may be exercised
after one year from the option's grant date and no later than 10 years after
the grant date. Effective in January 1999, stock options granted to NSP
officers vest at a rate of one-third each year for three years.
Employees forfeit stock options if their employment ends before the one-year
vesting term. If employment ends after the one-year vesting term, employees
either forfeit their options or must redeem them within three to 36 months,
depending on their circumstances. If an employee retires, all options granted
in 1999 will vest immediately and can be exercised over their 10-year life.
The exercise price of an option is the market price of NSP stock on the date
of grant. The plan previously granted other types of performance awards, some
of which remain outstanding. Most of these performance awards were valued in
dollars, but paid in shares based on the market price at the time of payment.
The following table includes transactions that have occurred under the
various incentive stock programs, with the corresponding weighted average
exercise price:
STOCK OPTION AND PERFORMANCE AWARDS 1998 1997 1996
(THOUSANDS OF SHARES) SHARES AVERAGE PRICE SHARES AVERAGE PRICE SHARES AVERAGE PRICE
- - ------------------------------------------------------------------------------------------------------------------------------
Outstanding Jan. 1 2 206 $22.57 2 235 $21.99 1 980 $20.99
Options granted in January 572 $26.88 573 $23.72 526 $25.47
Options and awards exercised (346) $22.39 (520) $21.12 (210) $20.99
Options and awards forfeited (34) $26.48 (60) $23.60 (54) $23.85
Options and awards expired (9) $23.24 (22) $25.47 (7) $20.00
- - ------------------------------------------------------------------------------------------------------------------------------
OUTSTANDING AT DEC. 31 2 389 $23.57 2 206 $22.57 2 235 $21.99
- - ------------------------------------------------------------------------------------------------------------------------------
- - ------------------------------------------------------------------------------------------------------------------------------
EXERCISABLE AT DEC. 31 1 847 $23.34 1 685 $22.21 1 740 $20.98
- - ------------------------------------------------------------------------------------------------------------------------------
- - ------------------------------------------------------------------------------------------------------------------------------
48
The following table summarizes information about stock options outstanding at
Dec. 31, 1998:
RANGE OF EXERCISE PRICES
$16.63-20.47 $21.10-22.75 $23.72-26.88
- - -------------------------------------------------------------------------------
Options Outstanding:*
Number Outstanding
at Dec. 31, 1998 290 396 721 942 1 361 838
Weighted average remaining
contractual life (years) 2.2 5.2 8.1
Weighted average exercise price $18.66 $21.96 $25.47
Options Exercisable:*
Number Exercisable
at Dec. 31, 1998 290 396 721 942 819 904
Weighted average exercise price $18.66 $21.96 $24.54
- - -------------------------------------------------------------------------------
* THERE WERE ALSO 14,621 OTHER AWARDS OUTSTANDING AT DEC. 31, 1998.
In addition to granting stock options, NSP grants restricted stock based on a
Dollar value of the award. We use the market price of the stock on the date
it Was granted to determine the number of restricted shares to grant. NSP
holds the stock until restrictions lapse; 50 percent of the stock vests one
year from the date of the award and the other 50 percent vests two years from
the date of the award. To obtain additional shares, we reinvest dividends on
the shares we hold while restrictions are in place. Restrictions also apply
to the additional shares.
Over the last three years, NSP has granted the following restricted stock
awards:
- 1996: 37,168 shares
- 1997: 52,688 shares
- 1998: 49,651 shares
Compensation expense related to these awards was immaterial.
5. BENEFIT PLANS AND OTHER POSTRETIREMENT BENEFITS
NSP offers the following benefit plans to its benefit employees.
Approximately 38 percent of benefit employees 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 almost 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 of applicable employee benefit and tax
laws. Plan assets principally consist of the common stock of public
companies, corporate bonds and U.S. government securities.
POSTRETIREMENT HEALTH CARE NSP has a contributory health and welfare benefit
plan that provides health care and death benefits to almost all NSP Retirees.
The plan, which will terminate for nonbargaining employees retiring after
1998, enables NSP and retirees to share the costs of retiree health care for
those employees retiring prior to 1999. In 1994, NSP implemented a
cost-sharing strategy, with 1997 and 1998 nonbargaining retirees paying 40
percent of total health care costs. Cost-sharing for bargaining employees is
governed by the terms of NSP'S collective bargaining agreement.
In conjunction with the 1993 adoption of SFAS No. 106 - Employers' Accounting
for Postretirement Benefits Other Than Pensions, NSP elected to amortize the
unrecognized accumulated postretirement benefit obligation (APBO) on a
straight-line basis over 20 years.
NSP's regulators require significant levels of external funding for retiree
benefits, including the use of tax-advantaged trusts. Plan assets held in
such trusts principally consist of investments in equity mutual funds and
cash equivalents.
Regulators for almost all of NSP's retail and wholesale customers have
allowed full recovery of increased benefit costs under SFAS No. 106.
Minnesota and Wisconsin retail regulators require external funding to the
extent it is tax advantaged. Such funding began for Wisconsin in 1993 and for
Minnesota in 1998. For wholesale ratemaking, FERC requires external funding
for all benefits paid and accrued under SFAS No. 106.
RECONCILIATION OF FUNDED STATUS PENSION BENEFITS OTHER POSTRETIREMENT BENEFITS
(THOUSANDS OF DOLLARS) 1998 1997 1998 1997
- - -------------------------------------------------------------------------------------------------------------------
BENEFIT OBLIGATION AT JAN. 1 $ 1 048 251 $ 993 821 $ 279 230 $ 268 683
Service cost 31 643 27 680 3 247 5 095
Interest cost 78 839 72 651 15 896 18 872
Plan amendments 102 315 (51 456)
Actuarial (gain) loss (41 635) 30 431 (9 732) 2 164
Benefit payments (75 949) (76 332) (17 423) (15 584)
- - -------------------------------------------------------------------------------------------------------------------
BENEFIT OBLIGATION AT DEC. 31 $ 1 143 464 $ 1 048 251 $ 219 762 $ 279 230
- - -------------------------------------------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at Jan. 1 $ 1 978 538 $ 1 634 696 $ 19 783 $ 15 514
Actual return on plan assets 319 230 420 174 2 471 1 461
Employer contributions 29 683 18 392
Benefit payments (75 949) (76 332) (17 423) (15 584)
- - -------------------------------------------------------------------------------------------------------------------
FAIR VALUE OF PLAN ASSETS AT DEC. 31 $ 2 221 819 $ 1 978 538 $ 34 514 $ 19 783
- - -------------------------------------------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------------------------------------------
Funded status at Dec. 31 - net asset (obligation) $ 1 078 355 $ 930 287 $(185 248) $(259 447)
Unrecognized transition (asset) obligation (387) (463) 104 482 161 700
Unrecognized prior service cost 114 305 18 663 (2 399)
Unrecognized net (gain) loss (1 167 340) (953 825) 3 790 14 406
- - -------------------------------------------------------------------------------------------------------------------
NET AMOUNT RECOGNIZED - ASSET (LIABILITY) $ 24 933 $ (5 338) $ (79 375) $ (83 341)
- - -------------------------------------------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------------------------------------------
49
AMOUNT RECOGNIZED IN THE STATEMENT OF FINANCIAL POSITION PENSION BENEFITS OTHER POSTRETIREMENT BENEFITS
(THOUSANDS OF DOLLARS) 1998 1997 1998 1997
- - --------------------------------------------------------------------------------------------------------------------------
Prepaid benefit cost $24 933
Accrued benefit liability $(5 338) $(79 375) $(83 841)
- - --------------------------------------------------------------------------------------------------------------------------
Net amount recognized - asset (liability) $24 933 $(5 338) $(79 375) $(83 341)
- - --------------------------------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE ASSUMPTIONS USED IN BENEFIT CALCULATIONS
Discount rate at end of year 6.5% 7.0% 6.5% 7.0%
Expected return on plan assets for year 8.5% 9.0% 8.0% 8.0%
Rate of future compensation increase per year 4.5% 5.0% 4.5% 5.0%
Rate of future health care cost increase per year:
Next succeeding year - age 65 and older 6.1% 6.8%
Next succeeding year - under age 65 8.1% 9.2%
Final rate of increase in 2004 5.0% 5.5%
Effect of changes in the assumed health care cost trend rate
for each year:
1% increase in APBO components at Dec. 31, 1998 $ 27 199 $ 40 487
1% decrease in APBO components at Dec. 31, 1998 (22 551) (35 359)
1% increase in service and interest costs components of the
net periodic cost 2 652 3 692
1% decrease in service and interest costs components of the
net periodic cost (2 158) (3 199)
COMPONENTS OF NET PERIODIC BENEFIT COST PENSION BENEFITS OTHER POSTRETIREMENT BENEFITS
(THOUSANDS OF DOLLARS) 1998 1997 1996 1998 1997 1996
- - ------------------------------------------------------------------------------------------------------------------------------
Service cost $ 31 643 $ 27 680 $ 29 971 $ 3 247 $ 5 095 $ 6 380
Interest cost 78 839 72 651 70 863 15 896 18 872 19 283
Expected return on plan assets (129 263) (115 359) (102 473) (1 582) (1 242) (927)
Amortization of transition (asset) obligation (76) (76) (76) 8 335 10 780 10 780
Amortization of prior service cost 6 673 1 071 1 071 (175)
Recognized actuarial (gain) (27 727) (20 762) (24 018) (4) 3 120
- - ------------------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost under SFAS 87 or 106 (39 911) (34 795) (24 662) 25 717 33 508 35 636
Costs recognized due to effects of ratemaking 35 545 30 862 23 572 4 033
- - ------------------------------------------------------------------------------------------------------------------------------
NET PERIODIC BENEFIT COST RECOGNIZED FOR
FINANCIAL REPORTING $ (4 366) $ (3 933) $ (1 090) $25 717 $33 508 $39 669
- - ------------------------------------------------------------------------------------------------------------------------------
- - ------------------------------------------------------------------------------------------------------------------------------
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 matched specified amounts of
employee contributions to the plan. NSP's matching contributions were: $4.8
million in 1998, $4.4 million in 1997 and $4.3 million in 1996.
