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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997 Commission file number: 1-3034
NORTHERN STATES POWER COMPANY
(Exact name of Registrant as specified in its charter)
MINNESOTA 41-0448030
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
414 NICOLLET MALL, MINNEAPOLIS, MINNESOTA 55401
(Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 612-330-5500
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class Name of each exchange on which
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Common Stock, $2.50 Par Value New York Stock Exchange,
Chicago Stock Exchange and
Pacific Stock Exchange
Cumulative Preferred Stock, $100
Par Value each
Preferred Stock $ 3.60 Cumulative New York Stock Exchange
Preferred Stock $ 4.08 Cumulative New York Stock Exchange
Preferred Stock $ 4.10 Cumulative New York Stock Exchange
Preferred Stock $ 4.11 Cumulative New York Stock Exchange
Preferred Stock $ 4.16 Cumulative New York Stock Exchange
Preferred Stock $ 4.56 Cumulative New York Stock Exchange
Trust Originated Preferred Securities 7 7/8% New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. _X_
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes _X_ No ___.
As of March 15, 1998, the aggregate market value of the voting common
stock held by non-affiliates of the Registrant was $4,307,021,119 and there
were 74,867,560 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE
The Registrant's Definitive Proxy Statement for its 1998 meeting of
Shareholders to be held on April 22, 1998, is incorporated by reference into
Part III of Form 10-K
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<PAGE>
INDEX
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Page No.
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PART I
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Item 1 - Business..............................................................1
TERMINATION OF PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION............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 in Effect......................4
Resource Adjustment Clauses in Effect....................................5
Rate Matters by Jurisdiction.............................................5
ELECTRIC UTILITY OPERATIONS
Competition..............................................................8
Technological Improvements..............................................11
Capability and Demand...................................................11
Energy Sources..........................................................14
Fuel Supply and Costs...................................................14
Nuclear Power Plants - Licensing, Operation and Waste Disposal..........16
Electric Operating Statistics...........................................19
GAS UTILITY OPERATIONS
Competition/Regulation..................................................20
Business Growth.........................................................21
Business Standards......................................................21
Standards of Conduct/Restructuring......................................22
Capability and Demand...................................................22
Gas Supply and Costs....................................................23
Viking Gas Transmission Company ........................................24
Gas Operating Statistics ...............................................25
NON-REGULATED SUBSIDIARIES
NRG Energy, Inc. .......................................................26
Energy Masters International, Inc. .....................................29
Eloigne Company.........................................................29
Seren Innovations, Inc..................................................30
Ultra Power Technologies, Inc...........................................30
Non-Regulated Business Information......................................31
ENVIRONMENTAL MATTERS......................................................32
CAPITAL SPENDING AND FINANCING.............................................34
EMPLOYEES AND EMPLOYEE BENEFITS............................................34
EXECUTIVE OFFICERS.........................................................35
Item 2 - Properties...........................................................37
Item 3 - Legal Proceedings....................................................38
Item 4 - Submission of Matters to a Vote of Security Holders..................39
PART II
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Item 5 - Market for Registrant's Common Equity and Related Stockholder
Matters............................................................39
Item 6 - Selected Financial Data..............................................40
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations..............................41
Item 8 - Financial Statements and Supplementary Data..........................50
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..............................72
PART III
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Item 10 - Directors and Executive Officers of the Registrant..................72
Item 11 - Executive Compensation..............................................72
Item 12 - Security Ownership of Certain Beneficial Owners and Management......72
Item 13 - Certain Relationships and Related Transactions......................72
PART IV
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Item 14 - Exhibits, Financial Statement Schedules, and Reports on Form 8-K....73
SIGNATURES....................................................................78
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EXHIBIT (EXCERPT)
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Statement Pursuant to Private Securities Litigation Reform Act of 1995........79
<PAGE>
PART I
ITEM 1 - BUSINESS
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Northern States Power Company (the Company) was incorporated in 1909
under the laws of Minnesota. Its executive offices are located at 414 Nicollet
Mall, Minneapolis, Minnesota 55401. (Phone 612-330-5500). The Company has two
significant subsidiaries, Northern States Power Company, a Wisconsin corporation
(the Wisconsin Company) and NRG Energy, Inc., a Delaware corporation (NRG). The
Company also has several other subsidiaries, including Energy Masters
International, Inc. (EMI) (formerly known as Cenerprise, Inc.), a Minnesota
corporation; Viking Gas Transmission Company, a Delaware corporation (Viking);
and Eloigne Company, a Minnesota corporation (Eloigne). (See "Gas Utility
Operations - Viking Gas Transmission Company" and "Non-Regulated Subsidiaries"
herein for further discussion of these subsidiaries.) The Company and its
subsidiaries collectively are referred to herein as NSP.
NSP is predominantly an operating public utility engaged in the
generation, transmission and distribution of electricity throughout an
approximately 49,000 square mile service area and the transportation, storage,
and distribution of natural gas in approximately 151 communities within this
area. Viking is a regulated natural gas transmission company that operates a
500-mile interstate natural gas pipeline. NRG operates several non-regulated
energy businesses and is an equity investor in many non-regulated energy
affiliates throughout the world.
The Company serves customers in Minnesota, North Dakota and South
Dakota. The Wisconsin Company serves customers in Wisconsin and Michigan. Of the
approximately 3 million people served by the Company and the Wisconsin Company,
the majority are concentrated in the Minneapolis-St. Paul metropolitan area. In
1997, about 62 percent of NSP's electric retail revenue was derived from sales
in the Minneapolis-St. Paul metropolitan area and about 54 percent of retail gas
revenue came from sales in the St. Paul metropolitan area. (For business segment
information, see Note 15 of Notes to Financial Statements under Item 8.)
NSP's utility businesses are currently experiencing some of the
challenges common to regulated electric and gas utility companies, namely,
increasing competition for customers, increasing pressure to control costs,
uncertainties in regulatory processes and increasing costs of compliance with
environmental laws and regulations. In addition, there are uncertainties related
to permanent disposal of spent nuclear fuel. (See Management's Discussion and
Analysis under Item 7, Notes 13 and 14 of Notes to Financial Statements under
Item 8 and "Electric Utility Operations - Capability and Demand and Nuclear
Power Plants - Licensing, Operation and Waste Disposal," herein, for further
discussion of this matter.)
A significant portion of NSP's earnings comes from non-regulated
operations. The non-regulated projects in which NRG has invested carry a higher
level of risk than NSP's traditional utility businesses. (See Management's
Discussion and Analysis under Item 7 herein, for further discussion of this
matter.)
Except for the historical information contained herein, the matters
discussed in this Form 10-K, are forward looking statements that are subjects to
certain risks, uncertainties and assumptions. Such forward-looking statements
are intended to be identified in this document by the words "anticipate,"
"estimate," "expect," "objective," "possible," "potential" and similar
expressions. Actual results may vary materially. Factors that could cause actual
results to differ materially include, but are not limited to: general economic
conditions, including their impact on capital expenditures; business conditions
in the energy industry; competitive factors; unusual weather; changes in federal
or state legislation; regulation; and the other risk factors listed from time to
time by the Company in reports filed with the Securities and Exchange Commission
(SEC), including Exhibit 99.01 to this report on Form 10-K.
TERMINATION OF PROPOSED MERGER WITH WISCONSIN ENERGY CORPORATION
As discussed in the Company's Form 8-K filed on May 19, 1997, NSP and
Wisconsin Energy Corporation (WEC) announced on May 16, 1997 that they mutually
agreed to terminate their plans to merge the two companies. As a result of the
merger termination, NSP charged to expense in the second quarter of 1997 its
share of deferred merger-related costs. (See Management's Discussion and
Analysis under Item 7 herein, for discussion of the financial effects of the
merger termination.)
The Minnesota Public Utilities Commission (MPUC) required NSP to
formally request closure of the merger application docket filed with them. In
July 1997, the MPUC approved NSP's request to withdraw its merger application.
The MPUC also determined in the third quarter of 1997 that it did not need to
further pursue issues raised during the merger proceedings relating to NSP's
rates, service quality and ratemaking treatment of a contract settlement related
to a prior period.
<PAGE>
UTILITY REGULATION AND REVENUES
General
Retail sales rates, services and other aspects of the Company's operations
are subject to the jurisdiction of the MPUC, the North Dakota Public Service
Commission (NDPSC), and the South Dakota Public Utilities Commission (SDPUC)
within their respective states. The MPUC also possesses regulatory authority
over aspects of the Company's financial activities including security issuances,
property transfers within the state of Minnesota when the asset value is in
excess of $100,000, mergers with other utilities, and transactions between the
regulated Company and its affiliates. In addition, the MPUC reviews and approves
the Company's electric resource plans and gas supply plans for meeting
customers' future energy needs. The Wisconsin Company is subject to regulation
of similar scope by the Public Service Commission of Wisconsin (PSCW) and the
Michigan Public Service Commission (MPSC). In addition, each of the state
commissions certifies the need for new generating plants and 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 energy sold in interstate commerce, wheeling
rates for energy transmission in interstate commerce, the wholesale gas
transportation rates of Viking, the siting and construction of facilities by
Viking and certain other activities of the Company, the Wisconsin Company and
Viking are subject to the jurisdiction of the Federal Energy Regulatory
Commission (FERC). NSP also is subject to the jurisdiction of other federal,
state and local agencies in many of its activities. (See "Electric Utility
Operations - Nuclear Power Plants - Licensing, Operation and Waste Disposal" and
"Environmental Matters" herein.)
The Minnesota Environmental Quality Board (MEQB) is empowered to select
and designate sites for new power plants with a capacity of 50 megawatts (Mw) or
more, wind energy conversion plants with a capacity of 5 Mw or more, and routes
for 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
understand and comply with all rules and regulations issued by the various
agencies.
Revenues
NSP's financial results depend, in part, on its ability to obtain adequate
and timely rate relief from the various regulatory bodies, its ability to
control costs and the success of its non-regulated activities. NSP's 1997
utility operating revenues, excluding intersystem non-firm electric sales to
other utilities of $84 million and miscellaneous revenues of $77 million, were
subject to regulatory jurisdiction as follows:
<TABLE>
<CAPTION>
Authorized Return on Common Percent of Total
Equity @ Dec. 31,1997 1997 Revenues
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ELECTRIC GAS (Electric & Gas)
<S> <C> <C> <C>
Retail:
Minnesota Public Utilities Commission 11.47% 11.47% 75.1%
Public Service Commission of Wisconsin 11.3 11.3 14.3
North Dakota Public Service Commission 11.5 12.0** 5.4
South Dakota Public Utilities Commission * 3.1
Michigan Public Service Commission 12.25 14.5 0.5
Sales for Resale - Wholesale, Viking Gas and Interstate
Transmission: Federal Energy Regulatory Commission * * 1.6
---
Total 100.0%
=====
</TABLE>
* Settlement proceeding, based upon revenue levels granted with no specified
return.
** Reflects ROE underlying the August 1996 rate settlement.
<PAGE>
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 from various jurisdictions
were as follows (note that amounts represent annual increases (decreases)
effective in those years):
Annual Increase/(Decrease)
--------------------------
Year Requested Granted
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(Millions of dollars)
1993 166.6 101.5
1994 (1.0) (1.0)
1995 (0.8) (0.8)
1996 2.2 (2.8)
1997 --- ---
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The following table summarizes the status of general rate increases
(decreases) for rates effective in 1997:
Annual Increase/(Decrease)
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Requested Granted Status
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(Millions of dollars)
Electric:
Wisconsin-Retail No Change No Change Order Issued Nov. 26, 1996
Gas
Wisconsin-Retail No Change No Change Order Issued Nov. 26, 1996
Total 1997 Rate Programs No Change No Change
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Ratemaking Principles in Minnesota and Wisconsin
Since the MPUC assumed jurisdiction of Minnesota electric and gas rates
in 1975, several significant regulatory precedents have evolved. The MPUC
accepts the use of a forecast test year that corresponds to the period when
rates are put into effect and allows collection of interim rates subject to
refund. The use of a forecast test year and interim rates minimizes regulatory
lag.
The MPUC must order interim rates within 60 days of a rate case filing.
Minnesota statutes allow interim rates to be set using (1) updated expense and
rate base items similar to those previously allowed, and (2) a return on common
equity equal to that granted in the last MPUC order for the utility. The MPUC
must make a determination on the application within 10 months after filing. If
the final determination does not permit the full amount of the interim rates,
the utility must refund the excess revenue collected, with interest. To the
extent final rates exceed interim rates, the final rates become effective at the
time of the order and retroactive recovery of the difference is not permitted.
Minnesota law allows Construction Work in Progress (CWIP) in a
utility's rate base. The MPUC has generally included Allowance for Funds Used
During Construction (AFC) in revenue requirements for rate proceedings. However,
cash earnings are allowed on small and short-term projects that do not qualify
for AFC. (For the Company's policy regarding the recording of AFC, see Note 1 of
Notes to Financial Statements under Item 8.)
The PSCW has a biennial filing requirement for processing rate cases
and monitoring utilities' rates. By June 1 of each odd-numbered year, the
Wisconsin Company must submit filings for calendar test years beginning the
following January 1. The filing procedure and subsequent review generally allow
the PSCW sufficient time to issue an order effective with the start of the test
year. The PSCW deviated from this biennial filing requirement while the proposed
merger of NSP and WEC was pending.
The PSCW reviews each utility's cash position to determine if a current
return on CWIP will be allowed. The PSCW will allow either a return on CWIP or
capitalization of AFC at the adjusted overall cost of capital. The Wisconsin
Company currently capitalizes AFC on production and transmission CWIP at the
FERC formula rate and on all other CWIP at the adjusted overall cost of capital.
Fuel and Purchased Gas Adjustment Clauses in Effect
The Company's retail electric rate schedules, and most of the Wisconsin
Company's wholesale rate schedules, provide for adjustments to billings and
revenues for changes in the cost of fuel and purchased energy. Although the lag
in implementing the billing adjustment is approximately 60 days, an estimate of
the adjustment is recorded in unbilled revenue in the month costs are incurred.
The
<PAGE>
Company's wholesale electric sales customers do not have a fuel clause provision
in their contracts. In lieu of fuel clause recovery, the contracts instead
provide a fixed rate with an escalation factor. For eight Wisconsin Company
customers on the W-1 wholesale rate, the wholesale electric fuel adjustment
factor is calculated for the current month based on estimated fuel costs for
that month. The estimated fuel cost is adjusted to actual the following month.
The Wisconsin Company's other two wholesale customers have fixed rate contracts
which do not have a fuel adjustment factor.
In 1995, the MPUC approved a variance of Minnesota fuel adjustment
clause rules to specifically allow for the inclusion of total wind purchase
power costs and biomass related energy costs in the fuel adjustment clause. The
Company must request approval for renewal of this variance on a continuing
basis. The Company is obligated by legislative mandate to purchase 425 Mw of
wind generated energy and 125 Mw of farm-grown closed-loop biomass generated
energy by 2002. (See Note 14 to the Financial Statements under Item 8 for a
discussion of the Company's legislative resource commitments.)
The Wisconsin Company's automatic retail electric fuel adjustment
clause for Wisconsin customers was eliminated in 1986. The electric fuel
adjustment clause was replaced by a procedure which compares actual monthly and
anticipated annual fuel costs with those costs which were included in the latest
retail electric rates approved by the PSCW. If the comparison results in a
difference outside a range of eight percent for the first month, five percent
for the second month, or two percent for the remainder of the year, the PSCW may
hold hearings limited to fuel costs and revise rates. Any revised rates would be
effective until the next biennial rate case. The adjustment approved is
calculated on an annual basis, but applied prospectively. Effective Jan. 1,
1996, the fuel costs that are monitored include demand costs for sales,
purchased power and transmission wheeling expenses, which had been excluded
prior to that date.