ESOP NSP has a leveraged Employee Stock Ownership Plan (ESOP) that covers
substantially all employees. NSP makes contributions to this noncontributory,
defined contribution plan to the extent we realize a tax savings on our
income statement from dividends paid on certain ESOP shares. Contributions to
the ESOP, which represent compensation expense, were: $4.3 million in 1998,
$4.4 million in 1997 and $4.6 million in 1996.
ESOP contributions have no material effect on NSP earnings because the
contributions are essentially offset by the tax savings provided by the
dividends paid on ESOP shares. NSP allocates leveraged ESOP shares to
participants when it repays ESOP loans with dividends on stock held by the
ESOP.
NSP's ESOP held: 11.3 million shares of NSP common stock at the end of 1998,
11.2 million shares of NSP common stock at the end of 1997 and 11.8 million
shares of NSP common stock at the end of 1996.
NSP excluded the following uncommitted leveraged ESOP shares from
earnings-per-share calculations: 0.6 million in 1998, 0.6 million in 1997 and
0.4 million in 1996.
6. NONREGULATED EARNINGS CONTRIBUTION
Income from nonregulated businesses consists of the following:
(THOUSANDS OF DOLLARS,
EXCEPT PER SHARE AMOUNTS) 1998 1997 1996
- - -------------------------------------------------------------------------------
Operating revenues $182 230 $223 571 $303 903
Equity in operating earnings of
unconsolidated affiliates 79 884 18 600 30 668
Operating and development expenses,
including project write-downs (248 420) (251 087) (326 332)
Interest and other income,
including gains from project sales 37 477 20 994 10 304
- - -------------------------------------------------------------------------------
Income from nonregulated businesses
before interest and taxes 51 171 12 078 18 543
Interest expense (54 261) (34 627) (18 834)
Income tax benefit 41 791 38 032 16 576
- - -------------------------------------------------------------------------------
NET INCOME $ 38 701 $ 15 483 $ 16 285
- - -------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------
EARNINGS PER SHARE $ 0.26 $ 0.11 $ 0.12
- - -------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------
50
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:
1998 1997 1996
- - -------------------------------------------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit 4.7% 4.3% 5.2%
Tax credits recognized (8.9)% (7.9)% (4.1)%
Equity income from unconsolidated affiliates (3.8)% (2.5)% (2.6)%
Regulatory differences - utility plant items 0.7% 1.1% 0.9%
Other - net (0.6)% (1.0)% 0.4%
- - -------------------------------------------------------------------------------------------------
EFFECTIVE INCOME TAX RATE 27.1% 29.0% 34.8%
- - -------------------------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS)
Income taxes are comprised of the following
expense (benefit) items:
Included in utility operating expenses:
Current federal tax expense $127 734 $125 202 $154 421
Current state tax expense 32 750 28 812 39 923
Deferred federal tax expense (6 625) (88) (19 933)
Deferred state tax expense 646 (23) (3 958)
Deferred investment tax credits (9 122) (9 048) (9 043)
- - -------------------------------------------------------------------------------------------------
Total 145 383 144 855 161 410
- - -------------------------------------------------------------------------------------------------
Included in income taxes on nonregulated
operations and nonoperating items:
Current federal tax expense (15 732) (19 470) (906)
Current state tax expense (6 744) (5 804) 712
Current foreign tax expense 2 358 236 616
Current federal tax credits (25 122) (17 006) (8 044)
Deferred federal tax expense 11 132 (2 237) (5 150)
Deferred state tax expense 1 566 (662) (1 520)
Deferred foreign tax expense (7 736) (2 892)
Deferred investment tax credits (310) (310) (308)
- - -------------------------------------------------------------------------------------------------
Total (40 588) (48 145) (14 600)
- - -------------------------------------------------------------------------------------------------
TOTAL INCOME TAX EXPENSE $104 795 $ 96 710 $146 810
- - -------------------------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------------------------
NRG intends to reinvest earnings from foreign operations in those operations
except to the extent the earnings are subject to current U.S. income taxes.
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 $158 million and $112 million at Dec. 31, 1998
and 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 not practicable to estimate the
amount of tax that might be payable.
The components of NSP's net deferred tax liability (current and noncurrent
portions) at Dec. 31 were:
(THOUSANDS OF DOLLARS) 1998 1997 1996
- - -------------------------------------------------------------------------------
Deferred tax liabilities:
Differences between book and
tax bases of property $ 886 099 $ 867 155 $ 850 139
Regulatory assets 103 640 100 564 121 232
Tax benefit transfer leases 27 170 31 614 43 481
Other 22 961 21 715 23 182
- - -------------------------------------------------------------------------------
Total deferred tax liabilities $1 039 870 $1 021 048 $1 038 034
- - -------------------------------------------------------------------------------
Deferred tax assets:
Regulatory liabilities $ 75 774 $ 83 765 $ 90 485
Deferred compensation, vacation
and other accrued liabilities
not currently deductible 67 539 70 765 65 690
Deferred investment tax credits 51 003 54 741 57 239
Other 29 565 26 557 34 509
- - -------------------------------------------------------------------------------
Total deferred tax assets $ 223 881 $ 235 828 $ 247 923
- - -------------------------------------------------------------------------------
NET DEFERRED TAX LIABILITY $ 815 989 $ 785 220 $ 790 111
- - -------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------
8. PREFERRED SECURITIES
At Dec. 31, 1998, various preferred stock series were callable at prices per
share ranging from $102.00 to $103.75, plus accrued dividends.
In 1997, a wholly owned special purpose subsidiary trust of NSP issued
$200 million of 7.875 percent preferred securities that mature in 2037.
Distributions paid by the subsidiary trust on the preferred securities are
financed through interest payments on debentures issued by NSP-Minnesota 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. A portion of the
proceeds was used to redeem NSP'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.
51
9. REGULATORY ASSETS AND LIABILITIES
The following summarizes the individual components of unamortized regulatory
assets and liabilities shown on the Consolidated Balance Sheets at Dec. 31:
REMAINING
(THOUSANDS OF DOLLARS) AMORTIZATION PERIOD 1998 1997
- - -----------------------------------------------------------------------------------------------
AFC recorded in plant
on a net-of-tax basis* Plant Lives $121 551 $128 364
Conservation programs* Primarily 2 Years 72 995 86 508
Losses on
reacquired debt Term of Related Debt 56 242 59 353
Environmental costs Primarily 10 Years 50 158 45 849
Unrecovered gas costs 1-2 Years 16 259 8 020
State commission
accounting adjustments* Plant Lives 7 370 7 286
Other Various 7 365 4 742
- - -----------------------------------------------------------------------------------------------
TOTAL REGULATORY ASSETS $331 940 $340 122
- - -----------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------
Deferred income tax adjustments $ 75 066 $ 88 035
Investment tax credit deferrals 84 865 91 146
Unrealized gains from
decommissioning investments 138 613 85 482
Pension costs - regulatory differences 53 012 27 107
Fuel costs, refunds and other 20 683 13 995
- - -----------------------------------------------------------------------------------------------
TOTAL REGULATORY LIABILITIES $372 239 $305 765
- - -----------------------------------------------------------------------------------------------
- - -----------------------------------------------------------------------------------------------
* 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. We use the equity method of accounting for such
investments in affiliates, which include joint ventures and partnerships. That's
because the ownership structure prevents NSP from exercising a controlling
influence over the projects' operating and financial policies. Under this
method, NSP records its portion of the earnings or losses of unconsolidated
affiliates as equity earnings. A summary of NSP's significant equity method
investments is listed below.
NAME GEOGRAPHIC AREA ECONOMIC INTEREST
- - -----------------------------------------------------------------------------
Loy Yang Power Australia 25.37%
Pacific Generation Company USA/Canada 3.70%-100%
Gladstone Power Station Australia 37.50%
COBEE South America 48.30%
MIBRAG mbH Europe 33.33%
Cogeneration Corp. of America USA 45.21%
Schkopau Power Station Europe 20.95%
Long Beach Generating USA 50.00%
El Segundo Generating USA 50.00%
Energy Development Limited Australia 33.97%
Scudder Latin American Trust
for Independent Power
Energy Projects Latin America 25.00%
Various independent power
production facilities USA 45%-50%
Various affordable housing
limited partnerships USA 20%-99%
- - -----------------------------------------------------------------------------
SUMMARIZED FINANCIAL INFORMATION OF UNCONSOLIDATED AFFILIATES Summarized
financial information for these projects, including interests owned by NSP
and other parties, is as follows for the years ended Dec. 31:
RESULTS OF OPERATIONS
(MILLIONS OF DOLLARS) 1998 1997 1996
- - -----------------------------------------------------------------------------
Operating revenues $1 509 $1 698 $ 958
Operating income $ 205 $ 93 $ 105
Net income $ 143 $ 84 $ 89
NSP's equity in earnings of
unconsolidated affiliates $ 80 $ 19 $ 31
FINANCIAL POSITION
(MILLIONS OF DOLLARS) 1998 1997 1996
- - -----------------------------------------------------------------------------
Current assets $ 714 $ 742 $ 681
Other assets 8 071 7 853 3 525
- - -----------------------------------------------------------------------------
TOTAL ASSETS $8 785 $8 595 $4 206
- - -----------------------------------------------------------------------------
- - -----------------------------------------------------------------------------
Current liabilities $ 537 $ 514 $ 397
Other liabilities 5 931 6 109 2 798
Equity 2 317 1 972 1 011
- - -----------------------------------------------------------------------------
TOTAL LIABILITIES AND EQUITY $8 785 $8 595 $4 206
- - -----------------------------------------------------------------------------
- - -----------------------------------------------------------------------------
NSP's equity investment
in unconsolidated affiliates $ 863 $ 741 $ 410
11. FINANCIAL INSTRUMENTS
FAIR VALUES The estimated Dec. 31 fair values of NSP's recorded financial
instruments are as follows:
(THOUSANDS OF DOLLARS) 1998 1997
- - --------------------------------------------------------------------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
- - --------------------------------------------------------------------------------------
Cash, cash equivalents
and short-term
investments $ 42 364 $ 42 364 $ 54 765 $ 54 765
Long-term
investments $ 438 981 $ 438 981 $ 344 491 $ 344 491
Long-term debt,
including
current portion $2 220 346 $2 313 468 $2 043 295 $2 079 123
- - --------------------------------------------------------------------------------------
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 NSP'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 executed certain transactions designed to protect the
Economic value in U.S. dollars of selected known and anticipated NRG cash
flows denominated in Australian dollars.
As of Dec. 31, 1998, NRG had one contract with a notional value of $2.8
million to hedge - or protect - foreign currency denominated future cash
flows. The effect of this contract on 1998 earnings was immaterial. This
foreign currency exchange contract expires in 1999. Management believes that
NRG'S exposure to credit risk due to nonperformance by the counterparties to
its forward exchange contracts is insignificant, based on the investment
grade rating of the counterparties.
52
EMI had natural gas forward and futures contracts in the notional amount of
$6 million at Dec. 31, 1998. The original contract terms range from one month to
two years. The contracts are intended to hedge risk from fluctuations in the
price of natural gas that will be required to satisfy sales commitments for
future deliveries to customers. EMI's futures contracts hedge $6.1 million in
anticipated natural gas sales in 1999-2000. At Dec. 31, 1998, EMI maintained
margin balances of $1.3 million on deposit with brokers for these contracts,
which are reported 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, 1998, $0.8 million would have been
payable by EMI for natural gas price fluctuations to date.
Energy Marketing uses energy futures contracts, along with physical supply, to
hedge market risk. At Dec. 31, 1998, the notional amount of electricity futures
contracts was less than $1 million. In February 1999, EMI transferred its gas
supply and marketing function to NSP's Energy Marketing Division. Existing sales
commitments and natural gas futures and forward contracts, currently in place,
will remain the contractual responsibility of EMI.
NSP had one interest rate swap agreement with a notional amount of $200 million.
NSP entered into this swap in conjunction with first mortgage bonds (5 1/2%
Series due Feb. 1, 1999). This agreement effectively converted the interest cost
of the debt from fixed to variable rates based on the six-month London Interbank
Offered Rate, with the rates changing semiannually. The net effective interest
cost at Dec. 31, 1998, was 4.91 percent. This swap expired on Feb. 1, 1999.
NRG has one interest rate swap agreement with a notional amount of $17.5
million. This swap was entered into with an existing variable rate debt issue.
The swap effectively converts the variable rate debt into fixed rate debt at
7.65 percent. If the swap had been discontinued on Dec. 31, 1998, NRG would have
had to pay the counterparty approximately $0.9 million. The swap expires on
Sept. 30, 2002.
LETTERS OF CREDIT NSP and its subsidiaries use letters of credit, generally with
terms of one year, to provide financial guarantees for certain operating
obligations, such as NSP-Minnesota workers' compensation benefits, ash disposal
site costs and EMI natural gas purchases.
In addition, NRG uses letters of credit for: nonregulated equity commitments,
collateral for credit agreements, fuel purchase and operating commitments and
bids on development projects.
At Dec. 31, 1998, there were $84 million in letters of credit outstanding,
including $33 million related to NRG commitments. The contract amounts of these
letters of credit approximate their fair value and are subject to fees
determined in the marketplace.
12. JOINT PLANT OWNERSHIP
NSP is part owner of an 860-megawatt, coal-fired electric generating unit called
Sherco 3. NSP owns, and has financed, 59 percent and Southern Minnesota
Municipal Power Agency (SMMPA) owns, and has financed, 41 percent of Sherco 3.
NSP is the operating agent under the joint ownership agreement. NSP's share of
related expenses for Sherco 3 is included in Utility Operating Expenses. NSP's
share of the gross cost recorded in Utility Plant was approximately $604 million
at year-end for both 1998 and 1997. The accumulated provisions for depreciation
were $214.8 million in 1998 and $196.2 million in 1997.
13. NUCLEAR OBLIGATIONS
FUEL DISPOSAL NSP is responsible for temporarily storing used - or spent
- - -nuclear fuel from its nuclear plants. Under a contract with NSP, the U.S.
Department of Energy (DOE) is responsible for permanently storing spent fuel
from NSP's nuclear plants as well as from other U.S. nuclear plants. NSP has
been funding its portion of the DOE's permanent disposal program since 1981.
NSP funded its obligation through an internal sinking fund until 1983, when
the DOE began assessing fuel disposal fees 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: $10.8 million in 1998, $10.1
million in 1997 and $11.3 million in 1996.
In total, NSP had paid approximately $262 million to the DOE through Dec. 31,
1998. However, we cannot determine whether 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 the 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 1996, the DOE notified
commercial spent fuel owners of an anticipated delay in accepting spent
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.
NSP and other utilities have commenced lawsuits against the DOE to recover
damages caused by 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, NSP 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 spent fuel storage until a DOE facility is available,
including pursuing the establishment of a private facility for interim
storage of spent nuclear fuel as part of a consortium of electric utilities.
If on-site temporary storage at NSP's nuclear plants reaches approved
capacity, NSP could seek interim storage at this or another contracted
private facility, if available.
Nuclear fuel expenses include payments to the DOE for the decommissioning - or
permanent retirement - and decontamination of the DOE's uranium enrichment
facilities. In 1993, NSP recorded the DOE's initial assessment of $46 million,
which is payable in annual installments from 1993-2008. NSP is amortizing each
installment to expense on a monthly basis in the 12 months following each
payment. The most recent installment paid in 1998 was $3.9 million; future
installments are subject to inflation adjustments under DOE rules. NSP is
obtaining rate recovery of these DOE assessments through the cost-of-energy
adjustment clause as the assessments are amortized. Accordingly, we deferred the
unamortized assessment of $35 million at Dec. 31, 1998, as a regulatory asset.
PLANT DECOMMISSIONING Decommissioning of NSP's nuclear facilities is planned for
the years 2010-2022, using the prompt dismantlement method. NSP 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. Consequently, the total decommissioning cost
obligation and corresponding assets currently are not recorded in NSP's
financial statements.
53
The Financial Accounting Standards Board (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
2000. Using Dec. 31, 1998, estimates, NSP's adoption of the proposed
accounting would result in the recording of the total discounted
decommissioning obligation of $811 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 than the ratemaking methodology
that derives the decommissioning accruals currently being recovered in rates.
NSP has not yet determined the potential impact of the FASB's proposed
changes in the accounting for site exit obligations, such as costs of
removal, other than nuclear decommissioning. However, the ultimate
decommissioning and site exit costs to be accrued are the same under both
methods. The effects of regulation are expected to minimize or eliminate any
impact on operating expenses and results of operations from this future
accounting change.
Consistent with cost recovery in utility customer rates, NSP 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 MPUC last approved NSP's nuclear decommissioning study and related nuclear
plant depreciation capital recovery request in April 1997, using 1993 cost data.