Gas rate schedules for the Company and the Wisconsin Company include a
purchased gas adjustment (PGA) clause that provides for rate adjustments for
changes in the current unit cost of purchased gas compared to the last costs
included in rates. The factor is calculated for the current month based on the
estimated purchased gas costs for that month.
By September 1 of each year, the Company is required by Minnesota
statute to submit to the MPUC an annual report of the PGA factors used to bill
each customer class by month for the previous year commencing July 1 and ending
June 30. The report verifies whether the utility is calculating the adjustments
properly and implementing them in a timely manner. In addition, the MPUC reviews
procurement policies, cost-minimizing efforts, rule variances in effect or
requested, retail transportation gas volumes, independent auditors' reports, and
the impact of market forces on gas costs for the coming year. The MPUC has the
authority to disallow certain costs if it finds the utility was not prudent in
its gas procurement activities. On Sept. 11, 1997 the MPUC allowed full recovery
of gas costs in response to the filing for the year ended June 30, 1996. The
MPUC's determination regarding the filing for the year ended June 30, 1997 is
pending. Approval is anticipated in the latter half of 1998.
In 1996, the PSCW conducted a generic hearing to consider alternative
incentive-based gas cost recovery mechanisms to replace the current PGA. In
November 1996, the PSCW issued an order with general guidelines for
incentive-based gas cost recovery mechanisms as well as "modified one-for-one"
gas cost recovery mechanism. All major gas utilities in Wisconsin were required
to file a proposal to replace their current PGA. In September 1997 the Wisconsin
Company filed its proposal with the PSCW. In the Wisconsin Company's proposal,
allowable gas commodity cost recovery would be based on a benchmark index which
is, in turn, based on the market price of gas. The allowable cost recovery of
the remaining components of the cost of gas (for example, fixed pipeline
transportation costs, supply reservation costs, and other costs approved by the
FERC) would be based on actual costs incurred, as is the case with the Wisconsin
Company's current PGA. The PSCW's decision is expected in June 1998. If the
Wisconsin Company's proposal is approved, the financial impact of the new gas
cost recovery mechanism will be substantially the same as with the current PGA.
Approximately 70 percent of the Wisconsin Company's gas revenues represent
recovery of gas costs through the PGA mechanism.
The Wisconsin Company's gas and retail electric rate schedules for
Michigan customers include Gas Cost Recovery Factors and Power Supply Cost
Recovery Factors, which are based on 12 month projections. After each 12 month
period, a reconciliation is submitted whereby over-collections are refunded and
any under-collections are collected from the customers. For 1997 the Gas Cost
Recovery Factor was in place; however, the Power Supply Cost Recovery (PSCR)
factor was waived in 1997 due to the proposed merger with WEC. The PSCR was
reinstated effective in 1998 as discussed under "Rate Matters by Jurisdiction".
Viking provides interstate gas transportation services only through its
pipelines 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 by
transportation service customers. On Feb. 27, 1998 Viking filed to
<PAGE>
increase its fuel retention rates to reflect current compressor operations, to
be effective April 1, 1998.
Resource Adjustment Clauses in Effect
In 1995, the MPUC approved the implementation of an annual recovery
mechanism for electric and gas conservation and energy management program
expenditures, including annual gas program costs and an amortization of electric
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. This decision allows for accelerated recovery of
conservation and energy management program expenditures which is desirable
because it allows more timely rate recovery of cost changes outside general rate
cases and lessens the risk for future stranded costs resulting from electric
industry restructuring. A surcharge to customer's bills is included as a line
item entitled "resource adjustment". The Company is required to request a new
cost recovery level annually. Current cost recovery levels were approved
effective in July 1997 for electric and September 1996 for gas. The 1997
proposed gas change (filed May 1, 1997) is pending final MPUC action.
In January 1996, a number of changes to the Company's regulatory
deferral and amortization practices for Minnesota electric conservation program
expenditures were approved. These changes allow the Company to expense rather
than defer and amortize new conservation expenditures beginning in 1996 and to
increase its recovery of electric margins lost due to conservation activity.
These conservation cost recovery changes are intended to avoid a significant
delay between the time when costs are incurred and when they are recovered in
rates. In addition, the Company received approval for 1996 and 1997 conservation
expenditures at levels lower than 1995. In 1997, the Company received approval
to further reduce electric conservation expenditure levels in 1998 and 1999 to 2
percent of Minnesota revenues, the minimum allowed by current Minnesota law.
Rate Matters by Jurisdiction
MINNESOTA PUBLIC UTILITIES COMMISSION (MPUC)
On Dec. 2, 1997 the Company filed for a general increase in gas retail
rates in the state of Minnesota. The Company requested an annualized increase of
$18.5 million or 5.5 percent. The Company requested an interim annualized rate
increase of $15.6 million or 4.6 percent effective Feb. 1, 1998. An interim rate
increase totaling $13.9 million on an annual basis has been approved, subject to
refund, effective Feb. 1, 1998. If the final rate level is less than the interim
rate level, the difference will be refunded to customers with interest. The MPUC
has ten months from the date of the filing to reach a decision on the Company's
rate increase request.
Since 1995, the Company has offered, with MPUC approval, a 50 percent
discount on the first 300 kilowatt-hours (Kwh) consumed each month by qualified
low-income residential customers. These low-income discounts are recovered from
other customers.
Approximately 33,000 of the Company's customers received assistance,
totaling $7.5 million for the 1996-97 heating season, from federally funded Low
Income Home Energy Assistance Programs (LIHEAP) operated by the State of
Minnesota. Other states served by NSP have similar programs. Qualification for
the Company's Low Income Discount Rate is based on eligibility for LIHEAP. The
federal LIHEAP program is facing some opposition and funding could be lost in
the future. In a January 1998 agreement with the Minnesota Office of the
Attorney General, the Company has agreed to provide up to $2.8 million in
supplemental grants over the next three years to NSP customers receiving aid
from the LIHEAP program.
Gas utilities in Minnesota are required to file for a change in gas
supply contract levels to meet peak demand, to redistribute demand costs among
classes, or exchange one form of demand for another. The Company filed in
October 1996 to increase its demand entitlements due to projected increases in
firm customer count, to decrease the Minnesota jurisdictional allocation of
total demand entitlements, effective Nov. 1, 1996, and to recover the demand
entitlement costs associated with the increase in transportation and storage
levels in its monthly PGAs. In February 1997, the MPUC approved NSP's 1996-97
entitlement levels. In October 1997, the Company filed for approval of its
1997-98 demand entitlements. This filing is pending MPUC approval.
In 1995, the MPUC initiated a rulemaking process to amend, repeal, or
replace existing rules governing customer service standards for gas and electric
utilities. The MPUC formed an advisory task force representing interests from
electric and gas utilities, low and fixed-income consumer advocate groups, other
Minnesota State agencies and other various rate payer classes. The ultimate
outcome of the rulemaking process is unknown at this time. The task force
currently is not actively meeting.
In response to customer requests and concerns, the Company initiated
several changes and clarifications to its tariff options through miscellaneous
filings in 1997. In February 1998, the MPUC approved the Company's "group
billing" proposal, which will allow customers with multiple accounts (e.g.,
municipalities, fast food restaurants, chain stores, etc.) to receive a single
aggregated bill.
<PAGE>
In November 1997, the MPUC approved the Company's gas Predictable Commodity
Price Service, which allows eligible customers to elect a gas service option
with a predetermined price for an annual period, rather than traditional pricing
which varies from month to month based on current wholesale gas prices.
On Oct. 9 1997, the MPUC voted to approve NSP's request for fuel clause
adjustment (FCA) treatment for costs incurred under the gas supply management
agreement between NSP Gas and NSP Generation (two business areas within NSP).
NSP's electric utility will recover approximately $2 million under the FCA, and
NSP Gas will earn approximately $20,000 in margin. The MPUC deferred any
decision on the issue of whether a transaction between business units within the
same utility corporation is an affiliated interest agreement under the 1993
amendments to Minnesota statute 216B.48.
No electric general rate filing is anticipated in Minnesota in 1998.
NORTH DAKOTA PUBLIC SERVICE COMMISSION (NDPSC)
In its August 1996 order approving the Company's North Dakota base rate
adjustment, the NDPSC also opened an investigation to examine gas cost of
service allocations and rate design criteria for the Company. In May 1997, the
NDPSC voted to close this investigation. The NDPSC did not order any cost
allocation or rate design changes, but encouraged NSP to file new tariffs to
increase the availability of transportation-only services to more classes of
customers.
No general rate filings are anticipated in North Dakota in 1998.
SOUTH DAKOTA PUBLIC UTILITIES COMMISSION (SDPUC)
Coincident with initial natural gas deliveries, NSP filed a request
with the SDPUC on Dec. 16, 1997 for a declaratory order establishing NSP as a
regulated gas utility in South Dakota. Included in the filing is also a request
for approval of initial large volume retail intrastate gas transportation rates.
NSP has not previously provided natural gas service in South Dakota.
In August 1997, Hutchinson Technologies, Inc. (HTI) chose NSP to
provide gas service, in addition to electric service, to its new 700 employee
facility in Sioux Falls, South Dakota. NSP tapped the Angus C. Anson combustion
turbine gas supply line and constructed a 3.5 mile 4 inch diameter steel
pipeline to the Sioux Empire Development Park 5 and the new HTI facility. NSP
will provide natural gas transportation service. Gas supply arrangements will be
made by the customer. HTI transportation revenues will not be material. However,
the Company will work to expand its South Dakota gas operations in the future.
No general rate filings are anticipated in South Dakota in 1998.
PUBLIC SERVICE COMMISSION OF WISCONSIN (PSCW)
To facilitate its review of the Wisconsin Company's application to
merge with WEC, in 1995 the PSCW deviated from its normal biennial rate case
filing requirements and directed the Wisconsin Company to file complete electric
and gas rate cases in early 1996 for the test year beginning January 1, 1997.
On March 15, 1996, the Wisconsin Company filed a full rate case for the
1997 test year on a stand alone basis as requested by the PSCW. The Wisconsin
Company's filing described revenue deficiencies for both electric and gas
utilities. However, no rate increases were requested. Technical hearings for the
Wisconsin Company's electric and gas rate cases were held before the PSCW on
July 8, 1996. On Nov. 26, 1996, the PSCW issued an order approving the Wisconsin
Company's application for no change in rates. However, certain classes of
customers experienced small changes in rates as a result of rate design
revisions requested by the Wisconsin Company. These changes to electric rates
for certain customers classes had an offsetting effect on overall revenues.
There were no significant changes to gas rates. In its order, the PSCW approved
a capital structure composed of 45 percent debt and 55 percent common equity,
and granted an 11.3 percent return on common equity.
On June 9, 1997 the Wisconsin Company 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 the Company's current rates due to unplanned
and extended outages at the Company's nuclear generating stations and higher
than projected costs to transmit electricity purchased from other utilities to
the Wisconsin Company's service territory. Effective Sept. 25, 1997, the PSCW
authorized the Company to charge a fuel cost surcharge of $0.00043 per Kwh to
all Wisconsin retail electric customers, which produced approximately $574,000
of additional electric revenue in 1997. The surcharge represents less than one
percent of current rates and is the first rate increase requested since January
1993. The surcharge will continue in effect on an interim basis until the next
rate order is issued and is subject to refund pending final PSCW review.
The Wisconsin Company filed retail electric and gas rate cases with the
PSCW on Nov. 14, 1997
<PAGE>
for the test year 1998. The Wisconsin Company requested a 4.3 percent increase,
approximately $12.7 million annually, in retail electric rates and a 1.9 percent
or $1.7 million decrease in retail gas rates. The Wisconsin Company has
requested that these changes take effect during the second quarter of 1998. The
electric rate filing includes a request for recovery of network transmission
service costs of which $1.7 million had been deferred at Dec. 31, 1997 as
approved by the PSCW.
MICHIGAN PUBLIC SERVICE COMMISSION (MPSC)
In August 1997, the MPSC approved the Wisconsin Company's application
to reinstate a PSCR factor for Michigan electric customers in 1998. On Sept. 29,
1997, the Wisconsin Company filed its request for a 1998 PSCR factor of $.00172
per Kwh which would produce about $250,000 of additional revenue in 1998.
There were no changes in the Michigan electric and gas base rates
during 1997. The Wisconsin Company is currently reviewing the need to file for a
change in Michigan rates in 1998.
OPEN ACCESS TRANSMISSION PROCEEDINGS (FERC)
In April 1996, the FERC issued two final rules, Order Nos. 888 and 889,
which have had a significant impact on wholesale electric markets by giving
competitors the ability to transmit electricity through utilities' transmission
systems. Order No. 888, which was effective on July 9, 1996, granted
nondiscriminatory open access to transmission service to promote wholesale
competition and requires utilities and other transmission users to abide by
comparable terms, conditions and pricing in transmitting power. Order No. 889,
effective Jan. 3, 1997, requires public utilities to implement Standards of
Conduct and use an electronic bulletin board called Open Access Same Time
Information System ("OASIS", formerly known as "Real-Time Information
Networks"). These rules require transmission system operation personnel to
provide the same information about the transmission system to all transmission
customers using the OASIS, and required separation of the wholesale power supply
("merchant") function from the transmission system operation function.
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. A new proposed rule on Capacity Reservation Open Access Transmission
Tariffs also was issued in April 1996. This proposed rule requested comments on
a new proposed tariff to be in effect no later than Dec. 31, 1997. The FERC has
since postponed this rulemaking indefinitely.
With regard to compliance with the first phase of FERC Order No. 888,
in July 1996, NSP submitted its transmission tariff compliance filing and an
information filing that unbundled the transmission component of the full
requirements municipal wholesale customers' rates. In October 1996, in response
to the final rule, NSP filed the FERC Order No. 888 proforma tariff using the
rates from the NSP tariff, approved in February 1996. The tariff approved in
February 1996 complies with the transmission pricing policies provisions of open
access requirement of the Energy Policy Act of 1992 which calls for
comparability of service and pricing, network service, an unbundling of
ancillary charges such as scheduling and load following. With regard to the
second phase, in December 1996 NSP submitted its compliance filing which
unbundled the transmission component of its coordination agreements. For
transactions under these agreements, these customers became NSP transmission
service customers. In October 1996, the FERC accepted NSP's information filing.
NSP also is taking steps to comply with FERC Order No. 889, including
submission of the requisite Standards of Conduct filing in January 1997 and
training employees on these standards in January 1997. In 1997, NSP separated
personnel who perform the merchant function, which includes power and energy
marketing and trading, from personnel who perform the transmission system
operation function. In addition, a significant effort was put forth in 1997 to
enter current and all new requests for transmission service into the electronic
bulletin board. In December 1997, the FERC issued an order clarifying issues
regarding FERC Order No. 889 standards of conduct. On Feb. 12, 1998, the FERC
issued an order requiring modifications to NSP's January 1997 Standards of
Conduct compliance filing, including requirements for additional separation of
functions. NSP submitted revised standards on March 16, 1998. NSP continues to
be generally supportive of the FERC's efforts to increase competition.
ELECTRIC TRANSMISSION TARIFFS (FERC)
On Feb. 17, 1998, the Company and the Wisconsin Company jointly filed a
Section 205 wholesale transmission rate case with the FERC requesting changes to
its point-to-point Open Access Transmission Tariff (Tariff). The requested
Tariff is based largely on the pro forma tariffs included in the FERC's Order
No. 888. Rates requested are based on a projected test year consisting of 1998
budget data, and included updated rates, proposing an 11 percent increase, for
firm point-to-point transmission service. The request, if approved, would
increase transmission revenues approximately $3 million annually. In addition,
the nonfirm point-to-point maximum rate would decrease by approximately eight
percent under the proposed tariff. Because NSP's present transmission rates are
based on a
<PAGE>
1992 historical test year, the major reason for the increase is additional
transmission investment capitalized since 1992. NSP has requested rates to
become effective May 1, 1998, subject to refund. FERC action is pending.
In addition, the filing includes new rates for the six ancillary
services required by FERC Order No. 888. If approved, these new rates will
result in additional revenues of approximately $1 million annually. The terms
and conditions in the proposed tariff are largely unchanged from the Order 888
proforma tariff. The rate changes will affect transmission service prices to
most wholesale transmission customers, including municipals, cooperatives and
utilities who buy electric supply from NSP. It will also affect the prices
utilities and power marketers pay for using NSP's transmission lines to transmit
power across NSP's system. Such power marketers include: the Company's new
merchant power marketing arm, NSP Energy Marketing, which sells NSP's surplus
energy; and a subsidiary of NRG, which received power marketing approval from
the FERC in 1997.
On March 2, 1998, the Company and the Wisconsin Company also filed a
separate Section 205 rate change to the Network Integration Transmission Service
(NTS) provisions of NSP's Tariff. NSP requested a May 1, 1998 effective date.
Under the FERC Order No. 888, NSP is required to offer, among other services,
NTS service to qualifying customers, who are neighboring non-jurisdictional
electric utilities (primarily cooperative or municipal utilities) who own
transmission facilities within the NSP electrical control area. Under NTS, NSP
and other qualifying regional utilities share the total annual costs of
operating and maintaining the regional transmission network that NSP uses, net
of related network revenues, based on each company's share of the total network
load. The transmission tariff filed with the FERC is used as the cost basis for
FERC-regulated utilities in determining NTS rates. NSP expects that the new
Tariff changes, if approved, and settlement negotiations will result in lower
NTS costs in 1998. (For more information on NTS, see Management's Discussion and
Analysis under Item 7 herein.)
ELECTRIC UTILITY OPERATIONS
Competition
NSP's electric sales are subject to competition in some areas from
municipally owned systems, rural cooperatives and, in certain respects, other
private utilities and independent power producers. Electric service also
increasingly competes with other forms of energy. The degree of competition may
vary from time to time, depending on relative costs and supplies of other forms
of energy. Although NSP cannot predict the extent to which its future business
may be affected by supply, relative cost or promotion of other electricity or
energy suppliers, NSP believes it will be in a position to compete effectively.
In October 1992, the President signed into law the Energy Policy Act of
1992 (Energy Act). The Energy Act amends the Public Utility Holding Company Act
of 1935, as amended (PUHCA) and the Federal Power Act. Among many other
provisions, the Energy Act is designed to promote competition in the development
of wholesale power generation in the electric utility industry. It exempts a new
class of independent power producers from regulation under the PUHCA. The Energy
Act also allows the FERC to order wholesale "wheeling" by public utilities to
provide utility and non-utility generators access to public utility transmission
facilities. The provision allows the FERC to set prices for wheeling, which will
allow utilities to recover certain costs. The costs would be recovered from the
companies receiving the services, rather than the utilities' retail customers.
The FERC Orders No. 888 and 889 (as discussed in "Utility Regulation and
Revenues", herein) reflect the trend toward increasing transmission access under
the Energy Act.
As discussed previously, 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. In 1997, NSP's merchant function, NSP Energy
Marketing, expanded its power trading to focus on new market opportunities
created by open transmission access. NSP Energy Marketing performs power and
energy marketing (both sales and purchases). The sales and revenue provided by
this function includes what NSP is currently classifying as sales for resale,
which includes both municipal power sales and sales to other utilities. 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 connection with its wholesale
power and energy sales.
NSP's merchant function includes sales to municipal power supply
customers, which was formerly referred to as wholesale sales. The municipal
power supply market has continued to be competitive. Rate discounts and
negotiated rates are being offered to current and potential municipal power
supply customers to allow the municipals to prepare themselves for competition.
NSP has attracted new customers and is retaining customers through this
strategy. In the past several years, these customers have been evaluating a
variety of energy sources to provide their electric supply. NSP's revenues from
sales of electrical power and energy to municipal power supply customers totaled
approximately $23 million in 1997, $29 million in 1996 and $44 million in 1995.
The reduction in revenues is attributed mainly to the nine municipal
<PAGE>
power supply customers whose contracts terminated in 1995 and 1996. These nine
customers remain transmission service customers. The Company currently has nine
municipal power supply customers and the Wisconsin Company has ten municipal
supply customers. All ten municipal power supply customers have current power
supply arrangements and are expected to purchase the majority of their power
supply requirements from the Wisconsin Company.
Even though NSP has contracts with several municipal power supply
customers, because of competition in the sales for resale markets, NSP will need
to continue to be competitive in the entire wholesale market as many parties,
including power marketers, are now able to use its transmission lines to
transport electricity. In 1997, NSP filed 61 transmission service agreements for
FERC approval. In 1996, this number was 58. Currently, 76 customers, including
power marketers (independent brokers who buy and sell wholesale electricity as a
commodity at market prices), and NSP's Energy Marketing area, were registered to
buy transmission service from NSP. NSP still has the first right to use its
transmission system for sales to retail customers. NSP has also reserved the
right to use its transmission system to serve its firm (guaranteed delivery)
municipal power customers. But for non-firm (delivery subject to utility's
discretion to curtail without liability) wholesale transactions, NSP Energy
Marketing must compete with others to use the NSP transmission system. The
process of making a wholesale energy sale is now much more detailed, but the
sale can also now be contingent upon the availability of transmission service.
NSP is no longer competing with only regional utilities when it buys
and sells excess power to wholesale customers, but is also competing with power
marketers from all over the United States. As more participants join this
market, margins are driven down. NSP is developing its wholesale power marketing
capabilities to compete on a national basis and not risk losing customers and
declining margins. NSP is also developing risk management practices to respond
to the rapidly growing electric commodity market.
Some states, such as Michigan in which NSP has service territory, 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 believes competition among suppliers to serve retail customers
will result in more innovative services and lower prices for all consumers if
the transition is managed in a thoughtful manner. 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. Currently, NSP pays property taxes in Minnesota
that are two to three times higher than they would be in neighboring states, and
investor-owned utilities also pay taxes that are significantly higher 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.
In Minnesota, the MPUC developed and adopted principles for electric
industry restructuring. One of the principles supports the establishment of a
robust competitive wholesale market. As a follow-up to the principles, the MPUC
convened the Electric Competition Workgroup, which included NSP, to examine
possible changes in industry regulation and structure to foster wholesale
competition. In 1996, the MPUC accepted the workgroup's report and expanded its
charter to examine issues related to retail competition. In 1997, the MPUC
accepted the retail competition report and ordered their staff to prepare a plan
to address the issues identified in the report in response to a hypothetical
legislative mandate to open up retail access. To date, the MPUC staff has not
yet submitted the plan to the MPUC.
Minnesota's Governor and legislative leadership have indicated that
electric utility restructuring will not be a priority in the 1998 session.
Nevertheless, legislative hearings on the issue were held in 1997. At the end of
the hearings, the joint House and Senate subcommittee decided that they needed
more technical information before making a policy recommendation to the full
legislature. Currently, two versions of an electric industry restructuring study
bill have passed the Senate and the House subcommittees and are being reviewed
for consolidation. Both bills would establish a Technical Advisory Work Group
composed of a wide range of stakeholders to examine, over a several month
period, a set of technical issues including reliability, consumer protections
and level playing field issues. Passage of a final version is expected sometime
in April 1998.
In February 1996, the PSCW issued its report to the state legislature
on restructuring the electric industry. The report was the culmination of over a
year of work by representatives from a wide range of interests, including low
income advocates, environmental groups, regulators and the utilities. NSP played
an active role in the efforts. Key elements of the report include: 1) unbundling
the vertically-integrated utility functions into generation, transmission,
distribution and energy services; 2) improving competition in electric
generation while insuring consumer access to the low costs associated with
existing power plants; 3) preventing the exercise of market power by large
companies; 4) revising Wisconsin's regulatory processes while protecting the
environment; 5) working to transform the transmission system into a common
carrier; 6) developing distribution and retail service
<PAGE>
requirements and 7) developing alternative means for funding and providing
social benefits to customers. The report included a 32 step plan to achieve
these elements with the ultimate goal of opening the retail market to
competition by the year 2001. The PSCW began implementing the 32 step plan in
1996. In September 1996, the PSCW issued an order setting minimum standards for
creating an independent system operator (ISO) for the electric transmission
system of NSP. This order was issued as part of a generic electric utility
restructuring process the PSCW started in 1995. As of the end of 1996, parties
had filed plans with the PSCW to unbundle utility functions; completed hearings
on revising the State's Advance Plan and Certificate of Public Convenience and
Necessity processes; developed proposals regarding the funding and delivery of
low income, energy efficiency, renewable resource and environmental research
services; and began to work on initial distribution and retail service
requirements.
After receiving comments on the restructuring work plan in July 1997,
the PSCW consolidated the 32-step work plan into a 7-step work plan. However,
due to the summer of 1997's electrical reliability concerns in eastern
Wisconsin, the PSCW indicated that industry restructuring efforts be subordinate
to, and compatible with, reliable electric supply. The PSCW maintains that the
development of a strong ISO remains of a primary importance to retail
competition. As a result of the reliability issue in 1997, the PSCW has
indicated it intends to focus on the development of a utility infrastructure
necessary to assure reliable electric service and the removal of barriers to
competition at the wholesale level first. In late 1997, the PSCW stated that
although many parties have concluded that retail competition is a foregone
conclusion, the PSCW never indicated that retail competition was inevitable, nor
that it was in the public interest. At present, a definite timeline has not yet
been established for the implementation of retail competition in Wisconsin.
In March 1998, the Governor of Wisconsin proposed reliability
legislation that, if enacted, will make dramatic changes in the state's energy
industry and take a number of steps toward industry restructuring. This proposal
will streamline the state's regulatory process and authorize some form of a
merchant plant market. This proposal will also require, prior to June 30, 2000,
transmission system owners to either transfer control of transmission system
assets to an ISO or divest of assets to an independent transmission owning
entity. NSP cannot predict the final contents of any such legislation or
ultimate impact on NSP.
In North Dakota, the NDPSC, in 1997, 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 this issue.
Also in North Dakota, the 1997 legislative session established a
committee of six legislators charged with studying the impact of competition on
the electric industry. By statute, the committee has a six-year time frame to
study the impact of competition on the generation, transmission and distribution
of electric energy in the state. To date, there has been no legislation drafted
and no consensus on the need to change the current environment.
On Jan. 14, 1998, the MPSC issued an order regarding electric retail
competition. The MPSC concluded that all customers who want to participate in
open access should have the opportunity to do so and that those customers who do
not participate should not pay higher rates because of open access. The order
directed the large Michigan utilites to make 2.5 percent of their electric load
eligible for open access in each year from 1997 through 2001. All remaining
Michigan electric customers would be given access in 2002. It also stated that
the phase-in schedule applied to all customer classes, a bidding process would
be used to allocate the open access capacity, loads of less than one Mw would be
allowed to participate through an aggregator, and that prudently incurred
stranded costs would be recovered. This order was unsuccessfully challenged by
the affected Michigan utilities, and the courts upheld the MPSC's authority to
implement retail competition.
In July 1996, NSP executed a long term electric service contract with
one of its largest electric customers, Koch Refining Company. Previously, Koch
had planned to construct a 180 Mw cogeneration plant, leave the NSP retail
system, and sell its excess electricity supply in the wholesale market in
competition with NSP. Under the agreement, Koch will remain an NSP retail
customer, and will participate in NSP's electric supply bidding process before
constructing any new generating plant. The agreement complies with a Minnesota
law enacted in 1996. NSP filed for MPUC approval of the agreement in September
1996. In early 1997, the MPUC ruled the agreement is consistent with the statute
but deferred action on cost recovery until the Company's next electric general
rate case.
In June 1996, the City Council for the City of St. Paul, Minnesota (the
City), approved new ten year electric and natural gas franchise agreements
between NSP and the City. Under Minnesota law,
<PAGE>
utilities are required to obtain franchises from the municipalities where they
serve. In the new agreements, NSP and the City agreed to a "unit charge"
mechanism where the City's franchise fee is collected on the units of energy
(Kw, Kwh or CCF) of electricity or gas delivered by NSP regardless of the
supplier. The new fee structure will generate about the same total fee revenue
for the City each year, but is "supplier neutral" and will not create uneconomic
price incentives for customers to leave the NSP system. To NSP's knowledge, the
new St. Paul franchise agreements are the first in the United States where all
utility franchise fees are collected on a unit of delivery basis.
NSP has proposed to fill future needs for new generation through
competitive bid solicitations. The use of competitive bidding to select future
generation sources allows the Company to take advantage of the developing
competition in this sector of the industry. The Company's proposal, which has
been approved by the MPUC allows NRG and NSP's own generation business unit to
bid in response to Company solicitations for proposals. The PSCW also allows
this process through the granting of waivers.
Retail competition represents yet another development of a competitive
electric industry. Management plans to continue its ongoing efforts to be a
low-cost supplier of electricity and an active participant in the more
competitive market for electricity expected in the future. NSP will continue to
work with regulators to complete the tariff and infrastructure that will support
an electric competitive environment. Additional actions the Company is pursuing
to position itself for the competitive environment include: creative partnership
solutions with strategic customers including communities; focusing on the unique
needs of national account customers; competitive pricing alternatives; improved
reliability; implementation of service guarantees; ease of customer access,
including 24 hour, seven days per week operation; metering automation; and
centralization of common services and aggressive cost management. In addition,
NSP will compete for service outside its traditional service area. This process
has begun via NSP's NRG and EMI subsidiaries.
Technological Improvements
In order 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, the Company implemented a new customer service system that supports
customer information and billing. NSP is also making modifications to its
computer software and other technology to address the year 2000 issues. (See
Management's Discussion and Analysis under Item 7 herein, for further discussion
of the year 2000 changes.)
In 1996, the Company implemented a "feeder management system", which is
part of NSP's electric distribution automation effort, that allows NSP to
monitor, control and communicate with and make better decisions about its
electric distribution system. It allows NSP to perform engineering studies
quickly, thus customers out of service can be restored faster. It also assists
NSP in using its capacity and avoid damaging equipment. This system is
interfaced with a new energy management system, which controls NSP's electric
transmission, distribution and generation facilities, and became fully
operational in 1997, improving system performance and customer service. This
system is also assisting NSP to comply with FERC Order Nos. 888 and 889, as
discussed previously, and to compete in the changed environment as a result of
these orders.
In 1997, NSP also implemented a portion of 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. Additions, changes and
deletions are done quickly and efficiently after construction, thereby making
the maps as current as possible. GIS will assist NSP in the design of
construction projects and services. Current and accurate information will be
available on-line. This is critical in NSP's daily operations, not only for the
productivity and safety of its construction crews, but for the improved quality
of service NSP can provide to its customers. NSP expects to complete
implementation in 1998.
Also in 1997, NSP began installing a wireless automated meter reading
system that will allow the Company to remotely read customer meters in the
Minneapolis - St. Paul metro area every month which will almost eliminate
estimated customer bills. The project, Automated Energy Services (AES), is
designed to improve customer service in the Minneapolis - St. Paul metro area.
More than one million electric and gas meters are expected to be automated by
the year 2000. As part of the AES project, NSP has contracted with an affiliate
of CellNet Data Systems, Inc. (CellNet), a company based in San Carlos,
California, 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.
Capability and Demand
Assuming normal weather, NSP expects its 1998 summer peak demand to be
7,427 Mw. NSP's 1998 summer capability is estimated to be 8,775 Mw, (net of
contract sales) including 903 Mw (including reserves) of contracted purchases
from the Manitoba Hydro-Electric Board, a Canadian Crown
<PAGE>
Corporation (Manitoba Hydro) and 724 Mw of other contracted purchases. The
estimate assumes 7,460 Mw of thermal generating capability and 1,315 Mw of
renewable source generating capability. Of the total summer capability, NSP has
committed 186 Mw for sales to other utilities.
NSP's 1997 maximum demand of 7,353 Mw occurred on July 16, 1997.