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. NSP believes
future decommissioning cost accruals will continue to be recovered in customer
rates.
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 NSP debt or stock. The assets held in
trusts as of Dec. 31, 1998, primarily consisted of investments in fixed income
securities, such as tax-exempt municipal bonds and U.S. government securities
that mature in one to 16 years, and common stock of public companies. NSP plans
to reinvest matured securities until decommissioning begins.
At Dec. 31, 1998, NSP had recorded and recovered in rates cumulative
decommissioning accruals of $508 million. The following table summarizes
the funded status of NSP's decommissioning obligation at Dec. 31, 1998:
(THOUSANDS OF DOLLARS) 1998
- - -------------------------------------------------------------------------------
Estimated decommissioning cost obligation
from most recent approved study (1993 dollars) $ 750 824
Effect of escalating costs to 1998 dollars
(at 4.5% per year) 184 840
- - -------------------------------------------------------------------------------
Estimated decommissioning cost obligation
in current dollars 935 664
Effect of escalating costs to payment
date (at 4.5% per year) 909 121
- - -------------------------------------------------------------------------------
Estimated future decommissioning costs (undiscounted) 1 844 785
Effect of discounting obligation (using risk-free
interest rate) (1 033 906)
- - -------------------------------------------------------------------------------
Discounted decommissioning cost obligation 810 879
External trust fund assets at fair value 438 981
- - -------------------------------------------------------------------------------
DISCOUNTED DECOMMISSIONING OBLIGATION IN EXCESS
OF ASSETS CURRENTLY HELD IN EXTERNAL TRUST $ 371 898
- - -------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------
Decommissioning expenses recognized include the following components:
(THOUSANDS OF DOLLARS) 1998 1997 1996
- - -------------------------------------------------------------------------------
Annual decommissioning cost accrual
reported as depreciation expense:
Externally funded $33 178 $33 178 $33 178
Internally funded
(including interest costs) 1 477 1 368 1 268
Interest cost on externally funded
decommissioning obligation 6 960 7 690 5 246
Earnings from external trust funds (6 960) (7 690) (6 294)
- - -------------------------------------------------------------------------------
NET DECOMMISSIONING
ACCRUALS RECORDED $34 655 $34 546 $33 398
- - -------------------------------------------------------------------------------
- - -------------------------------------------------------------------------------
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.
14. COMMITMENTS AND CONTINGENT LIABILITIES
CAPITAL COMMITMENTS NSP estimates utility capital expenditures, including
purchases of nuclear fuel, will be $450 million in 1999 and $2.1 billion for
1999-2003. There also are contractual commitments for the disposal of spent
nuclear fuel. (See Note 13.)
As of Dec. 31, 1998, NRG is contractually committed to additional equity
investments of approximately $1.3 billion in 1999 and approximately $1.3
billion for 1999-2003 for various power generation projects. The 1999 capital
commitments reflect NRG's expected acquisitions of existing generation
facilities, including: Arthur Kill, Astoria, Somerset, Dunkirk, Huntley and
Encina. A significant portion of these capital requirements is expected to be
financed by nonrecourse project debt.
54
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
current status of these commitments can be met by building, purchasing or, in
the case of biomass, converting generation resources.
In 1994, NSP received Minnesota legislative approval for additional on-site
temporary storage facilities at NSP's Prairie Island plant, provided NSP
satisfies certain requirements. Seventeen dry cask containers were approved. In
1996, the Minnesota Environmental Quality Board (MEQB) certified that NSP had
met the requirements necessary to use the sixth through ninth casks at the
Prairie Island nuclear generating facility. The final eight casks become
available unless the resource commitments discussed below are not met and the
Minnesota Legislature revokes its approval before June 1, 1999. As of Dec. 31,
1998, NSP had loaded seven casks.
The 1994 legislation requires NSP to have 425 megawatts of wind resources
contracted by Dec. 31, 2002. Of this commitment, approximately 130 megawatts
remain to be contracted. The MPUC recently ordered an additional 400 megawatts
to be contracted by 2012; however, this order is subject to further MPUC
consideration.
During 1997 and 1998, NSP executed three separate power purchase agreements
(PPA) for a total of 125 megawatts of biomass-fueled generation resources. These
contracts meet the statutory requirements to contract for 125 megawatts of
biomass energy by Dec. 31, 1998. However, all three contracts are currently
being reviewed by the MPUC. The MPUC has tabled further consideration until at
least March of 1999 to allow future consideration of the PPAs. Delayed MPUC
action on any of these contracts puts at risk having 50 megawatts of biomass
resources operational by Dec. 31, 2001, and 75 megawatts of biomass resources
operational by Dec. 31, 2002.
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 NSP's low-income discount programs in
accordance with the statute. NSP's capital commitments 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, NSP 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 NSP. Under the sale agreements, NSP is required to guarantee repayment to the
third party of the remaining loan balances. At Dec. 31, 1998, the outstanding
balance of the loans was approximately $22 million. Based on prior collection
experience of these loans, NSP 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 $33 million, $32
million and $29 million for 1998, 1997 and 1996, 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 1999 and
2013, require minimum purchases and deliveries of fuel, lease payments for
railcars and additional payments for the right to purchase coal in the future.
In total, NSP is committed to the minimum purchase of approximately $254 million
of coal, $34 million of nuclear fuel and $266 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.
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 all fuel 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 NSP has several agreements to purchase electricity from the
Manitoba Hydro-Electric Board (MH). A summary of the agreements is as follows:
POWER AGREEMENTS YEARS MEGAWATTS
- - ---------------------------------------------------------------
Participation power purchase 1999-2005 500
Seasonal diversity exchanges:
Summer exchanges from MH 1999-2014 150
1999-2016 200
Winter exchanges to MH 1999-2014 150
1999-2015 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 NSP's Sherco 3 generating
plant, adjusted to 1993 dollars. The future annual capacity costs for the
500-megawatt MH agreement are 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 1999 and
account for approximately 10 percent of NSP's 1999 electric system
capability. The risk of loss from nonperformance by MH is not considered
significant, and the risk of loss from market price changes is mitigated
through cost-of-energy rate adjustments.
NSP has an agreement with Minnkota Power Cooperative for the purchase of summer
season capacity and energy. From 1999 through 2001, NSP will buy 150 megawatts
of summer season capacity for approximately $12 million annually. From 2002
through 2015, NSP 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. NSP
also has a seasonal (summer) purchase power agreement with Minnesota Power for
the purchase of 173 megawatts, including reserves, from 1999-2000. The annual
cost of this capacity will be approximately $2 million.
55
NSP has agreements with several nonregulated power producers to purchase
electric capacity and associated energy. The 1999 cost of these commitments
is approximately $45 million for 363 megawatts of summer capacity. This
commitment is expected to range between $44 million and $55 million annually for
the years 2000 through 2021. These commitments are expected to decline to
approximately $27 million annually for the years 2022 through 2027, due to the
expiration of existing agreements.
NUCLEAR INSURANCE NSP's public liability for claims resulting from any nuclear
incident is limited to $9.8 billion under the 1988 Price-Anderson amendment to
the Atomic Energy Act of 1954. NSP has secured $200 million of coverage for its
public liability exposure with a pool of insurance companies. The remaining
$9.6 billion of exposure is funded by the Secondary Financial Protection
Program, available from assessments by the federal government in case of a
nuclear accident. NSP is subject to assessments of up to $88 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.
NSP purchases insurance for property damage and site decontamination cleanup
costs with coverage limits of $1.5 billion for each of NSP's two nuclear plant
sites 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 NEIL are expensed over the
policy term. All companies insured with NEIL are subject to retrospective
premium adjustments if losses exceed accumulated reserve funds. Capital has been
accumulated in the reserve funds of NEIL to the extent that NSP would have no
exposure for retrospective premium assessments in case of a single incident
under the business interruption and the property damage insurance coverage.
However, in each calendar year, NSP could be subject to maximum assessments of
approximately $3.6 million for business interruption insurance (generally five
times the amount of its annual premium) and $14.7 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
$40 million, and other current liabilities include an accrual of $5 million, at
Dec. 31, 1998, for estimated costs associated with environmental remediation.
Approximately $28 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 NSP, 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 NSP's nuclear generating plants. (See Note 13
for further discussion.)
The Environmental Protection Agency (EPA) or state environmental agencies have
designated NSP-Minnesota as a potentially responsible party (PRP) for 17 waste
disposal sites to which NSP-Minnesota allegedly sent hazardous materials.
- Twelve of these 17 sites have been remediated and, consistent with
settlements reached with the EPA and other PRPs, NSP-Minnesota has paid
$2.2 million for its share of the remediation costs. While these
remediated sites will continue to be monitored, NSP-Minnesota expects
that future remediation costs, if any, will be immaterial. Under
applicable law, NSP-Minnesota, along with each PRP, could be held jointly
and severally liable for the total remediation costs of PRP sites.