Resources available at that time included 7,117 Mw of Company-owned capability
and 1,706 Mw of purchased capability net of contracted sales. Due to the
Mid-Continent Area Power Pool's (MAPP) penalty for reserve margin shortfalls and
to be prepared for weather uncertainty at the lowest overall cost, NSP carried a
reserve margin for 1997 of 19.7 percent. The minimum reserve margin requirement
as determined by the members of the MAPP, of which NSP is a member, is 15
percent. In March 1996, the members of MAPP approved a proposal to convert MAPP
into a Regional Transmission Group (RTG). As a result of this approval, a
restated agreement, "Restated Mid-Continent Area Power Pool Agreement Jan. 12,
1996" was approved by the FERC in Docket No. ER96-1447, effective Nov. 1, 1996.
Converting MAPP to an RTG is consistent with the 1992 Energy Policy Act and FERC
policies. (See Note 14 of Notes to Financial Statements under Item 8 for more
discussion of power agreement commitments.)
In November 1997, MAPP provided to members drafts of its revised
restated agreement indicating the changes necessary to accommodate an ISO, and a
Transmission System Control Agreement through which transmission owners would
give up operational authority of their Regional Transmission Facilities to the
MAPP ISO. Some of the provisions include governance structure of the ISO, with a
nine-member board of directors, new bylaws and a code of conduct. In addition,
the MAPP Regional Transmission Committee (RTC) would be responsible for
establishing the ISO as a non-profit membership corporation. An advisory group
would be formed under the RTC to provide technical advice, review disputes
between the ISO and members, and to make recommendations to the RTC. A vote by
MAPP members is expected by mid-1998. The proposal would be filed with the FERC
after the vote. NSP is considering alternatives to ISOs including the formation
of an independent transmission company.
In October 1997, officials from MAPP and the Southwest Power Pool (SPP)
met to coordinate the investigation of a possible consolidation of the two
regions. SPP, based in Little Rock, Arkansas, consists of 72 members that serve
more than 6.6 million customers in all or part of eight southwestern states. The
group identified functional areas to be investigated for possible consolidation:
ISO filing, tariff administration, engineering, information technology,
operations, training, policy and administration. The group has provided a
written report to the regional governing bodies who will vote on the
recommendations in April 1998.
The Company, in conjunction with the Wisconsin Company and LaCrosse,
Wisconsin - based Dairyland Power Cooperative (DPC), proposes to construct,
operate and maintain 230- and 115- kilovolt (Kv) transmission line 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 future widespread blackouts in northwestern Wisconsin. The 230-Kv line
would run from a substation in eastern Minnesota, cross the St. Croix River and
terminate near Amery, Wisconsin. The 115-Kv line would end near Taylors Falls,
Minnesota. The proposal also includes a 161-Kv line between Hayward and Ashland,
Wisconsin. The project needs review and approval by the MEQB, PSCW and Rural
Utilities Services. The major issue is the location and aesthetics of crossing
the St. Croix River, which is a designated National Scenic Riverway. Assuming
regulatory approvals, the companies expect the project to be in service by 2003.
The Company is continuing an extensive performance-based transmission
and distribution reliability program. This program includes preventative
maintenance on transmission and distribution power lines, improvements to
existing equipment and implementation of new technology. The Company has
invested more than $350 million in transmission facility upgrades since 1992.
The program focuses on the leading causes of outages consisting of lightning,
trees and underground cable cuts, and also concentrates on reducing the number
of human-error related outages. In 1997, the reliability program resulted in a
17 percent reduction in the total number of non-storm related outages to the
Company's feeders, from 1,696 in 1996 to 1,409 in 1997, a new record low. In
addition, outages to critical customer sites remained steady and maintained the
low average achieved in 1996, allowing the Company to exceed its 1997 year end
goal. Reliability goals for 1998 include emphasis on reliability-focused
maintenance programs, improved restoration processes, and improved customer
communication/access.
The Company filed its most recent Resource Plan with the MPUC on Jan.
5, 1998, for the period 1998 to 2012. The plan shows how the Company intends to
meet the increased energy needs of its electric customers and includes an
approximate schedule of the timing of resource solicitation to meet such needs.
The plan contains conservation programs to reduce the Company'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.
<PAGE>
In summary, the plan:
* Forecasts slower growth in energy and peak demand requirements. The
plan forecasts 1.7 percent growth in NSP's energy and peak demand
requirements, which is down from the 2.9 percent growth NSP experienced
in 1985 to 1995.
* Outlines NSP's efforts to continue to help our customers use
electricity wisely through demand side management and conservation
programs.
* Shows a need for 140 Mw of new capacity in 2003. NSP will use a
competitive bid process to acquire the capacity.
* Describes the programs for achieving the mandated renewable energy
sources of 425 Mw of wind and 125 Mw of biomass. NSP's program is the
largest commitment to renewables in the region. NSP recommends no new
commitments to renewables.
* 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 following resource needs were identified in the Resource Plan
filing:
Cumulative Mw Resource Needs By Type vs. Base of 1997
2000 2004 2008 2012
------- --------- ----------- ----------
Renewables* 0 160 (32) 160 (32) 160 (32)
Peak 0 0-500 500-1,000 600-1,300
Intermediate 0 0-500 400-600 500-700
Base 0 0 0-800 300-1,600
Demand Side Management 352 697 994 1,243
Total 0-352 729-1,729 1,926-3,426 2,675-4,875
* Renewables include wind generation and biomass generation. The 1994 Minnesota
legislative mandates related to these are discussed in Note 14 to the Financial
Statements under Item 8 and "Electric Utility Operations - Nuclear Power Plants
- - Licensing, Operation and Waste Disposal," herein . The Company considers 265
Mw of the 425 Mw windpower mandate and all 125 Mw of the biomass generation
mandate to be committed capacity. (Including 25 Mw of windpower which was
installed in 1994.) The amounts shown in parentheses are the estimated MAPP
accredited capacity values at the time of system peak demand. The MAPP
accreditation procedure for wind is intended to measure wind generation's
contribution to system reliability at the time of system peak demand. Because
wind generation is a variable resource, the accredited capacity is less than the
installed capacity.
================================================================================
The resource plan proposed to satisfy the above resource needs through
a combination of the following energy source options:
- - Continued operation of existing generation facilities.
- - Demand reduction of an additional 1,080 Mw by 2012 through conservation
and load management.
- - 425 Mw of wind energy and 125 Mw of biomass energy under contract by
2002.
- - Acquisition of competitively priced resources to meet changing needs,
i.e. competitive bidding.
The Resource Plan also included an update of the Company's competitive
bid schedule. The Company plans to seek proposals as follows:
Proposal Resource Nominal In-Service
Date Type Amount Date
- ----------------------------------------------------------
1998 Mandated 160 Mw Year-End
Wind 2002
1999 All-Source with 100-1,200 Mw 2003-2005
Flexibility Options
2000 All-Source with 300-1,200 Mw 2004-2006
Flexibility Options
2001 All-Source with 200-1,100 Mw 2005-2007
Flexibility Options
and Contingent Bid + 1,100 Mw
2002 All-source with 200-500 Mw 2006-2008
Flexibility Options
2003 All-source with 200-500 Mw 2007-2009
Flexibility Options
The resource plan is now subject to public review and comment. The
Company expects that the
<PAGE>
MPUC will probably take action in early 1999, to approve or modify the plan.
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. NSP, along with several other
parties, participated in a proceeding initiated by the MPUC to establish such
values. The MPUC issued its order in January 1997. The high end of the range of
externality values ordered by the MPUC add about 0.55 cents per Kwh to a typical
new coal plant and about 0.15 cents per kwh to a natural gas fired plant. The
carbon dioxide value comprises about 60 percent to 80 percent of these amounts.
On Feb. 24, 1998, NSP and several other parties argued their appeal of the MPUC
order before the Minnesota Court of Appeals, which will rule on the appeal
within 90 days.
NSP continues to implement various Demand Side Management (DSM)
programs designed to improve load factor and reduce NSP's power production cost
and system peak demands, thus reducing or delaying the need for additional
investment in new generation and transmission facilities. NSP currently offers a
broad range of DSM programs to all customer sectors, including information
programs, rebate and financing programs and rate incentive programs. These
programs are designed to respond to customer needs and focus on increasing NSP's
value of service that, over the long term, will help its customer base become
more energy efficient and competitive. During 1997, NSP's programs reduced
system peak demand by approximately 130 Mw. Since 1982, NSP's DSM programs have
reduced system peak demand by approximately 1,284 Mw, which is equivalent to 17
percent of its 1997 summer peak demand. In its 1997 Conservation Improvement
Program Filing with the Minnesota Department of Public Service, the Company
received approval to reduce its DSM expenditures in Minnesota to 2 percent of
Minnesota revenues in 1998 and 1999, the minimum allowed by current Minnesota
law. As recently as 1995, the Company spent approximately 3.5 percent of its
Minnesota revenues on DSM.
In 1994, the MPUC increased the Company's cost recovery and incentives
for DSM by allowing recovery of a portion of the lost margins due to DSM impacts
on electric revenues and DSM investment returns and performance bonuses. The
performance bonuses are awarded through an incentive program that rewards the
attainment of specified conservation goals. The lost margin recovery, subject to
annual review by the MPUC, was approximately $20 million in 1997, $14 million in
1996, and $7 million in 1995. The DSM investment returns and performance
bonuses, subject to annual review by the MPUC, were $8 million in 1996 and $7
million in 1995. In addition, in April 1998 the Company will file for approval
of approximately $7 million of DSM investment returns and performance bonuses
for 1997.
Energy Sources
For the year ended Dec. 31, 1997, 47 percent of NSP's Kwh requirements
was obtained from coal generation and 25 percent was obtained from nuclear
generation. Purchased and interchange energy provided 24 percent, including 14
percent from Manitoba Hydro; NSP's hydro and other fuels provided the remaining
4 percent. The fuel resources for NSP's generation based on Kwh were coal (63
percent), nuclear (33 percent), renewable and other fuels (4 percent).
The following is a summary of NSP's electric power output in millions
of Kwh for the past three years:
1997 1996 1995
---- ---- ----
Thermal plants 31,896 32,657 33,802
Hydro plants 1,015 1,194 1,049
Purchased and
interchange 10,660 9,065 9,189
------ ------ -----
Total 43,571 42,916 44,040
============================
Many of NSP's power purchases from other utilities are coordinated
through the regional power organization MAPP. NSP is one of 70 members, 21
associate members and 8 regulatory participants in MAPP. The MAPP agreement
provides for the members to coordinate the installation and operation of
generating plants and transmission line facilities. The terms and conditions of
the MAPP agreement and transactions between MAPP members are subject to the
jurisdiction of the FERC.
Fuel Supply and Costs
Coal and nuclear fuel will continue to dominate NSP's regulated utility
fuel requirements for generating electricity by NSP owned generating capacity.
It is expected that approximately 96 percent of NSP's fuel requirements, on a
Btu basis, will be provided by these two fuels over the next several years,
leaving 4 percent of NSP's annual fuel requirements for generation to be
provided by other fuels (including natural gas, oil, refuse derived fuel, waste
materials, renewable sources and wood). The actual fuel mix for 1997 and the
estimated fuel mix for 1998 and 1999 are as follows:
Fuel Use on Btu Basis
---------------------
(Est) (Est)
1997 1998 1999
----- ----- ----
Coal 62.2% 60.4% 59.6%
Nuclear 33.9% 36.0% 36.8%
Other 3.9% 3.6% 3.6%
<PAGE>
The Company normally maintains between 20 and 40 days of coal inventory
depending on the plant site. The Company has long-term contracts providing for
the delivery of up to 100 percent of its 1998 coal requirements. Coal delivery
may be subject to short-term interruptions or reductions due to transportation
problems, weather and availability of equipment.
Based on existing coal contracts, the Company expects more than 98
percent of the coal it burns in 1998 will have a sulfur content of less than one
percent. The Company 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 total of 35 million tons of low-sulfur coal for the next
three years. These arrangements are sufficient to meet approximately 80 percent
of the requirements of existing coal-fired plants after 1998.
The Company is able to purchase the remaining 20 percent of its coal
requirements in a large active spot market. The Company has options from
suppliers for over 100 million tons of coal with a sulfur content of less than
one percent that could be available for future generating needs. The plants in
the Minneapolis-St. Paul area are about 800 miles from the mines in Montana and
1,000 miles from the mines in Wyoming. Coal delivered by rail provides the
Company with an economical source of fuel.
The estimated coal requirements of the Company at its major coal-fired
generating plants for the periods indicated and the coal supply for such
requirements are as follows:
================================================================================
<TABLE>
<CAPTION>
State
Sulfur Dioxide
Maximum Amount Contract Approximate Emission Limit
Annual Covered by Expiration Sulfur Pounds Per
Plant Demand Contract in 1998 Date Content (%)(2) MBTU* Input
- --------------------------------------------------------------------------------------------
(Tons) (Tons)
<S> <C> <C> <C> <C> <C>
Black Dog 1,000,000 1,000,000 (1) 0.5 1.3(3)
High Bridge 800,000 800,000 (1) 0.5 1.95
Allen S. King 2,000,000 2,000,000 (1) 0.9 1.6
Riverside 1,400,000 1,400,000 (1) 0.7 2.5(4)
Sherco 7,700,000 7,700,000 (1) 0.5 0.9(5)
---------- ------------
12,900,000 12,900,000(6)
</TABLE>
*MBTU = Million British Thermal Units
Notes:
(1) Contract expiration dates vary between 1998 and 2005 for western coal.
Spot market purchases of other western coal, and other fuels will
provide the remaining fuel requirements after 1998. The Company is also
burning petroleum coke as a source of fuel.
(2) This percentage represents the average blended sulfur content of the
combination of fuels typically burned at each plant.
(3) 1.2 lb./MBTU when Unit 2 is operating.
(4) The SO2 limitation at Riverside Unit 8 is 2.5 lb./MBTU. The limitation
for Units 6 and 7 is currently 0.9 lb. SO2 /MBTU.
(5) The SO2 limitation at Units 1 and 2 ranges from 70 percent removal with
a maximum emission rate of 0.48 lbs SO2/MBTU to 60 percent removal with
a maximum emission rate of 0.96 lb. SO2/MBTU averaged over 90 days. The
SO2 limitation at Unit 3 is 70 percent removal of SO2 input and a
maximum emission rate of 0.60 lb. SO2/MBTU averaged over 30 days. The
use of lime and/or limestone in the plant's scrubbers may be necessary
to achieve these limits.
(6) Annual requirements are expected to range from 11.4 to 12.9 million.
================================================================================
The Company's current fuel oil inventory is adequate to meet
anticipated 1998 requirements. Additional oil may be provided through spot
purchases from two local refineries and other domestic sources.
To operate the Company's nuclear generating plants, the Company secures
contracts for uranium concentrates, uranium conversion, uranium enrichment and
fuel fabrication. The contract strategy involves a portfolio of spot purchases
and medium and long-term contracts for uranium, conversion and enrichment.
Current
<PAGE>
contracts are flexible and cover between 70 percent and 100 percent of uranium,
conversion and enrichment requirements through the year 1998. These contracts
expire at varying times between 1998 and 2005. The overlapping nature of
contract commitments will allow the Company to maintain 70 percent to 100
percent coverage beyond 1998, if appropriate. The Company expects sufficient
uranium, conversion and enrichment to be available for the total fuel
requirements of its nuclear generating plants. Fuel fabrication is 100 percent
committed through the year 2003 and 30 percent covered through 2010. The Company
expects the unit cost of fuel to produce electricity with these nuclear
facilities will be lower than the comparable cost of fuel to produce electricity
with any other currently available fuel sources for the sustained operation of a
generation facility. The cost of nuclear fuel, including disposal, is recovered
in the customer price of the electricity sold by the Company.