- The total remediation costs of the five unremediated sites is currently
estimated to be approximately $18 million. If additional remediation is
necessary or unexpected costs are incurred, the amount could be higher.
NSP-Minnesota 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, NSP-Minnesota has recorded an estimate of approximately $550,000
for its share of future costs for these five sites, including $500,000
that is expected to be paid in 1999.
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 NSP-Minnesota's future liability. It is NSP-Minnesota's practice to
vigorously pursue and, if necessary, litigate with insurers to recover incurred
remediation costs whenever possible. Through litigation, NSP-Minnesota 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 NSP-Minnesota 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 previously.
NSP-Wisconsin may be involved in the cleanup and remediation at five
additional sites. One site is a solid and hazardous waste landfill site in
Amery, Wis. NSP-Wisconsin contends that it did not dispose of hazardous
wastes in this landfill during the time period in question. The four other
sites are at locations of former manufactured gas plants at Ashland,
LaCrosse, Eau Claire and Chippewa Falls, Wis. The ultimate cleanup and
remediation costs at the LaCrosse, Eau Claire, Amery and Chippewa Falls sites
and the extent of NSP-Wisconsin's responsibility, if any, for sharing such
costs are not known at this time, but are expected to be immaterial.
The Wisconsin Department of Natural Resources (WDNR) named NSP-Wisconsin as one
of three PRPs for creosote and coal tar contamination at the Ashland site. The
Ashland site includes property owned by NSP-Wisconsin and two other properties,
which include an adjacent city lakeshore park area and a small area of Lake
Superior's Chequemegon Bay adjoining the park. The ultimate cost to NSP
associated with the Ashland site is expected to be determined by the WDNR after
appropriate study and review.
In December 1998, the WDNR released the results of its consultant's feasibility
study (FS) for remediating the Ashland site. The options considered by the
WDNR's consultant ranged from no action to completely removing and treating the
contaminated soils, groundwater and lake sediments. The report describes eight
potential corrective strategies and associated costs, and it scores the
effectiveness of each option in terms of meeting state and federal cleanup
standards and guidelines. The options described in the FS are estimated to cost
between $4 million and $93 million, with four of the eight options within a
range of $24 million to $51 million. The two options that were scored the most
effective by the consultant are in the middle to high end of the cost range.
However, the FS recommendations do not bind or require the WDNR to take any
specific remedial action, nor do they limit the options available to remediate
the Ashland site.
Under a spill response order that NSP signed in 1998, NSP has until March 1,
1999, to develop its own FS, which would then be considered by the WDNR in its
decision-making process. This FS is now being prepared by NSP's consultant. NSP
believes that reasonably effective remedial options exist for the Ashland site,
which were not evaluated by the WDNR's consultant, that are estimated to cost
between $6 million and $13 million. These other remedial options and their
56
associated costs will be updated and refined in NSP's FS. NSP officials
continue to discuss remediation options available for the Ashland site, and
NSP-Wisconsin's level of responsibility, with the WDNR.
Until the WDNR selects a remediation method and determines the level of
responsibility of each potentially responsible party, NSP is not able to
estimate its share of the ultimate cost of remediating the Ashland site. NSP
anticipates a decision from the WDNR in the first half of 1999. In the
interim, NSP-Wisconsin has recorded a liability for an estimate of its share
of the cost of remediating the Ashland site based on information available to
date. NSP-Wisconsin has deferred as a regulatory asset the remediation costs
accrued for the Ashland site because management expects that the PSCW will
continue to allow NSP-Wisconsin to recover payments for environmental
remediation from its customers. The PSCW has consistently authorized recovery
in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site,
and has authorized recovery of similar remediation costs for other utilities.
NSP-Minnesota also is continuing to investigate other properties that 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 NSP-Minnesota has any
responsibility for remedial action and if recovery under NSP-Minnesota's
insurance policies can contribute to any remediation costs.
- NSP-Minnesota has remediated three sites, which continue to be
monitored. NSP-Minnesota has paid $6.7 million to remediate these
sites and expects to incur in the future only immaterial monitoring
costs related to these remediated sites.
- Another 12 gas sites remain under investigation, and NSP-Minnesota is
taking remedial action at four of the sites.
- As of Dec. 31, 1998, NSP-Minnesota had paid $4.2 million for the four
active sites and had recorded an estimated liability of approximately
$1.5 million for future costs at these sites, 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 cost of gas site
remediation, the amounts accrued represent the best current estimate of
NSP-Minnesota'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 NSP-Minnesota to defer certain remediation costs of four active sites in
1994. In September 1998, the MPUC allowed the recovery of these gas site
remediation costs in gas rates, with a portion assigned to NSP's electric
operations for two sites formerly used by NSP generating facilities.
Accordingly, NSP-Minnesota has recorded an environmental regulatory asset for
these costs. NSP-Minnesota may request recovery of costs to remedy other
activated sites following the completion of preliminary investigations.
The Clean Air Act, including the Amendments of 1990, 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. NSP has invested
significantly over the years to reduce sulfur dioxide emissions at its plants.
No additional capital expenditures are anticipated to comply with the sulfur
dioxide emission limits of the Clean Air Act. NSP is evaluating how best to
implement the nitrogen oxides standards. NSP-Minnesota's capital expenditures
include some costs for ensuring compliance with the Clean Air Act's other
emission requirements; other expenditures may be necessary upon Environmental
Protection Agency (EPA) 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 included in the capital expenditure commitments disclosed
previously. The depreciation of these capital costs will be subject to
regulatory recovery in future rate proceedings.
In September 1998, the EPA issued nitrogen oxide regulation affecting 22 states,
including Wisconsin. NSP-Wisconsin may be required to retrofit some of its
electric generating plants by 2003 to comply with this regulation. NSP-Wisconsin
and other parties have petitioned for a judicial review of the regulation. The
new regulation has not been finalized by the WDNR, so NSP-Wisconsin cannot
determine the additional cost to comply.
Several of NSP's facilities have asbestos material, which can be a health hazard
to people who come in contact with it. Governmental regulations specify the
timing and nature of disposal of asbestos 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 1998 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.
LEGAL CLAIMS In the normal course of business, NSP is a party to routine claims
and litigation arising from prior and current operations. NSP is actively
defending these matters and has recorded an estimate of the probable cost of
settlement or other disposition.
In April 1997, a fire damaged several buildings in downtown Grand Forks, N.D.,
during the historic floods in that city. On July 23, 1998, the St. Paul Mercury
Insurance Co., which insured the First National Corp. and its three buildings in
downtown Grand Forks, commenced a lawsuit against NSP for damages in excess of
$15 million. The suit was filed in the District Court in Grand Forks County in
North Dakota. Douglas W. Leatherdale, a member of NSP's board of directors, is
chairman and chief executive officer of St. Paul Companies Inc., the parent of
St. Paul Mercury Insurance Co. W. John Driscoll, a member of NSP's board of
directors, is also a director of St. Paul Companies Inc. The insurance company
alleges that the fire was electrical in origin and that NSP was legally
responsible for the fire because it failed to shut off electrical power to
downtown Grand Forks during the flood and prior to the fire. In December 1998, a
second lawsuit related to the fire was commenced by two partnerships that owned
57
property damaged by the fire and Protection Mutual Insurance Co., which insured
the Grand Forks Herald building damaged by the fire. It is NSP's position that
it is not legally responsible for this unforeseeable event. At no time prior to
the fire was NSP instructed to shut off power to downtown Grand Forks by any
government officials, including representatives from the fire department.
Moreover, people in downtown Grand Forks were relying on electricity before and
after the fire occurred. NSP has a self-insured retention deductible of $2
million, with general liability insurance coverage limits of $150 million. The
ultimate cost to NSP, if any, is unknown at this time.
On Nov. 24, 1998, Wisconsin Electric Power Company (WEPCO) filed a complaint
against NSP with the FERC. WEPCO alleges that it suffered 21 firm transmission
service curtailments from May 1998 to August 1998 and that these curtailments
violated NSP's obligation under FERC Order No. 888 electric transmission service
tariff. WEPCO is seeking: a refund of an unspecified amount, a ruling that
certain mitigation charges WEPCO agreed to pay violate Order No. 888 and other
miscellaneous relief. On Dec. 24, 1998, NSP filed an answer demonstrating the 21
curtailments were implemented lawfully under NSP's contracts with WEPCO, FERC
Order No. 888 and the NSP transmission tariff, as clarified by the FERC. NSP
asked the FERC to promptly dismiss the complaint. There is no deadline for FERC
action on the complaint.
On Dec. 11, 1998, a gas explosion in downtown St. Cloud, Minn., killed four
people, including two NSP employees, injured approximately 14 people and damaged
several buildings. The accident occurred as a crew of four employees from Cable
Constructors Inc. (CCI) was installing fiber optic cable. CCI was performing
this work for Seren as part of its broadband communications project in St. Cloud
and surrounding communities. The accident is under investigation by the National
Transportation Safety Board (NTSB). Although this investigation is expected to
take several months, the NTSB investigator in charge has stated publicly that
"the location of the gas line and a gas main that runs parallel had been
properly marked by NSP before the drilling." NSP and Seren have been notified of
potential property and personal injury claims related to this explosion. Both
companies deny any liability for this accident. NSP has a self-insured retention
deductible of $2 million with general liability coverage limits of $185 million.