The Company's average electric fuel costs for the past three years are
shown below:
Fuel Costs *
Per Million Btu
---------------
Year Ended December 31
1995 1996 1997
------- ------ ----
Coal** $ 1.11 $ 1.02 $1.05
Nuclear*** .48 .47 .47
Composite All Fuels .87 .83 .88
* Fuel adjustment clauses in its electric rate schedules or statutory
provisions enable NSP to adjust for fuel cost changes. (See "Utility
Regulation and Revenues - Fuel and Purchased Gas Adjustment Clauses"
under Item 1.)
** Includes refuse-derived fuel and wood.
*** See Note 1 to the Financial Statements under Item 8 for an explanation
of the Company's nuclear fuel amortization policies.
Nuclear Power Plants - Licensing, Operation and Waste Disposal
The Company operates two nuclear generating plants: the single unit,
543 Mw Monticello Nuclear Generating Plant (Monticello) and the Prairie Island
Nuclear Generating Plant (Prairie Island) with two units totaling 1,028 Mw. The
Monticello Plant received its 40-year operating license from the Nuclear
Regulatory Commission (NRC) on Sept. 8, 1970, and commenced operation on June
30, 1971. Prairie Island Units 1 and 2 received their 40-year operating licenses
on Aug. 9, 1973, and Oct. 29, 1974, respectively, and commenced operation on
Dec. 16, 1973, and Dec. 21, 1974, respectively.
In its most recent ratings of Company nuclear facilities, the NRC rated
the overall performance of both the Prairie Island and Monticello Plants as
excellent. On a scale of 1 to 3 (1 being the highest), the plants both rate at
1.25, which is the average of ratings in the areas of plant operations,
maintenance, engineering, and plant support. These ratings of the NRC's
Systematic Assessment of Licensee Performance (SALP) place the plants in the top
quarter of the 18 plants located in the Midwest.
The Prairie Island and Monticello nuclear plants currently hold the
Institute of Nuclear Power Operations' (INPO) top rating for plant operations
and training. In addition, INPO has awarded both of the plants the INPO
Excellence Award, which is a rigorous peer review process that recognizes plants
with the highest levels of excellence in operational safety and reliability and
which have no significant weaknesses.
The Company previously operated the Pathfinder Plant near Sioux Falls,
South Dakota as a nuclear plant from 1964 until 1967, after which it was
converted to an oil and gas-fired peaking plant. The nuclear portions were
placed in a safe storage condition in 1971, and the Company began
decommissioning in 1990. Most of the plant's nuclear material, which was
contained in the reactor building and fuel handling building, was removed during
1991. Decommissioning activities cost approximately $13 million and have been
expensed. A few millicuries of residual contamination remain at the operating
plant site.
Operating nuclear power plants produce gaseous, liquid and solid
radioactive wastes. The discharge and handling of such wastes are controlled by
federal regulation. For commercial nuclear power plants, high-level radioactive
waste includes used nuclear fuel. Low-level radioactive wastes are produced from
other activities at a nuclear plant. They consist principally of demineralizer
resins, paper, protective clothing, rags, tools and equipment that have become
contaminated through use in the plant.
A 1980 federal law places responsibility on each state for disposal of
its low-level radioactive waste. The law encourages states to form regional
agreements or compacts to dispose of regionally generated waste. Minnesota is a
member of the Midwest Interstate Low-Level Radioactive Waste Compact Commission
(Compact). The development costs were to be paid by the generators of low-level
radioactive waste within the Compact. In June 1997, the Compact abandoned
efforts to find a disposal site due to decreased low-level waste generation and
increased costs to build a facility. In November 1997, the Compact approved the
return of funds contributed for development costs to Midwest nuclear utilities.
Currently, the Barnwell facility, located in South Carolina, has been given
authorization by South Carolina to accept low-level radioactive waste and the
Compact has authorized its generators to use the Barnwell facility.
<PAGE>
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 1998. The
Company has contracted with the DOE for the future disposal of spent nuclear
fuel. The DOE is currently charging a disposal fee based on nuclear electric
generation sold. This fee ranges from approximately $10 million to $12 million
per year, which NSP recovers from its electric customers in cost-of-energy rate
adjustments. To date, NSP has paid the DOE $250 million in assessments for
disposal of spent nuclear fuel.
None of the Company's spent nuclear fuel has been accepted by the DOE
for disposal. Further, the DOE has indicated that a permanent federal facility
will not be ready to accept used nuclear fuel from utilities until approximately
2010. The Company, along with a group of other utilities and state agencies,
initiated a series of lawsuits against the DOE. The primary purpose of the
lawsuits is to insure that the Company and its customers receive timely storage
and disposal of used nuclear fuel in accordance with the terms of the Company's
contract with the DOE. (See Item 3 - Legal Proceedings 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,
the Company began expanding the used nuclear fuel storage facilities at its
Monticello plant by replacement of the racks in the storage pool. Also, in 1987,
the Company completed the shipment of 1,058 used fuel assemblies from the
Monticello plant to a General Electric storage facility in Morris, Illinois. As
a result, the Monticello plant does not expect to run out of storage capacity
prior to the end of its current operating license in 2010.
The on-site storage pool for spent nuclear fuel at Prairie Island was
filled during refueling in June 1994, so adequate space for a subsequent
refueling was no longer available. In anticipation of this, the Company, in
1989, proposed construction of a temporary on-site dry cask storage facility for
spent nuclear fuel at Prairie Island. The Minnesota Legislature (Legislature)
considered the dry cask storage issue during its 1994 legislative session as
required by a Minnesota Court of Appeals ruling in June 1993.
In May 1994, the Governor of the State of Minnesota (Governor) signed
into law a bill passed by the Legislature. The law authorizes the Company to
install 17 dry casks at Prairie Island. Based on the assumptions and conditions
in the original Certificate of Need from the MPUC, the Company determined the 17
casks would allow operation until at least 2003 and 2004 for units 1 and 2
respectively. After review of the 1994 Legislation the Company has determined 17
casks will allow facility operation until 2007. The Company executed an
agreement with the Governor concerning the renewable energy and alternative
siting commitments contained in the new law. The law authorized immediately the
installation of the first increment of five casks. The second increment of four
casks were authorized on Oct. 2, 1996 by the MEQB certifying that by Dec. 31,
1996: (i) the Company had applied to the NRC for an alternative site license for
an off-site temporary used nuclear fuel storage facility in Goodhue County (but
not on the Prairie Island nuclear generating plant site), (ii) the Company had
used good faith in pursuing development of the alternative site, and (iii) 100
Mw of wind generation was under contract.
As part of fulfilling the commitments required to secure the use of
additional casks, in August 1996, the Company filed the application for the
Goodhue County facility. The MEQB terminated an alternative siting process which
was one of the legislative requirements. The Company's certification by the MEQB
for the use of casks six through nine was legally challenged by the Prairie
Island Tribe (Tribe). In July 1997, the Minnesota Supreme Court denied further
review of the Tribe's petition. As a result of the decision, the Company
withdrew it's application to the NRC for the Goodhue County facility.
In 1996, the Company took steps for its wind and biomass resource
commitments as discussed under the caption "Electric Utility
Operations-Capability and Demand", herein. Other commitments resulting from the
legislation include a low-income discount for electric customers, additional
required conservation improvement expenditures and various study and reporting
requirements to a legislative electric energy task force. In January 1995, the
MPUC approved the Company's low-income discount programs in accordance with the
statute. The Company has implemented programs to meet the other legislative
commitments. (See "Electric Utility Operations - Capability and Demand", herein
and Notes 13 and 14 of Notes to Financial Statements under Item 8 for further
discussion of this matter.)
The final increment of eight casks are available unless prior to June
1, 1999, the Legislature specifically revokes the authorization for the final
eight casks. As of Jan. 31, 1998, seven storage casks are loaded and stored on
the Prairie Island nuclear generating plant site.
To address the issue of continued temporary storage of spent nuclear
fuel until the DOE
<PAGE>
provides for permanent storage or disposal, the Company is leading a consortium
working with various private parties to establish a private facility for interim
storage of spent nuclear fuel. In June 1997, the Private Fuel Storage Limited
Liability Co. (PFS) filed a license application with the NRC for a national
temporary storage site for spent nuclear fuel. The PFS, a consortium of
utilities including the Company, will undertake the development, licensing,
construction and operation of a storage facility on the Skull Valley Indian
Reservation in Utah. The full 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
mid-2002. However, due to uncertainty regarding pending regulatory and
governmental approvals, it is possible that this interim storage may be delayed
or not available at all.
On Jan. 23, 1997, the NRC issued Prairie Island a Severity Level III
violation and a $50,000 civil penalty stemming from design issues with the
Cooling Water Emergency Intake Line. The Cooling Water Emergency Intake Line is
the dedicated safety-related water source for the Cooling Water Pumps in the
event of a seismic occurrence rendering the normal intake bay inoperable. The
NRC determined that a violation of the safety evaluation process occurred
because an unreviewed safety question existed, due to these changed assumptions
on the non-seismic canal and operator action. The NRC contends NSP's response to
this regulatory issue was not promptly and adequately addressed.
In January 1997 the NRC issued a notice of an apparent violation for
the Company's Monticello plant. The notice regarded whether the Monticello plant
should have submitted to the NRC issues about safety questions when it approved
a reduction in the number of safety-related pumps used for containment cooling.
On March 5, 1997, the Company presented to the NRC the facts and history of the
case, and further discussions centered on corrective actions. At this time the
Company does not know the outcome of this apparent violation and whether a civil
penalty will be incurred.
On Oct. 16, 1997 the NRC assessed Prairie Island a Severity Level III
violation and $50,000 civil penalty for pump testing violations and untimely
updating of licensing documents. The NRC determined the criteria for measuring
the flow of auxiliary feedwater pumps did not accurately reflect the design
requirements for the pumps. The pumps are the backup system to provide cooling
water to the plant's steam generators. Prairie Island used a standard criterion
of ten percent below design flow to evaluate test results wherein the NRC
determined three percent was a more accurate criterion. Past test results stated
none of the pumps exceeded the three percent criterion and would have provided
the necessary waterflow if needed. The testing procedures were corrected during
the inspection.
The Company filed its triennial nuclear decommissioning study in 1996,
and the MPUC approved it in April 1997. The filing requested continuance of the
accruals, funding and other parameters approved in the last decommissioning
study filed in 1993.
Although the Company expects to operate the Prairie Island plant units
through the end of their useful lives, the approved capital recovery would allow
for the plant to be fully depreciated, including the accrual and recovery of
decommissioning costs by 2008, about six years earlier than the end of its
licensed life. The approved cost recovery period has been reduced because of the
uncertainty regarding spent fuel storage.
During the past several years, the NRC has issued a number of
regulations, bulletins and orders that require analyses, modification and
additional equipment at commercial nuclear power plants. The Company has spent
approximately $530 million since 1971, including approximately $5 million in
1997 and approximately $1 million in 1996 and 1995 under such requirements. The
NRC is engaged in various ongoing studies and rulemaking activities that may
impose additional requirements upon commercial nuclear power plants. Management
is unable to predict any new requirements or their impact on the Company's
facilities and operations.
See Note 13 to the Financial Statements under Item 8 for further
discussion of nuclear fuel disposal issues and information on decommissioning of
the Company's nuclear facilities. Also, see Note 14 to the Financial Statements
under Item 8 for a discussion of the Company's nuclear insurance and potential
liabilities under the Price-Anderson liability provisions of the Atomic Energy
Act of 1954.
<PAGE>
Electric Operating Statistics
The following table summarizes the revenues, sales and customers from
NSP's electric transmission and distribution business:
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
REVENUES (THOUSANDS)
Residential $ 739 684 $ 727 145 $ 735 743 $ 683 783 $ 651 593
Small commercial and industrial 379 848 376 797 362 521 351 287 327 888
Medium commercial and industrial 433 526 401 137 399 259 * *
Large commercial and industrial 468 404 450 811 448 226 824 195 780 444
Streetlighting and other 30 826 30 033 29 162 28 936 29 214
---------- ---------- ---------- ---------- ----------
Total retail 2 052 288 1 985 923 1 974 911 1 888 201 1 789 139
Sales for resale 107 464 98 961 133 961 146 239 159 498
Miscellaneous 58 798 42 529 33 898 32 204 26 279
---------- ---------- ---------- ---------- ----------
Total $2 218 550 $2 127 413 $2 142 770 $2 066 644 $1 974 916
========== ========== ========== ========== ==========
SALES (MILLIONS OF KILOWATT-HOURS)
Residential 9 791 9 847 9 956 9 303 9 092
Small commercial and industrial 5 907 6 091 5 763 5 585 5 307
Medium commercial and industrial 8 263 7 470 7 511 * *
Large commercial and industrial 11 059 11 089 10 941 17 874 17 117
Streetlighting and other 335 336 329 334 344
---------- ---------- ---------- ---------- ----------
Total retail 35 355 34 833 34 500 33 096 31 860
Sales for resale 4 658 4 929 6 500 6 733 8 044
---------- ---------- ---------- ---------- ----------
Total 40 013 39 762 41 000 39 829 39 904
========= ========= ======== ========= =========
CUSTOMER ACCOUNTS (AT DEC. 31) **
Residential 1 273 161 1 252 476 1 238 576 1 222 628 1 207 572
Small commercial and industrial 150 103 149 134 144 774 142 858 141 446
Medium commercial and industrial 9 142 7 962 7 906 * *
Large commercial and industrial 695 669 652 8 172 8 114
Streetlighting and other 6 276 5 030 4 883 4 836 4 813
---------- ---------- ---------- ---------- ----------
Total retail 1 439 377 1 415 271 1 396 791 1 378 494 1 361 945
Sales for resale 59 54 67 70 71
---------- ---------- ---------- ---------- ----------
Total 1 439 436 1 415 325 1 396 858 1 378 564 1 362 016
=========== ========== ========== ========= =========
</TABLE>
* 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 estimated medium group was reported as large
prior to 1995.
** Customers accounts for 1996 and 1997 may not be fully comparable to prior
years due to differences in meter accumulation in a new billing system
implemented in 1996.
<PAGE>
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) and Wisconsin (Eau Claire, LaCrosse and Ashland). As discussed in the
"Rate Matters by Jurisdiction" section herein, NSP has requested a declaratory
order from the SDPUC establishing the Company as a regulated gas utility in
South Dakota. NSP is directly connected to four interstate natural gas pipelines
serving these regions: Northern Natural Gas Company (Northern), Viking,
Williston Basin Interstate Pipeline Company (Williston) and Great Lakes
Transmission Limited Partnership (Great Lakes). Approximately 84 percent of
NSP's retail gas customers are served from the Northern pipeline system.
During 1992 and 1993, the FERC issued a series of orders (together
called Order No. 636) that addressed interstate natural gas pipeline
restructuring. This restructuring required all interstate pipelines, including
those serving NSP, to "unbundle" each of the services they provide: sales,
transportation, storage and ancillary services. 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 because of the alternatives now available to these
customers. Like gas LDCs, these customers now have expanded ability to buy gas
directly from suppliers and arrange pipeline and LDC transportation service. NSP
has provided unbundled transportation service since 1987. Transportation service
does not currently have an adverse effect on earnings because NSP's sales and
transportation rates have been designed to make NSP economically indifferent to
sales or transportation of gas. However, some transportation customers may have
greater opportunities or incentives to physically bypass the LDC distribution
system. NSP has arranged its gas supply and transportation portfolio in
anticipation that it may be required to terminate its retail merchant sales
function. Overall, NSP believes Order 636 has enhanced its ability to remain
competitive and allowed it to increase certain of its margins by providing an
increased selection of services to its customers.
Order No. 636 allows interstate pipelines to negotiate with customers
to recover up to 100 percent of prudently incurred "transition costs" (also
known as stranded costs) attributable to Order 636 restructuring. In February
1997, the FERC upheld this decision after appeals of Order No. 636 were remanded
by the United States Court of Appeals for the District of Columbia Circuit. In
addition, the FERC ruled existing shippers need only agree to a five-year
contract extension to obtain a right of first refusal on continued access to the
shipper's expiring capacity; the original rule was a 20-year commitment.
NSP's primary gas supplier, Northern, is in the process of determining
the final amount of transition costs to be passed on to customers as a result of
Order No. 636 restructuring. Northern's total Order No. 636 transition costs, to
be passed on to all of its customers, are estimated to be approximately $100
million. Northern will recover the prudent transition costs by amortizing the
amount over a period of several years, and including the amortized costs as a
component of its FERC regulated transportation charges. NSP estimates that it
will be responsible for approximately $13 million of Northern's transition
costs, spread over a period of approximately six years, which began Nov. 1,
1993. To date, NSP's regulatory commissions have approved recovery of
restructuring charges in retail gas rates. NSP has no significant Order No. 636
transition cost responsibilities to its other pipeline suppliers.
In response to the additional competitive pressures as a result of
Order No. 636, the Company has aggressively pursued alternative pricing
strategies and service enhancements to provide additional value to customers.
In 1996, NSP's retail gas utility operations were faced with the threat
of physical bypass by large industrial customers. Previously, NSP had used its
flexible gas rate discounting authority to compete to retain these customers.
However, reductions in natural gas pipeline construction costs (which benefit
NSP when it constructs its own facilities) made it economical for some customers
to consider bypassing NSP. In response, NSP filed a new Negotiated
Transportation Service Tariff with the MPUC. The MPUC voted to approve the
tariff on March 6, 1997. The new tariff provides additional flexibility in gas
rates discounting for potential bypass customers.
On June 19, 1997, the Company filed a 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 MPUC approved the rider in October 1997,
and the program commenced in January 1998.
In September 1996, NSP filed for FERC approval to "abandon" FERC's
jurisdiction over two liquefied natural gas (LNG) plants which the
<PAGE>
Company and the Wisconsin Company operate near St. Paul, Minnesota, and Eau
Claire, Wisconsin, respectively. FERC asserted jurisdiction over the plants in
the late 1970s, and NSP has provided FERC regulated LNG services from the two
plants since that time. Under the NSP filings, the plants would remain in
service but FERC would terminate its jurisdiction under Section 7 (c) of the
Natural Gas Act, and the plants would be subject only to MPUC and PSCW
jurisdiction, respectively. The filings were initially required to complete the
canceled Primergy merger, but NSP requested the filings be approved irrespective
of the merger. In October 1997, the FERC granted Part 157 abandonment.
Business Growth
NSP's gas utility extended service to approximately 14,000 new
customers during 1997. In addition to exploring new growth opportunities, NSP is
also focusing on conversion of potential customers who are located near NSP's
gas mains but are not hooked up to receive the service. NSP estimates there are
approximately 20,000 potential customers in this category.
In 1997, the Wisconsin Company signed a 10-year contract with the U.S.
Army to build, own, and operate a natural gas system at Fort McCoy, a regional
U.S. Army training center near Sparta, Wisconsin. At the end of January 1998,
$820,000 of the approximately $2.0 million total cost of the project had been
spent. On Feb. 2, 1998, the Wisconsin Company began providing gas to 169
buildings that were already served by the Fort's existing natural gas
distribution system, and by July 1998 an additional 746 buildings should be
added as the Fort's propane equipment is converted to use natural gas. The
contract should produce about $1.7 million of additional revenue each year. The
Wisconsin Company has received orders from the PSCW allowing the Wisconsin
Company to treat the investment as utility property and to include the cost of
gas purchased for the project in the PGA. The project is expected to be complete
in July 1998. NSP has constructed a new town border station adjacent to Fort
McCoy off the Northern Natural pipeline, removed eight miles of old steel gas
piping, and installed 14 miles of new gas distribution main. Prior to the
Wisconsin Company's contract, some of Fort McCoy's 1,000 buildings were served
by liquid propane; others received natural gas supplied by Wisconsin Gas Co.
through a fort-owned distribution system. NSP is the electric supplier to the
fort-owned electric distribution system.
In 1997, the NDPSC approved two NSP applications for certificates of
public convenience and necessity to extend gas service to Horace, North Dakota,
and three additional small cities outside Fargo. As a result, gas service will
be made available to about 350 customers in areas not previously served with
natural gas.
In late 1997, the Wisconsin Company signed a purchase agreement to
acquire Natural Gas Inc. (NGI) of New Richmond, Wisconsin. The companies have
filed an application with the PSCW and expect to receive approval for the
transaction in the spring of 1998. New Richmond is located in St. Croix County
the fastest growing county in Wisconsin in 1996 with a 15 percent growth rate.
NGI, a privately owned natural gas utility, founded in 1962, serves 1,900
natural gas customers in New Richmond and has revenues of approximately $2.3
million. The transaction will be structured as a tax-free reorganization for
income tax purposes and a pooling of interests for accounting purposes.
On Dec. 31, 1997, the Company announced an agreement and plan of merger
with Black Mountain Gas Company of Cave Creek, Arizona (Black Mountain). The
agreement is dependent upon regulatory approval and Black Mountain shareholder
approval. Black Mountain Gas Co. 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 the city of Page, Arizona. Black
Mountain currently serves 6,500 customers and had 1997 annual revenues of
approximately $6 million. The transaction will be structured as a tax-free
reorganization for income tax purposes and a pooling of interests for accounting
purposes.
The Company's gas operation maintains a non-utility service which sells
service contracts on a variety of home appliances. Working in partnership with
local independent service contractors, NSP Advantage Service offers 24 hour
appliance repair service. This service is offered to individuals within the
Company's service territory.
Business Standards
In July 1996, FERC adopted new rules (in its Order No. 587) which adopt
by reference 140 standard natural gas business practices approved by the Gas
Industry Standards Board ("GISB"). GISB is the independent standards
organization of the natural gas industry. The new rules and standards apply to
interstate gas pipelines like Viking, and are intended to simplify
transportation of natural gas across the interstate gas pipeline "grid".
However, NSP's retail natural gas operations must change their information
systems and operations to comply with the pipeline changes. The new FERC rules
went into effect in the second quarter of 1997. NSP and Viking estimate their
total compliance cost will be approximately $1 million. NSP invested
approximately $0.6 million through Dec. 31, 1997 to make its systems compatible
with the new pipeline systems. Viking will seek rate recovery of the rule
compliance costs in future rate proceedings.
<PAGE>
Standards of Conduct/Restructuring
In January 1997, the PSCW adopted "Standards of Conduct" for gas local
distribution companies (LDCs) serving Wisconsin consumers. The standards are
similar to, but much more extensive than, the standards of conduct FERC has
imposed on Viking under FERC Order No. 497 and on NSP's wholesale electric
transmission functions under FERC Order No. 889. The PSCW standards require
separation of the LDC delivery function from any affiliate which engages in "gas
functions" and impose extensive reporting and other administrative requirements.
The Wisconsin Company filed its compliance plan in February 1997. In
restructuring the natural gas industry, the PSCW reviewed four proposed models.
The chosen model included deregulation of the gas purchasing and transportation
functions by market segment as competition becomes effective and sustainable.
The PSCW then separated restructuring into three phases. In Phase I, the PSCW
found it necessary to completely separate the gas purchasing activities
associated with providing regulated services from those associated with
providing unregulated services and to develop standards of conduct to apply to
opportunity gas sales and utilities' relationships with their affiliates. The
focus of Phase II was to develop Standards of Conduct (SOC) intended to ensure
that interested market participants have the opportunity to purchase released
pipeline capacity and gas supply, and that the releasing utility receives the
best price for the sale. In situations in which a gas utility has a gas
marketing affiliate, additional restrictions between the utility and its
affiliate are necessary to ensure fair treatment of all market participants and
to prevent cross-subsidization. Phase III focused on three main issues: (1)
identifying regulatory or structural barriers that may prohibit competition; (2)
identifying standards to determine the level of competitiveness of the market
and the level of necessary regulations and; (3) identifying conditions to impose
on marketers serving formerly regulated markets. In this phase, the PSCW decided
that gas marketers should be registered and that consumer protection and
customer service policy issues must be addressed before any markets are
deregulated. The PSCW then ordered the formation of six work groups to address
the following: Capacity Policy, Market Registration/Certification, Legislation,
End-Use Price Reporting, Market-Based Pricing for Large Volume Customers, and
Consumer Protection and Essential Services. These groups will continue to meet
over the coming years to address the various issues.
On Aug. 29, 1997, Enron Capital & Trade et al. filed a petition for a
rulemaking with the MPUC which would have required all Minnesota gas LDCs to (i)
file unbundling plans to be implemented in early 1998, and (ii) terminate their
regulated merchant sales function by 2002. On Oct. 16, 1997 the MPUC voted to
dismiss the Enron petition and reconvene its LDC unbundling work group. The MPUC
ordered the work group to submit an LDC unbundling decision matrix to the MPUC
by June 1, 1998. The Company is participating in the work group process.
The MPUC also solicited comments from gas utilities on questions
concerning Affiliated Interest Contract Issues and has established a Chair's
Round Table to address these concerns. The Round Table is engaged in ongoing
discussions.
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 in Wisconsin, South Dakota and North Dakota could create precedent
for future rules affecting NSP's retail electric operations in those states.
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 662,025 MMBtu for 1997 occurred on Jan. 27, 1997.
NSP's gas supply sources are purchases of third-party gas which are
delivered under gas transportation service agreements with interstate pipelines.
These agreements provide for firm deliverable pipeline capacity of approximately
594,003 MMBtu/day. In addition, NSP has contracted with six providers of
underground natural gas storage services to meet the heating season and peak day
requirements of NSP gas customers. Using storage reduces the need for firm
pipeline capacity. These storage agreements provide NSP storage for
approximately 20 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 245,420 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 "needle peaks" caused by firm space heating
demand on extremely cold winter days and can be used to minimize daily imbalance
fees on interstate pipelines.
A number of NSP's interruptible industrial customers purchase their
natural gas requirements directly from producers or brokers for transportation
and delivery through NSP's distribution system. Transportation rates have been
designed to make NSP economically indifferent as to whether NSP sells and
transports gas, or only transports gas.
<PAGE>
Gas Supply and Costs
As a result of FERC Order No. 636 restructuring, NSP's natural gas
supply commitments have been unbundled from its gas transportation and storage
commitments. NSP's gas utility actively seeks gas supply, transportation and
storage alternatives to yield a diversified portfolio that provides increased
flexibility, decreased interruption and financial risk, and economical rates.
This diversification involves numerous domestic and Canadian supply sources,
varied contract lengths, and transportation contracts with seven natural gas
pipelines. NSP has firm gas transportation contracts with the following seven
pipelines. The contracts expire in various years from 1998 through 2013:
Northern Northern Border Pipeline Company
Williston Basin ANR Pipeline Company
Viking TransCanada Gas Pipeline Ltd.
Great Lakes
The agreements with Great Lakes, Northern Border, ANR and TransCanada
provide for firm transportation service upstream of Northern and Viking,
allowing competition among suppliers at supply pooling points, and minimizing
commodity gas costs.
In addition to these fixed transportation charge obligations, NSP has
entered into firm gas supply agreements that provide for the payment of monthly
or annual reservation charges irrespective of the volume of gas purchased. The
total annual obligation is approximately $14.5 million. These agreements are
beneficial because they allow NSP to purchase the gas commodity at a high load
factor at rates below the prevailing market price reducing the total cost per
Mcf.
NSP has certain gas supply and transportation agreements, which include
obligations for the purchase and/or delivery of specified volumes of gas, or to
make payments in lieu thereof. At Dec. 31, 1997, NSP was committed to
approximately $290.7 million in such obligations under these contracts, over the
remaining contract terms, which range from the years 1998-2013. These
obligations include some of the effects of contract revisions made to comply
with Order No. 636. NSP has negotiated "market out" clauses in its new supply
agreements, which reduce NSP's purchase obligations if NSP no longer provides
merchant gas service.
NSP purchases firm gas supply from a total of approximately 25 domestic
and Canadian suppliers under contracts with durations of one year to 10 years.
NSP purchases no more than 20 percent of its total daily supply from any single
supplier. This diversity of suppliers and contract lengths allows NSP to
maintain competition from suppliers and minimize supply costs. NSP's objective
is to be able to terminate its retail merchant sales function, if either
demanded by the marketplace or mandated by regulatory agencies, with no
financial cost to NSP.
The cost of gas supply, transportation service and storage service is
recovered through the PGA cost recovery adjustment mechanism discussed
previously under "Utility Regulation and Revenues". The average cost of gas and
propane held in inventory for the latest test year is allowed in rate base by
the MPUC and the PSCW.
In July 1997, NSP and thirteen other parties appealed a July 1995 FERC
order regarding rate treatment of two Great Lakes expansion projects. In the
early 1990's, Great Lakes completed two expansion projects which did not improve
service to the Company but which quadrupled its "rate base", which is a factor
in calculating the rates the Company pays Great Lakes for transporting gas. The
FERC's July 1995 order allowed Great Lakes to increase all rates to recover the
cost of these expansion projects which increased the Company's transport costs
on Great Lakes' system by 61 percent annually. Great Lakes was also allowed to
surcharge for services received since November 1991. The Company and other
parties to the appeal requested the cost of the expansion projects be recovered
only from customers who benefit from them. In January 1998, the District of
Columbia Court of Appeals ruled the July 1995 FERC order was lawful. The
additional transportation costs have been recovered through the Purchased Gas
Adjustment clause to the Company's rates, so there was no impact on the
Company's earnings.
In September 1997, the FERC ruled that Kansas natural gas producers
must refund Kansas ad valorem tax collected improperly collected from 1983 to
1988 plus interest. During this period, Northern had bought gas from Kansas
producers and resold it to NSP. In December 1997, Northern received one $30
million refund and, in turn, refunded $4.2 million to NSP. However, the Kansas
producers are appealing the FERC order and are also pursuing federal legislation
to overturn the FERC order. In February 1998, the FERC ruled that the Kansas
producers could place disputed refunds in escrow and pipelines such as Northern
could recollect refunded amounts if final refunds are less than those already
paid. The Company and the Wisconsin Company are requesting rule waivers from
their respective regulatory agencies to retain any refunds received from
Northern pending resolution of the litigation and legislation.
Purchases of gas supply or services by the Company from the Wisconsin
Company, its Viking pipeline affiliate and its EMI gas marketing affiliate are
subject to approval by the MPUC. The MPUC has approved all the Company's
transportation contracts with Viking and a 1994 spot gas purchase agreement with
EMI. In January 1998, NSP sought MPUC approval of a new agreement with EMI which
would
<PAGE>
allow both purchases from and sales to EMI. This agreement is pending MPUC
approval.
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:
Wisconsin
The Company Company
----------- -------
1993 $3.11 $3.02
1994 $2.59 $3.13
1995 $2.29 $2.78
1996 $2.88 $2.93
1997 $3.33 $3.22
Viking Gas Transmission Company (Viking)
In June 1993, the Company acquired 100 percent of the stock of Viking
Gas Transmission Company (Viking) from Tenneco Gas, a unit of Tenneco Inc., in
Houston, Texas. Viking, which is now a wholly owned subsidiary of the Company,
owns and operates a 500 mile interstate natural gas pipeline serving portions of
Minnesota, Wisconsin and North Dakota with a capacity of approximately 480
million cubic feet per day. The Viking pipeline currently serves 10 percent of
NSP's gas distribution system needs. Viking currently operates exclusively as a
transporter of natural gas for third-party shippers under authority granted by
the FERC. Rates for Viking's transportation services are regulated by FERC. In
addition to revenue derived from FERC-approved rates, which are reported in
NSP's consolidated Operating Revenues, Viking is receiving intercompany revenues
from the Company and the Wisconsin Company for jurisdictional allocations of the
acquisition adjustment paid by NSP (in excess of Tenneco's pipeline carrying
value) to acquire Viking. The Company is not currently recovering this cost in
retail gas rates in Minnesota, but is recovering this cost in North Dakota. The
Company has requested recovery of this cost in its 1998 Minnesota gas rate case.