Seren's primary insurance coverage is $1 million and its secondary insurance
coverage is $185 million. The ultimate cost to NSP and Seren, if any, is
presently unknown.
15. SEGMENT AND RELATED INFORMATION
Effective Dec. 31, 1998, NSP adopted SFAS No. 131 - Disclosures About Segments
of an Enterprise and Related Information. NSP has four reported segments:
Electric Utility, Gas Utility and two of its nonregulated energy businesses, its
wholly owned subsidiaries, NRG and EMI.
- NSP's electric utility generates, transmits and distributes electricity
primarily in Minnesota, Wisconsin, Michigan, North Dakota and South
Dakota. It also makes sales for resale and provides wholesale
transmission service to various entities in the United States.
- NSP's gas utility transmits, transports, stores and distributes natural
gas and propane primarily in Minnesota, Wisconsin, North Dakota, Michigan
and, beginning in 1998, Arizona.
- NRG develops, builds, acquires, owns and operates several nonregulated
energy-related businesses, including independent power production,
commercial and industrial heating and cooling, and energy-related refuse-
derived fuel production, both domestically and outside the United States.
- EMI is an energy service company, primarily retrofitting and upgrading
facilities for greater energy efficiency, largely in the United States.
In general, NSP has segmented its operations as either regulated or
nonregulated businesses. Further, the regulated businesses are separated
between electric and gas; and nonregulated businesses are separated by
company (primarily based on product and services). The electric and gas
businesses are part of NSP-Minnesota, NSP-Wisconsin and Viking companies and
are reviewed at various jurisdiction and/or company levels. They have been
aggregated as reportable segments as they are aggregated for reporting to
NSP's Board of Directors. Assets by segment are not reported to management
and are not included in the disclosures that follow.
The measure of profit or loss for electric and gas reported in the various
management reports varies, but the largest component, NSP-Minnesota, reports net
income and earnings per share on a basis consistent with consolidated net income
and earnings per share, except that allocations are needed for some items, as
described later. Intercompany and intersegment sales are priced at approved
tariff rates and are immaterial. In addition, since NRG and EMI are separate
companies, their net income and earnings per share are the measure of profit or
loss for both internal management reporting and consolidated external NSP
reporting.
To report net income for electric and gas utility segments, NSP-Minnesota and
NSP-Wisconsin must assign or allocate all costs and certain other income.
In general, costs are:
- directly assigned wherever applicable
- allocated based on cost causation allocators wherever applicable
- allocated based on a general allocator for all other costs not assigned
by the above two methods
The "all other" category includes segments that measure below the quantitative
threshold for separate disclosure and consists primarily of nonregulated
companies, including Eloigne, an affordable housing investment company; Seren, a
communications and data services company; Ultra Power, a power-cable testing
company; and several other small companies and businesses.
58
BUSINESS SEGMENTS
1998 ELECTRIC GAS ALL RECONCILING CONSOLIDATED
(THOUSANDS OF DOLLARS) UTILITY UTILITY NRG EMI OTHER ELIMINATIONS TOTAL (a)
- - -----------------------------------------------------------------------------------------------------------------------------------
Operating revenues from external
customers (b) $2 361 536 $456 710 $ 98 688 $ 54 254 $ 29 288 $3 000 476
Intersegment revenues 815 9 292 1 737 $(10 916) 928
- - -----------------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES $2 362 351 $466 002 $100 425 $ 54 254 $ 29 288 $(10 916) $3 001 404
- - -----------------------------------------------------------------------------------------------------------------------------------
Depreciation and amortization 308 415 31 864 16 320 2 129 3 779 362 507
Interest income 9 103 1 403 8 052 184 776 (608) 18 910
Financing costs, mainly interest
expense 109 192 15 485 50 313 108 3 997 (608) 178 487
Income tax expense (credit) 135 914 10 672 (25 654) (4 214) (11 923) 104 795
Equity in earnings (losses) of
unconsolidated affiliates 969 81 706 300 (2 122) 80 853
SEGMENT NET INCOME (LOSS) $ 226 351 $ 17 321 $ 41 732 $ (7 659) $ 4 628 $ 282 373
- - -----------------------------------------------------------------------------------------------------------------------------------
1997 ELECTRIC GAS ALL RECONCILING CONSOLIDATED
(THOUSANDS OF DOLLARS) UTILITY UTILITY NRG EMI OTHER ELIMINATIONS TOTAL (a)
- - -----------------------------------------------------------------------------------------------------------------------------------
Operating revenues from external
customers (b) $2 217 542 $515 162 $102 791 $ 94 375 $ 26 405 $2 956 275
Intersegment revenues 1 008 6 113 926 $ (7 005) 1 042
- - -----------------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES $2 218 550 $521 275 $103 717 $ 94 375 $ 26 405 $ (7 005) $2 957 317
- - -----------------------------------------------------------------------------------------------------------------------------------
Depreciation and amortization 299 325 28 609 10 310 1 768 3 069 343 081
Interest income 1 696 331 10 806 604 774 (482) 13 729
Financing costs, mainly interest
expense 111 595 13 429 30 729 272 3 626 (482) 159 169
Merger cost write-off 29 005 29 005
Income tax expense (credit) 122 655 12 087 (23 680) (5 921) (8 431) 96 710
Equity in earnings (losses) of
unconsolidated affiliates 605 26 003 (5 144) (2 259) 19 205
SEGMENT NET INCOME (LOSS) $ 199 553 $ 22 284 $ 21 982 $(10 841) $ 4 342 $ 237 320
- - -----------------------------------------------------------------------------------------------------------------------------------
1996 ELECTRIC GAS ALL RECONCILING CONSOLIDATED
(THOUSANDS OF DOLLARS) UTILITY UTILITY NRG EMI OTHER ELIMINATIONS TOTAL (a)
- - -----------------------------------------------------------------------------------------------------------------------------------
Operating revenues from external
customers (b) $2 126 364 $526 640 $ 70 104 $207 939 $ 25 860 $2 956 907
Intersegment revenues 1 049 3 363 1 545 $ (4 755) 1 202
- - -----------------------------------------------------------------------------------------------------------------------------------
TOTAL REVENUES $2 127 413 $530 003 $ 71 649 $207 939 $ 25 860 $ (4 755) $2 958 109
- - -----------------------------------------------------------------------------------------------------------------------------------
Depreciation and amortization 279 459 29 027 8 666 1 192 2 842 321 186
Interest income 4 593 696 9 443 295 680 (326) 15 381
Financing costs, mainly interest
expense 100 406 11 785 15 354 301 3 179 (326) 130 699
Income tax expense (credit) 145 514 17 872 (5 655) (4 591) (6 330) 146 810
Equity in earnings (losses) of
unconsolidated affiliates 358 34 674 (1 461) (2 545) 31 026
SEGMENT NET INCOME (LOSS) $ 230 602 $ 27 652 $ 19 978 $ (8 526) $ 4 833 $ 274 539
- - -----------------------------------------------------------------------------------------------------------------------------------
(a) The Consolidated Total amounts for income and expense items represent the
sum of utility amounts (including some nonoperating items) from the
Statement of Income and the nonregulated amounts from Note 6. The
depreciation and amortization amounts in the Statement of Cash Flows are
different than reported in the Consolidated Total column due to
classification of certain depreciation and amortization amounts as other
expense items in the Statement of Income.
(b) All operating revenues are from external customers located in the United
States. However, NRG has significant equity investments for nonregulated
projects outside of the United States. Equity in earnings of unconsolidated
affiliates, primarily independent power projects, includes $29.3 million in
1998, $27.1 million in 1997 and $29.5 million in 1996 from nonregulated
projects located outside of the United States. NRG's equity investments in
projects outside of the United States were $591 million in 1998, $517
million in 1997 and $295 million in 1996.
59
16. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
(THOUSANDS OF DOLLARS, QUARTER ENDED
EXCEPT PER SHARE AMOUNTS) MARCH 31, 1998 JUNE 30, 1998 SEPT. 30,1998(a) DEC. 31, 1998(b)
- - ----------------------------------------------------------------------------------------------------------
Utility operating revenues $701 402 $638 601 $766 448 $712 723
Utility operating income 79 050 65 054 134 985 85 200
Net income 57 117 35 034 101 694 88 528
Earnings available for common stock 54 750 33 974 100 634 87 467
Earnings per average common share:
Basic $0.37 $0.23 $0.67 $0.58
Diluted $0.37 $0.23 $0.67 $0.58
Dividends declared per common share $0.3525 $0.3575 $0.3575 $0.3575
Stock prices - high $29 25/32 $30 7/32 $29 3/16 $30 13/16
- low $26 1/2 $27 11/32 $25 11/16 $26 3/16
(THOUSANDS OF DOLLARS, QUARTER ENDED
EXCEPT PER SHARE AMOUNTS) MARCH 31, 1997 JUNE 30, 1997(c) SEPT. 30, 1997 DEC. 31, 1997
- - ----------------------------------------------------------------------------------------------------------
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 $0.45 $0.12 $0.62 $0.42
Diluted $0.45 $0.12 $0.61 $0.42
Dividends declared per common share $0.3450 $0.3525 $0.3525 $0.3525
Stock prices - high $24 9/16 $26 $26 15/32 $29 7/16
- low $22 3/4 $22 1/4 $24 $24 7/32
- - ----------------------------------------------------------------------------------------------------------
(a) 1998 results include a $22 million pretax charge, which reduced third
quarter earnings by 10 cents per share, for the write-down of NRG projects.