The Wisconsin Company is recovering this cost in its retail gas rates.
As a natural gas pipeline, Viking is subject to FERC standards of
conduct in its transactions with the Company, the Wisconsin Company and EMI,
pursuant to FERC Order No. 497. Viking must transact with EMI on a
non-discriminatory basis, and certain restrictions are imposed on the retail gas
operations of the Company and the Wisconsin Company. The Order No. 497
restrictions on Viking are similar to the Order No. 889 restrictions on NSP's
wholesale electric transmission operations.
In November 1997, Viking placed a major expansion project in service.
The project expanded Viking's mainline capacity by 61,000 MMBtu/day (about 14
percent). The project will cost approximately $26 million. Viking expects to
recover the project costs through additional long term transportation service
revenues.
In October 1996, Viking placed two expansion projects in service. The
projects expanded Viking's mainline capacity by 19,400 MMBtu/day (about 5
percent), the first major Viking expansion since the 1960's, and constructed a
second pipeline lateral to increase capacity to serve NSP's growing retail gas
operations in the Grand Forks area. The two projects, which were not related but
constructed at the same time, cost approximately $8 million. Viking expects to
recover the project costs through additional long term transportation service
revenues.
On June 3, 1997, Viking, in partnership with TransCanada PipeLines,
Ltd. (TransCanada), formed Viking Voyageur Gas Transmission Company LLC
(Voyageur). In December 1997, NICOR, Inc. (NICOR) joined Voyageur so that it is
40 percent owned by Viking, 40 percent by TransCanada, and 20 percent by NICOR.
The parties are continuing negotiations toward a definitive agreement regarding
the contribution and possible merger of Viking into Voyageur as part of the
transaction, subject to certain conditions.
On October 31, 1997, Voyageur filed with the FERC for a certificate of
public convenience and necessity (CPCN) to install a new 773 mile, 42 inch
diameter pipeline parallel to the existing Viking pipeline and extending into
the Chicago area. If constructed, the new pipeline could transport approximately
1.45 billion cubic feet of natural gas per day to markets in Minnesota,
Wisconsin, North Dakota and Illinois. The anticipated project cost is
approximately $1.24 billion (U.S. currency), and the new pipeline would be
placed in service in late 1999 or 2000. The project would be constructed only if
sufficient market demand exists, and would be subject to extensive
pre-construction regulatory and environmental reviews by the FERC and other
appropriate government agencies. If the project proceeds, the Voyageur partners
would jointly own and operate the expanded pipeline entity.
The Voyageur project is currently undergoing extensive regulatory
reviews with respect to need, cost and environmental matters. As of Dec. 31,
1997, NSP has incurred $5.8 million related to negotiating the Voyageur
agreements and its share of the CPCN application preparation costs, including
various engineering and environmental studies, legal and other costs. Of this
amount, $0.3 million was expensed by Viking, and $5.5 million was deferred for
recovery in Voyageur's regulated gas transportation rates. The Company expects
to spend approximately $6 million in 1998 in additional project planning,
engineering, environmental, legal and other matters, to be recorded for deferred
recovery in Voyageur rates.
<PAGE>
Although many parties have intervened in support of the Voyageur
project, the CPCN application has also been protested by various parties,
including competing interstate pipelines. In addition, another pipeline project
to deliver western Canadian gas to near Chicago (the Alliance project) is also
pending FERC review. Thus there is some risk the Voyageur project may not be
constructed. If the Voyageur project is ultimately not constructed for any
reason, the Company would be required to expense the deferred project-related
costs in the year of project cancellation.
================================================================================
Gas Operating Statistics
The following table summarizes the revenue, sales and customers from
NSP's regulated gas businesses:
<TABLE>
<CAPTION>
REVENUE (THOUSANDS) 1997 1996 1995 1994 1993
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Residential $253 065 $267 130 $215 543 $207 506 $223 543
Commercial and industrial
Firm 144 539 146 145 119 863 120 912 131 431
Interruptible 79 135 63 585 48 646 49 384 52 216
Other 34 153 1 686 3 688 630
-------- -------- -------- -------- --------
Total Retail 476 773 477 013 385 738 381 490 407 820
Interstate transmission (Viking) 19 809 17 553 16 328 16 307 10 247
Agency, transportation and
off-system sales 21 287 34 662 26 122 24 338 12 237
Elimination of Viking sales to NSP (2 673) (2 435) (2 374) (2 232) (1 228)
-------- -------- -------- -------- --------
Total $515 196 $526 793 $425 814 $419 903 $429 076
======== ======== ======== ======== ========
SALES (THOUSANDS OF MCF)
Residential 42 428 48 149 42 294 38 750 41 277
Commercial and industrial
Firm 28 880 31 748 28 275 27 342 28 622
Interruptible 25 898 23 210 22 408 19 373 18 559
Other 33 394 772 212 186
-------- -------- -------- -------- --------
Total retail 97 239 103 501 93 749 85 677 88 644
========= ======= ====== ====== ======
OTHER GAS DELIVERED (THOUSANDS OF MCF)
Interstate transmission (Viking) 166 588 161 972 152 952 147 919 83 613
Agency, transportation and
off-system sales 11 701 17 535 19 679 13 466 8 128
Elimination of Viking sales to NSP (17 145) (19 311) (20 440) (16 845) (8 425)
-------- -------- -------- -------- --------
Total other gas delivered 161 144 160 196 152 191 144 540 83 316
======= ======= ======= ======= =======
CUSTOMER ACCOUNTS (AT DEC. 31)*
Residential 410 773 398 723 386 007 370 734 357 276
Commercial and industrial 41 905 40 244 38 575 37 140 36 185
-------- -------- -------- -------- --------
Total retail 452 678 438 967 424 582 407 874 393 461
Other gas delivered 36 30 62 18 40
-------- -------- -------- -------- --------
Total 452 714 438 997 424 644 407 892 393 501
======= ======= ======= ======= =======
</TABLE>
* Customers accounts for 1996 and 1997 may not be fully comparable to
prior years due to differences in meter accumulation in a new billing
system implemented in 1996.
================================================================================
<PAGE>
NONREGULATED SUBSIDIARIES
NRG Energy, Inc.
NRG Energy, Inc. (NRG) is the Company's subsidiary that develops,
builds, acquires, owns and operates several non-regulated energy-related
businesses. It was incorporated in Delaware on May 29, 1992, and assumed
ownership of the assets of NRG Group, Inc., including its subsidiary companies.
In 1997 NRG filed a S-1 registration statement with the Securities and Exchange
Commission. The following summary describes NRG's most significant projects.
Additional information is included in Item 1 of NRG's 1997 Form 10-K which is
incorporated herein by reference via Exhibit 99.03. NRG businesses generated
1997 operating revenues of $92 million and equity income of $26 million, and had
assets of $1.2 billion at Dec. 31, 1997.
NRG intends to continue to grow through combination of acquisitions and
greenfield development of power generation and thermal energy production and
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,
the more significant of which are discussed below.
OPERATING BUSINESSES - EQUITY INVESTMENTS
In May 1997, NRG as part of a consortium with CMS Energy Corporation
(CMS) and Horizon Energy Australia Investments, acquired the Australian State of
Victoria's Loy Yang A power plant (Loy Yang), Victoria's largest and Australia's
lowest-cost electric generating facility. Loy Yang is a 2,000 Mw, brown
coal-fired power station. The acquisition included an adjacent coal mine. NRG
holds a 25.37 percent ownership interest in the consortium. Loy Yang is one of
the newest and most modern of Victoria's brown coal-fired generating plants,
with a portion of its electric output committed under power supply contracts
through the year 2000. The coal mine has two billion tons of proven coal
reserves, enough to serve the coal supply needs for 50 years of the Loy Yang
plant acquired by the consortium and the Loy Yang B plant not included in the
acquisition. The mine has a supply contract with the 1,000 Mw Loy Yang B
electric generating plant and the exclusive rights to provide coal supplies for
a third Loy Yang generating plant, should it be built. Loy Yang is jointly
managed and operated by CMS and NRG.
In 1994, NRG, through wholly owned foreign subsidiaries, acquired a
37.5 percent interest in the Gladstone Power Station, a 1,680 Mw coal-fired
plant in Gladstone, Queensland, Australia from the Queensland Electricity
Commission. Other members of the unincorporated joint venture, including Comalco
Limited of Australia (Comalco), acquired the remaining interest. A large portion
of the electricity generated by the station is sold to Comalco for use in its
aluminum smelter, pursuant to long-term power purchase agreements. NRG, through
an Australian subsidiary, operates the Gladstone plant.
In 1993, NRG, through a wholly owned foreign subsidiary, acquired a 50
percent interest in a German corporation, Saale Energie GmbH (Saale). Saale owns
a 400 Mw share of a 960 Mw power plant (60 Mw of which is sold directly to an
independent railroad) located in Schkopau, Germany, which is near Leipzig.
PowerGen plc of the United Kingdom acquired the remaining 50 percent interest in
Saale. VEBA Kraftwerke Ruhr AG of Gelsenkirchen, Germany (VKR), the builder of
the Schkopau plant, owns the remaining 58.9 percent interest and operates the
plant. The plant is fired by brown coal (lignite) mined by MIBRAG (discussed
later) under a long-term contract. Saale has a long-term power sales agreement
for its 400 Mw share of the Schkopau facility with VEAG of Berlin, Germany, the
company that controls the high-voltage transmission of electricity in the former
East Germany. The first 425 Mw unit of the plant began operation in January of
1996, and the second unit came on line in July of 1996.
In 1993, NRG, through a wholly owned foreign subsidiary, agreed to
acquire a 33.33 percent interest in the coal mining, power generation and
associated operations of Mitteldeutsche Braunkohlengesellschaft mbH (MIBRAG),
located south of Leipzig, Germany. MIBRAG is a German corporation formed by the
German government to hold two open-cast brown coal (lignite) mining operations,
a lease on an additional mine, the associated mining rights and rights to future
mining reserves, two small industrial power plants, a circulating fluidized bed
power plant, a district heating system and coal briquetting and dust production
facilities. Under the acquisition agreement, Morrison Knudsen Corporation and
PowerGen plc also each acquired a 33 percent interest in MIBRAG, while the
German government retained a one-percent interest in MIBRAG. The investor
partners began operating MIBRAG effective Jan. 1, 1994, and the legal closing
occurred Aug. 11, 1994. In December 1996, each of the investor
<PAGE>
partners purchased one third of the remaining one percent interest held by the
German government.
In 1996 NRG and Nordic Power Invest AB (NPI), a wholly-owned subsidiary
of Vattenfall AB, purchased 96.6 percent (4,060,732 shares) of the common stock
of Bolivian Power Company Limited (COBEE) for $43 per share through Tosli
Investment BV, the holding company jointly owned by NRG and NPI. In October
1997, the ownership of Tosli changed to 50 percent each for NRG and Vattenfall
AB as NRG sold 10 percent of Tosli to Vattenfall AB. COBEE is the second largest
generator of electricity in Bolivia with 171 Mw of capacity, which includes 136
Mw of hydro capacity and a 17 Mw gas-fired peaking unit. COBEE is incorporated
in Canada, with a local office in La Paz, Bolivia and a headquarters located in
Minneapolis, Minnesota. COBEE is in the process of expanding its hydroelectric
facilities in the Zongo Valley and upon completion, total generating capacity
will be 218 Mw.
In November 1997, NRG acquired 100 percent of the outstanding shares of
Pacific Generation Company (PGC), a wholly-owned indirect subsidiary of
PacifiCorp Company, Inc. PGC has ownership interests in 11 projects with a total
capacity of 737 Mw with operational responsibility for 312 Mw and net ownership
interests of 166 Mw. One of the projects is located in Canada and the other ten
are located throughout the United States. The projects are diverse in terms of
fuel type, including natural gas, hydro, refuse-derived fuel, coal and wind.
In April 1996, NRG purchased a 41.86 percent interest in O'Brien
Environmental Energy, Inc. (O'Brien). O'Brien was renamed NRG Generating (U.S.)
Inc. (NRGG). NRG currently holds 45.21 percent of the common stock of NRGG and
the remaining 54.79 percent is held publicly. NRGG is traded on the NASDAQ small
capital market under the ticker symbol NRGG. NRGG is the 100 percent owner of
power cogeneration facilities in Newark and Parlin, New Jersey. These two
facilities have an aggregate operating capacity of approximately 196 Mw. NRGG
also has a 33.3 percent interest in the 150 Mw Grays Ferry cogeneration project
in Philadelphia, Pennsylvania. NRGG and one of its partners in this project
recently commenced litigation seeking to enjoin PECO Energy Company (PECO) from
terminating its power purchase agreement with the project and to compel PECO to
pay the rate set forth in the existing agreements. NRGG's position is that the
actions of PECO are without merit and the existing agreements should be
enforced. On March 19, 1998 the federal court dismissed the action for lack of
jurisdiction. In addition to an equity interest in NRGG, in the purchase NRG
also acquired certain biogas projects which were transferred to its subsidiary,
NEO Corporation, and also made loans to NRGG and entered into project
commitments. (See Note 14 of the Financial Statements Under Item 8 for further
discussion of NRG's capital commitments related to NRGG.) During 1997, NRGG
purchased the Millennium project from NRG, resulting in a gain of approximately
3 cents per share.
NRG also owns various domestic and international equity interests in
independent power production and cogeneration facilities, and thermal energy
production and transmission facilities with total equity of 560 Mw and 156.7
Megawatt therms (MWt), respectively, at Dec. 31, 1997.
OPERATING BUSINESSES - WHOLLY-OWNED
NRG participates in several energy businesses which are managed as a
thermal business group. The Minneapolis Energy Center (MEC) provides steam and
chilled water to customers in downtown Minneapolis, Minnesota. MEC currently
provides 90 customers with 1.6 billion pounds of steam per year and 34 customers
with 39.1 million ton hours of chilled water per year. NRG, through its
wholly-owned subsidiary NRG Energy Center, Inc., acquired MEC in August 1993 for
approximately $110 million. MEC's assets include two steam and chilled water
plants, three chilled water plants, two combined steam plants, six miles of
steam and two miles of chilled water distribution lines. The MEC plants have a
combined steam capacity of 1,323 mmBtus per hour (388 Mwt) and cooling capacity
of 35,550 tons per hour. In addition, NRG owns and operates three steam lines in
Minnesota that provide steam from the Company's power plants to Rock-Tenn
Company, the Andersen Corporation and the Minnesota Correctional Facility in
Stillwater.
NRG operates two refuse-derived fuel (RDF) processing plants and an ash
disposal site in Minnesota. The ownership of one plant was transferred by the
Company to NRG at the end of 1993. NRG manages the operation of the other RDF
plant, of which the Company owns 85 percent, and of the ash disposal site. The
Company pays NRG a fee to manage its RDF facility under an operation and
maintenance agreement approved by the MPUC. In 1997, the RDF plants processed
approximately 800,000 tons of municipal solid waste into approximately 650,000
tons of RDF that was burned at two NSP power plants and at a power plant owned
by United Power Association.
NRG also owns 204 MWt of thermal energy production through several
additional wholly-owned subsidiaries operating in Minnesota and North Dakota.
NEW BUSINESS DEVELOPMENT
NRG is pursuing several energy-related investment opportunities,
including those discussed
<PAGE>
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 herein.
A joint venture among NRG, Ansaldo Energia SpA, Italy and P.T. Kiani
Metra, Indonesia, is developing a 400 Mw coal-fired power generation facility in
West Java, Indonesia through P.T. Dayalistrik Pratama ("PTDP"), a limited
liability company created by the joint venturers. NRG and Ansaldo each have an
ownership interest of 45 percent in PTDP and P.T. Kiani Metra has an ownership
interest of 10 percent. In November 1996, PTDP signed a Power Purchase Agreement
with P.T. PLN (Persero), an instrumentality of the Government of Indonesia. NRG
Energy plans to have a 45 percent equity interest in the project and would
operate and maintain the power plant for the 30 year life of the project.