(b) 1998 results include a $26 million pretax gain, which increased fourth
quarter earnings by 11 cents per share, for an NRG project sell down.
(c) 1997 results include a $29 million pretax charge, which reduced second
quarter earnings by 12 cents per share, for the write-off of merger costs.
60
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
During 1998, there were no disagreements with NSP's independent public
accountants on accounting procedures or accounting and financial disclosures.
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required under this Item with respect to directors is set
forth in the Registrant's 1999 Proxy Statement for its Annual Meeting of
Shareholders to be held April 28, 1999, on pages 3 through 9 under the caption
"Election of Directors," which is incorporated by reference. Information with
respect to Executive Officers is included under the caption "Executive Officers"
in Item 1 of this report, and is incorporated by reference.
ITEM 11 - EXECUTIVE COMPENSATION
Information required under this Item is set forth in the Registrant's
1999 Proxy Statement for its Annual Meeting of Shareholders to be held April 28,
1999, on pages 10 through 18 under the caption "Compensation of Executive
Officers," which is incorporated by reference.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required under this item is set forth in the Registrant's
1999 Proxy Statement for its Annual Meeting of Shareholders to be held April 28,
1999, on page 9 under the caption "Share Ownership of Directors, Nominees and
Named Executive Officers," which is incorporated by reference.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required under this Item is set forth in the Registrant's
1999 Proxy Statement for its Annual Meeting of Shareholders to be held April 28,
1999, on pages 4 through 6 under the captions "Class I - Nominees for Terms
expiring in 2002," "Class III Directors whose Terms expire in 2001," "Class II -
Directors whose Terms Expire in 2000," which is incorporated by reference.
61
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
- - -------------------------------------------------------------------------------
(a) 1. FINANCIAL STATEMENTS PAGE
Included in Part II of this report:
Report of Independent Accountants for the years
ended Dec. 31, 1998, 1997 and 1996. 39
Consolidated Statements of Income for the three
years ended Dec. 31, 1998. 40
Consolidated Statements of Cash Flows for the three
years ended Dec. 31, 1998. 41
Consolidated Balance Sheets, Dec. 31, 1998
and 1997. 42
Consolidated Statements of Changes in Common
Stockholders' Equity for the three years ended
Dec. 31, 1998. 43
Consolidated Statements of Capitalization,
Dec. 31, 1998 and 1997. 44
Notes to Financial Statements. 46
(a) 2. FINANCIAL STATEMENT SCHEDULES
Schedules are omitted because of the absence of the conditions
under which they are required or because the information required
is included in the financial statements or the notes.
(a) 3. EXHIBITS
* Indicates incorporation by reference
2.01* Agreement and Plan of Merger, dated as of March
24, 1999, by and between Northern States Power
Company and New Century Energies, Inc.
(Incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K (File No 1-12907) of
New Century Energies, Inc dated March 24, 1999.
3.01* Restated Articles of Incorporation of the Company
and Amendments. (Exhibit 3.01 to Form 10-Q for
the quarter ended June 30, 1998, File No.
1-3034).
3.02* Bylaws of the Company as amended March 26, 1997,
and ratified by NSP's shareholders on June 25,
1997. (Exhibit 3.02 to Form 10-K for the year
1997, File No. 1-3034).
4.01* Trust Indenture, dated Feb. 1, 1937, from NSP to
Harris Trust and Savings Bank, as Trustee.
(Exhibit B-7 to File No. 2-5290).
4.02* Supplemental and Restated Trust Indenture, dated
May 1, 1988, from NSP to Harris Trust and Savings
Bank, as Trustee. (Exhibit 4.02 to Form 10-K for
the year 1988, File No. 1-3034).
Supplemental Indenture between NSP and said
Trustee, supplemental to Exhibit 4.01, dated as
follows:
4.03* June 1, 1942 (Exhibit B-8 to File No. 2-97667).
4.04* Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290).
4.05* Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924).
4.06* July 1, 1948 (Exhibit 7.05 to File No. 2-7549).
4.07* Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047).
4.08* June 1, 1952 (Exhibit 4.08 to File No. 2-9631).
4.09* Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216).
62
4.10* Sept. 1, 1956 (Exhibit 2.09 to File No. 2-13463).
4.11* Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156).
4.12* July 1, 1958 (Exhibit 4.12 to File No. 2-15220).
4.13* Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355).
4.14* Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282).
4.15* June 1, 1962 (Exhibit 2.14 to File No. 2-21601).
4.16* Sept. 1, 1963 (Exhibit 4.16 to File No. 2-22476).
4.17* Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338).
4.18* June 1, 1967 (Exhibit 2.17 to File No. 2-27117).
4.19* Oct. 1, 1967 (Exhibit 2.01R to File No. 2-28447).
4.20* May 1, 1968 (Exhibit 2.01S to File No. 2-34250).
4.21* Oct. 1, 1969 (Exhibit 2.01T to File No. 2-36693).
4.22* Feb. 1, 1971 (Exhibit 2.01U to File No. 2-39144).
4.23* May 1, 1971 (Exhibit 2.01V to File No. 2-39815).
4.24* Feb. 1, 1972 (Exhibit 2.01W to File No. 2-42598).
4.25* Jan. 1, 1973 (Exhibit 2.01X to File No. 2-46434).
4.26* Jan. 1, 1974 (Exhibit 2.01Y to File No. 2-53235).
4.27* Sept. 1, 1974 (Exhibit 2.01Z to File No. 2-53235).
4.28* Apr. 1, 1975 (Exhibit 4.01 AA to File No. 2-71259).
4.29* May 1, 1975 (Exhibit 4.01BB to File No. 2-71259).
4.30* March 1, 1976 (Exhibit 4.01CC to File No. 2-71259).
4.31* June 1, 1981 (Exhibit 4.01DD to File No. 2-71259).
4.32* Dec. 1, 1981 (Exhibit 4.01EE to File No. 2-83364).
4.33* May 1, 1983 (Exhibit 4.01FF to File No. 2-97667).
4.34* Dec. 1, 1983 (Exhibit 4.01GG to File No. 2-97667).
4.35* Sept. 1, 1984 (Exhibit 4.01HH to File No. 2-97667).
4.36* Dec. 1, 1984 (Exhibit 4.01II to File No. 2-97667).
4.37* May 1, 1985 (Exhibit 4.36 to Form 10-K for the year
1985, File No. 1-3034).
4.38* Sept. 1, 1985 (Exhibit 4.37 to Form 10-K for the year
1985, File No. 1-3034).
4.39* July 1, 1989 (Exhibit 4.01 to Form 8-K dated
July 7, 1989, File No. 1-3034).
63
4.40* June 1, 1990 (Exhibit 4.01 to Form 8-K dated
June 1, 1990, File No. 1-3034).
4.41* Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated
Oct. 13, 1992, File No. 1-3034).
4.42* April 1, 1993 (Exhibit 4.01 to Form 8-K dated
March 30, 1993, File No. 1-3034).
4.43* Dec. 1, 1993 (Exhibit 4.01 to Form 8-K dated
Dec. 7, 1993, File No. 1-3034).
4.44* Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated
Feb. 10, 1994, File No. 1-3034).
4.45* Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated
Oct. 5, 1994, File No. 1-3034).
4.46* June 1, 1995 (Exhibit 4.01 to Form 8-K dated
June 28, 1995, File No. 1-3034).
4.47* April 1, 1997. (Exhibit 4.47 to Form 10-K for the
year 1997. File No. 1-3034).
4.48* March 1, 1998 (Exhibit 4.01 to Form 8-K dated
March 11, 1998, File No. 1-3034).
4.49* Trust Indenture, dated April 1, 1947, from
NSP-Wisconsin to Firstar Trust Company (formerly
First Wisconsin Trust Company), as Trustee.
(Exhibit 7.01 to File No. 2-6982).
Supplemental Indentures between NSP-Wisconsin and
said Trustee, supplemental to Exhibit 4.49 dated
as follows:
4.50* March 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.51* June 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.52* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.53* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693).
4.54* Sept. 1, 1973 (Exhibit 2.03F to File No. 2-49757).
4.55* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146).
4.56* March 1, 1982 (Exhibit 4.08 to Form 10-K for the
year 1982, File No. 10-3140).
4.57* June 1, 1986 (Exhibit 4.01I to File No. 33-6269).
4.58* March 1, 1988 (Exhibit 4.01J to File No. 33-20415).
4.59* Supplemental and Restated Trust Indenture dated
March 1, 1991, from NSP-Wisconsin to Firstar
Trust Company (formerly First Wisconsin Trust
Company), as Trustee. (Exhibit 4.01K to File No.
33-39831).
4.60* April 1, 1991 (Exhibit 4.01L to File No. 33-39831).
4.61* March 1, 1993 (Exhibit 4.01 to Form 8-K dated
March 4, 1993, File No. 10-3140).
4.62* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated
September 21, 1993, File No. 10-3140).
4.63* Dec. 1, 1996 (Exhibit 4.01 to Form 8-K dated
December 12, 1996, File No. 10-3140).
4.64* NSP Employee Stock Ownership Plan. (Exhibit 4.60 to
Form 10-K for the year 1994 File No. 1-3034).
4.65* Subordinated Debt Securities Indenture, dated as of
Jan. 30, 1997, between NSP and Norwest Bank
Minnesota, National Association, as trustee.
(Exhibit 4.02 to Form 8-K dated Jan. 28, 1997,
File No. 001-03034).
64
4.66* Preferred Securities Guarantee Agreement, dated as
of Jan. 31, 1997, between NSP and Wilmington Trust
Company, as Trustee. (Exhibit 4.05 to Form 8-K dated
Jan. 28, 1997, File No. 001-03034).
4.67* Amended and Restated Declaration of Trust of NSP
Financing I, dated as of Jan. 31, 1997, including
form of Preferred Security. (Exhibit 4.10 to Form
8-K dated Jan, 28 1997, File No. 001-03034).
4.68* Supplemental Indenture, dated as of Jan. 31,
1997, between NSP and Norwest Bank Minnesota,
National Association, as trustee, including form
of Junior Subordinated Debenture. (Exhibit 4.12
to Form 8-K dated Jan 28, 1997, File No.
001 - 03034).
4.69* Common Securities Guarantee Agreement dated as of
Jan. 31, 1997, between NSP and Wilmington Trust
Company, as Trustee. (Exhibit 4.13 to Form 8-K dated
Jan. 28, 1997, File No. 001 - 03034).
4.70* Subscription Agreement, dated as of Jan. 28, 1997,
between NSP Financing I and NSP. (Exhibit 4.14 to
Form 8-K dated Jan 28, 1997, File No. 001 - 03034).
10.01* Facilities Agreement, dated July 21, 1976, between
NSP and the Manitoba Hydro-Electric Board relating
to the interconnection of the 500 KV Line. (Exhibit
5.06I to File No. 2-54310).
10.02* Transactions Agreement, dated July 21, 1976, between
NSP and the Manitoba Hydro-Electric Board relating
to the interconnection of the 500 KV Line. (Exhibit
5.06J to File No. 2-54310).
10.03* Coordinating Agreement, dated July 21, 1976, between
NSP and the Manitoba Hydro-Electric Board relating
to the interconnection of the 500 KV Line. (Exhibit
5.06K to File No. 2-54310).
10.04* Ownership and Operating Agreement, dated
March 11, 1982, between NSP, Southern Minnesota
Municipal Power Agency and United Minnesota
Municipal Power Agency concerning Sherburne
County Generating Unit No. 3. (Exhibit 10.01 to
Form 10-Q for the quarter ended Sept. 30, 1994,
File No. 1-3034).
10.05* Transmission Agreement, dated April 27, 1982, and
Supplement No. 1, dated July 20, 1982, between
NSP and Southern Minnesota Municipal Power
Agency. (Exhibit 10.02 to Form 10-Q for the
quarter ended Sept. 30, 1994, File No. 1-3034).
10.06* Power Agreement, dated June 14, 1984, between NSP
and the Manitoba Hydro-Electric Board, extending
the agreement scheduled to terminate on April 30,
1993, to April 30, 2005. (Exhibit 10.03 to Form
10-Q for the quarter ended Sept. 30, 1994, File
No. 1-3034).
10.07* Power Agreement, dated August 1988, between NSP
and Minnkota Power Company. (Exhibit 10.08 to
Form 10-K for the year 1988, File No. 1-3034).
EXECUTIVE COMPENSATION ARRANGEMENTS AND BENEFIT PLANS COVERING EXECUTIVE
OFFICERS AND DIRECTORS
10.08* Summary of Terms and Conditions of Employment of
James J Howard, Chairman, President and Chief
Executive Officer, effective Feb. 1, 1987, as
amended and restated effective as of Jan. 28,
1998. (Agreement filed as Exhibit 10.03 to Form
10-Q for the quarter ended March 31, 1998, File
No. 1-3034).
10.09* NSP Severance Plan. (Exhibit 10.12 to Form 10-K for
the year 1994, File No. 1-3034).
65
10.10* NSP Deferred Compensation Plan amended effective
Jan. 1, 1993. (Exhibit 10.16 to Form 10-K for the
year 1993, File No. 1-3034).
10.11* Amended and Restated Executive Long-Term Incentive
Award Stock Plan. (Exhibit 10.02 to Form 10-Q for the
quarter ended March 31, 1998, File No. 1-3034).
10.12* Executive Annual Incentive Award Plan for 1998.
(Exhibit 10.01 to Form 10-Q for the quarter ended
March 31, 1998, File No. 1-3034).
10.13* Stock Equivalent Plan for Non-Employee Directors of
Northern States Power Company As Amended and Restated
Effective Oct. 1, 1997. (Exhibit 10.15 to Form 10-K
for the year 1997. File No. 1-3034.)
10.14 Employment Contract of James J. Howard dated
March 24, 1999.
12.01 Statement of Computation of Ratio of Earnings to
Fixed Charges.
21.01 Subsidiaries of the Registrant.
23.01 Consent of Independent Accountants -
PricewaterhouseCoopers LLP, Minneapolis, Minn.
99.01 Statement pursuant to Private Securities Litigation
Reform Act of 1995.
99.02* Description of Business of NRG Energy, Inc. (Item 1
of NRG Energy, Inc.'s Annual Report on Form 10-K for
the fiscal year ended Dec. 31, 1998, File No.
333-33397).
27.01 Financial Data Schedule for 1998.
(b) REPORTS ON FORM 8-K. The following reports on Form 8-K were filed
either during the three months ended Dec. 31, 1998, or between
Dec. 31, 1998, and the date of this report:
Oct. 6, 1998, (Filed Oct. 6, 1998) Item 5. Other Events. Item 7.
Financial Statements and Exhibits. Re: Disclosure of NRG's $23
million pretax write-down of investments in Indonesia and other
projects against third quarter 1998 earnings.
Dec. 22, 1998 (Filed Dec. 29, 1998) - Item 5. Other Events. Item 7.
Financial Statements and Exhibits. Re: Disclosure of NRG's sale of a
portion of its interest in Enfield Energy Centre .
March 25, 1999 (Filed March 25, 1999) - Item 5. Other Events.
Item 7. Financial Statements and Exhibits. RE: Disclosure of
NSP's proposed merger with New Century Energies, Inc.
66
SIGNATURES
- - --------------------------------------------------------------------------------
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this annual report to be
signed on its behalf by the undersigned, thereunto duly authorized.
NORTHERN STATES POWER COMPANY
March 24, 1999 /s/
----------------------------------------------
E J MCINTYRE
Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, report signed below by the following
persons on behalf of the registrant in the capacities and on the date indicated.
/s/ /s/
- - ---------------------------------------------- ----------------------------------------------
JAMES J HOWARD E J MCINTYRE
Chairman of the Board, President and Chief Vice President and Chief Financial Officer
Executive Officer (Principal Financial Officer)
(Principal Executive Officer)
/s/ /s/
- - ---------------------------------------------- ----------------------------------------------
ROGER D SANDEEN H LYMAN BRETTING
Vice President and Controller Director
(Principal Accounting Officer)
/s/ /s/
- - ---------------------------------------------- ----------------------------------------------
DAVID A CHRISTENSEN W JOHN DRISCOLL
Director Director
/s/ /s/
- - ---------------------------------------------- ----------------------------------------------
GIANNANTONIO FERRARI ALLAN L. SCHUMAN
Director Director
/s/ /s/
- - ---------------------------------------------- ----------------------------------------------
RICHARD M KOVACEVICH DOUGLAS W LEATHERDALE
Director Director
/s/ /s/
- - ---------------------------------------------- ----------------------------------------------
MARGARET R PRESKA A PATRICIA SAMPSON
Director Director
67
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
- - --------- ------- -----------
DT 10.14 Employment contract of James J. Howard dated
March 24, 1999.
DT 12.01 Statement of Computation of Ratio of Earnings to
Fixed Charges.
DT 21.01 Subsidiaries of the Registrant.
DT 23.01 Consent of Independent Accountants - Price
WaterhouseCoopers LLP, Minneapolis, MN.
DT 99.01 Statement pursuant to Private Securities
Litigation Reform Act of 1995.
DT 27.01 Financial Data Schedule for 1998.
DT = Filed electronically with this direct transmission.