Ansaldo will have responsibility for construction. The coal-fired power plant
will sell its entire output to the local Java-Bali grid. In September 1997, the
government of Indonesia placed the project on review. All project development
efforts have been temporarily halted until the economic issues of Indonesia are
stabilized and the project is allowed to proceed by the government.
In December 1996, NRG reached agreement with Indeck Energy Services
(Europe) to purchase a 50 percent equity interest in the Enfield Energy Centre,
a 350 Mw power project located in the North London Borough of Enfield, England
in the United Kingdom (UK). The power station is planned to begin commercial
operations in 1999 and would be jointly developed by NRG and Indeck. The power
station will sell its output to the UK grid. Natural gas will fuel the plant,
which will use an air-cooled condensing system to eliminate any visible water
vapor plume. Because of its proximity to London, local underground cables will
be used to distribute the electricity rather than large overhead transmission
lines. NRG expects to invest approximately $60 million in this project.
Financial commitments were obtained from lenders in 1997.
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.
Pursuant to the DCA, a business plan for the joint project was submitted in June
1997. NRG has stated its willingness to invest up to $67.25 million of equity in
this project and to assist the joint project in obtaining non-recourse debt in
an amount necessary to fund the required capital improvements to the Balti and
Eesti Power Plants. Recently, the Estonian Government announced it had rejected
the business plan of NRG and EE and offered to work on a new plan in early 1998.
NRG's policy is to expense all costs until there is a signed contract and Board
of Directors approval. All such costs with respect to Estonia have been
expensed. Discussions are continuing with the Estonian Government as management
continues to evaluate the Estonian situation.
NRG, together with two other parties and the Chapter 11 trustees, have
filed a plan with the United States Bankruptcy Court for the Middle District of
Louisiana to acquire the fossil generating assets of Cajun Electric Power
Cooperative of Baton Rouge, Louisiana ("Cajun") for approximately $1.2 billion.
The NRG consortium has the support of the Chapter 11 trustee and Cajun's secured
creditors. The Court has also received two other competing reorganization plans,
all of which are subject to a confirmation hearing which began in December 1996.
NRG expects the confirmation process to conclude in the second quarter of 1998.
Under the plan filed with the Court, NRG would hold a 30 percent equity interest
in Louisiana Generating LLC, which would acquire Cajun's 1,706 Mw net of
non-nuclear generating assets. The plan of reorganization for Cajun contemplates
an equity investment from NRG of approximately $75-100 million.
In 1996, a new wholly owned subsidiary of NRG purchased the senior debt
of Mid-Continent Power Company (MCPC) of Pryor, Oklahoma. In 1997, NRG received
all of MCPC's assets in exchange for forgiveness of a portion of the debt. In
December 1997, NRG sold a portion of its interest in MCPC resulting in a gain of
3 cents per share. MCPC owns a 120 Mw cogeneration facility in Pryor, Oklahoma.
PROJECTS WITH NONRECURRING EARNINGS EFFECTS
In 1994, NRG, through a wholly owned subsidiary, purchased a 50 percent
ownership interest in Sunnyside Cogeneration Associates, a Utah joint venture,
which owns and operates a 58 Mw waste coal plant in Utah. The waste coal plant
is currently being operated by a partnership that is 50 percent owned by an NRG
affiliate. As of year-end 1997, NRG and its partner's effort to restructure the
debt of the Sunnyside cogeneration project was not successful. Due to a lack of
progress in restructuring the project's debt, NRG's net capitalized investment
in the Sunnyside project was written down by $9 million (8 cents per share after
tax) in the fourth quarter of 1997. NRG's remaining investment in the project
was $1 million at Dec. 31, 1997.
NRG, through wholly owned subsidiaries, owns 45 percent of the San
Joaquin Valley Energy Partnerships (SJVEP), which owns four power plants located
near Fresno, California with a total capacity of 55 Mw. The plants previously
operated under long-term Standard Offer 4 (SO4) power sales contracts with
Pacific Gas and Electric (PG&E) which expire in 2017. In early 1995, PG&E
reached basic agreements with SJVEP to acquire the SO4
<PAGE>
contracts. The negotiated agreements resulted in cost savings for PG&E customers
as well as economic benefits for SJVEP. Under the terms of the agreements, PG&E
has been released from its contractual obligation to purchase power generated by
SJVEP. Proceeds received from PG&E under the agreements were used to repay SJVEP
debt obligations and recover investments in the facilities. SJVEP continues to
own and maintain the facilities and to evaluate opportunities to market power
without the prior costs incurred for plant depreciation and interest on debt, or
to sell the assets. All regulatory approvals for the agreements were received in
the second quarter of 1995. NRG's share of the pretax gain realized by SJVEP
from this transaction, which was recorded in June 1995, was approximately $30
million (26 cents per share after tax). Settlement distributions were paid to
NRG from SJVEP in 1995 and 1996. SJVEP's 10 Mw facility was sold to NEO in late
1996.
In 1994, Michigan Cogeneration Partners Limited Partnership (MCP), a
partnership between subsidiaries of NRG and Cogentrix Energy, Inc., reached an
agreement with Consumers Power Company (Consumers), an electric utility
headquartered in Jackson, Michigan, to terminate the power sales contract
related to a 65 Mw cogeneration facility being developed by MCP in Parchment,
Michigan. The agreement to terminate the contract required Consumers to make a
payment to MCP of $29.8 million. As a result, NRG recorded a net pretax gain
from the termination of this contract of $9.7 million, which increased NSP's
earnings by approximately nine cents per share in the third quarter of 1994.
NRG's subsidiary, Scoria Incorporated, and Western Syncoal Co., a
subsidiary of Montana Power Co., completed construction in January 1992 of a
demonstration coal conversion plant designed to improve the heating value of
coal by removing moisture, sulfur and ash. The plant, located in Montana, began
commercial operation in August 1993. NRG's net capitalized investment in the
Scoria coal project was written down by $3.5 million in 1994, $5 million in 1995
and $1.5 million in 1996 to reflect reductions in the expected future operating
cash flows from the project. NRG has no remaining investment to recover in the
Scoria project.
NRG's subsidiary Graystone Corporation, and several other companies
were to build the first privately owned uranium enrichment plant in the United
States. Because of the uncertainty surrounding the ultimate successful operation
of this plant, NRG wrote off its $1.5 million investment in Graystone during
1994.
Energy Masters International, Inc. (EMI)
(formerly Cenerprise, Inc.)
NSP's non-regulated wholly owned subsidiary, EMI, commenced operations
in October 1993 through the acquisition from bankruptcy of selected assets of
Centran Corporation, a natural gas marketing company. EMI, in addition to
marketing natural gas to end-use customers, provides customized value-added
energy services to customers, both inside NSP service territory and on a
national basis. EMI offers customers many energy products and services
including: utility billing analysis, end-use gas marketing, risk management,
construction, energy services consulting and administrative services. The MPUC
has approved a 1994 contract whereby EMI may make natural gas sales at market
based rates (determined by competitive bids) to NSP for resale to retail gas
customers. As described previously under the caption "Gas Utility Operations -
Capability and Demand", herein, a new 1998 agreement is pending MPUC approval.
In 1995, EMI and Atlantic Energy Enterprises (AEE) established Enerval
LLC (formerly known as Atlantic CNRG Services LLC). EMI and AEE each own 50
percent of the venture, which develops new and expanded natural gas and electric
energy products and services, primarily in the northeast United States. EMI is
currently in the process of evaluating proposals for the sale of its interest in
Enerval and expects to finalize the sale during the second quarter of 1998. In
late 1997, EMI's investment in and advances to Enerval were written down to an
estimate of their net realizable value.
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 has offices in seven states nationwide and specializes in
energy efficiency improvement services for commercial, industrial and
institutional customers. EMC continues to operate as a separate legal entity, as
a subsidiary of EMI.
In 1997, EMI acquired 100 percent of Energy Solutions International
Inc. (ESI). ESI, based in St. Paul, Minnesota, is a full-service energy
management firm operating in 15 states nationwide. ESI continues to operate as a
separate legal entity, as a subsidiary of EMI.
Eloigne Company
In 1993, the Company established Eloigne Company (Eloigne), to identify
and develop affordable housing investment opportunities. Eloigne's principal
business is the acquisition of a broadly diversified portfolio of rental housing
projects
<PAGE>
which qualify for low income housing tax credits under current federal tax law.
As of Dec. 31, 1997, approximately $56 million had been invested in Eloigne
projects, including approximately $18 million in wholly owned properties (at net
book value) and approximately $38 million in equity interests in jointly-owned
projects. These investments and related working capital requirements have been
financed with approximately $27 million of long-term debt (including current
maturities) and the remainder with equity capital.
Completed Eloigne projects as of Dec. 31, 1997, are expected to
generate tax credits of $71.1 million over the ten-year period 1998-2007. Tax
credits recognized in 1997 as a result of these investments were approximately
$6.7 million. A proposed "phase-out" of these tax credits was passed by the
United States Congress but vetoed by the President in 1995. The legislation
would have sunset the low-income housing tax credit allocation after Dec. 31,
1997. Under the vetoed proposal, projects with credits allocated prior to that
date would continue to generate tax credits over the remainder of the 10-year
credit period allowed. No legislation was reintroduced into Congress during 1996
or 1997 to phase-out low income tax credits.
Seren Innovations, Inc.
Seren Innovations, Inc. (Seren) was formed in November, 1996 to pursue
communications and data services business in the upper Midwest. Seren invested
$6 million in a fixed wireless network now being deployed in the Minneapolis -
St. Paul metro area by an affiliate of CellNet Data Systems, Inc. In return,
Seren will receive contracted payments from the use of the network. Seren also
has the potential to receive additional royalties for data services added to the
network.
Seren is pursuing additional network development opportunities in other
markets, which may result in potential equity investments of up to $50 million
in 1998-1999.
Ultra Power Technologies, Inc.
Ultra Power Technologies Inc., (Ultra Power), a new NSP subsidiary
formed in late 1997, will market a proactive, non-destructive, power-cable
testing technology, for which NSP has been instrumental in the research and
development. The predictive tool was developed by Dr. Matt Mashikian of
Instrument Manufacturing Co. (IMCORP). Dr. Mashikian and IMCORP have entered
into a contract with Ultra Power to provide equipment and software to Ultra
Power. 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 will market this service to utilities and commercial
customers with underground cable.
<PAGE>
NONREGULATED BUSINESS INFORMATION
<TABLE>
<CAPTION>
December 31
============================================================================================================
(Thousands of dollars) 1997 1996
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Equity investment by nonregulated businesses in unconsolidated projects
(Including undistributed earnings and capitalized development costs)
Australian projects $320 069 $91 350
European projects 105 925 108 091
South American and Latin American projects 81 712 92 257
Other international projects 9 534 3 316
Affordable housing projects (U.S.) 38 230 32 034
Other U.S. projects 185 264 82 681
- ------------------------------------------------------------------------------------------------------------
Total equity investment in unconsolidated nonregulated projects $740 734 $409 729
Nonregulated property of consolidated subsidiaries
(net of accumulated depreciation) - primarily U.S. projects 256 726 192 790
Notes receivable from unconsolidated projects, including current portion 133 426 81 564
Intangible assets, including goodwill 110 218 101 496
Current and other assets 108 229 52 080
- ------------------------------------------------------------------------------------------------------------
Total assets of nonregulated businesses $1 349 333 $837 659
============================================================================================================
Long-term debt, including current maturities $555 843 $269 486
Short-term debt 122 637 7 030
Other current liabilities 47 775 45 957
Other liabilities 66 283 23 954
- ------------------------------------------------------------------------------------------------------------
Total liabilities of nonregulated businesses 792 538 346 427
NSP's equity investment in nonregulated businesses 619 682 488 438
Cumulative currency translation adjustments (62 887) 2 794
- ------------------------------------------------------------------------------------------------------------
Total equity of nonregulated businesses 556 795 491 232
- ------------------------------------------------------------------------------------------------------------
Total liabilities and equity of nonregulated businesses $1 349 333 $837 659
============================================================================================================
</TABLE>
SIGNIFICANT NONREGULATED GENERATION PROJECTS OPERATING AT DEC. 31, 1997
<TABLE>
<CAPTION>
Total NRG Mw-
Generation Projects Operating Location Mw Ownership Equity Operator
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Gladstone Power Station Australia 1680 37.50% 630 NRG
Loy Yang Australia 2000 25.37% 507 NRG/CMS Generation
Pacific Generation Company USA/Canada 776 8.50%-100.00% 203 Various/AES
Schkopau Power Station (1) Germany 960 20.55% 200 Veba Kraftwerke Ruhr A.G.
NRG Generation (U.S.) Inc.
(NRGG) (2) New Jersey, USA 196 45.21% 87 NRG
COBEE Bolivia 171 48.30% 83 COBEE
MIBRAG mbH Germany 200 33.33% 67 MIBRAG
Energy Development Limited Australia 237 19.97% 38 Energy Development Limited
Scudder Latin American Power
Projects(Scudder) (3) Latin America 254 25.00% 19 Stewart & Stevenson/Wartsila
</TABLE>
1. Through a lease agreement, NRG has ownership of 200 Mw.
2. NRGG owns various percentages of projects (15.07%-37.52%) making NRG's share
of ownership 87 Mw.
3. Scudder owns various percentages of projects (6.45%-8.78%) making NRG's share
of ownership 19 Mw.
<PAGE>
ENVIRONMENTAL MATTERS
NSP proactively prevents adverse environmental impacts by regularly
monitoring operations to ensure the environment is not adversely affected, and
takes timely corrective actions where past practices have had a negative impact
on the environment. Significant resources are dedicated to environmental
training, monitoring and compliance matters. NSP strives to maintain compliance
with all applicable environmental laws.
NSP is potentially liable for remediation of waste disposal sites owned
by others, and for decommissioning and restoration of present and former plant
sites, which is discussed in Notes 1, 13 and 14 to the Financial Statements
under Item 8.
In general, NSP has been experiencing greater environmental monitoring
and compliance requirements, which have caused and may continue to cause
slightly higher operating expenses and capital expenditures. The Company has
spent approximately $727 million on capitalized environmental improvements to
new and existing facilities since 1968. NSP expects to incur approximately $18
million in capital expenditures and approximately $34 million in operating
expenses for compliance with environmental regulations in 1998. The precise
timing and amount of future environmental costs are currently unknown. (For
further discussion of environmental costs, see "Environmental Matters" under
Management's Discussion and Analysis of Financial Condition and Results of
Operations under Item 7, and Note 14 to the Financial Statements under Item 8.)
Permits
NSP's regulated businesses are required to renew environmental
operating permits for its facilities at least every five years. NSP believes
that it is in compliance, in all material respects, with environmental
permitting requirements.
Waste Disposal
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," herein, in Management's Discussion
and Analysis under Item 7 and in Notes 13 and 14 of Notes to Financial
Statements under Item 8.
The Company and NRG have contractual commitments to convert municipal
solid waste to boiler fuel (called Refuse-Derived Fuel or RDF) and to burn the
fuel to generate electricity. NRG owns and/or operates two resource recovery
plants that produce RDF from the waste. The RDF from NRG's plants is burned at
the Company's Red Wing and Wilmarth plants in the Company's service area, and
the Elk River plant owned by United Power Association. In addition, the
Wisconsin Company owns a RDF plant and the RDF produced by this plant is burned
at the French Island plant in the Wisconsin Company's service area. Processing
and burning RDF is an additional economical source of electricity, which is
beneficial to NSP's electric customers. The Company's commitment to this program
enables counties to meet state-mandated goals to reduce the amount of solid
waste which would otherwise go to landfills. In addition, the program provides
for increased materials recovery and increased use of municipal solid waste as
an energy source.
NSP has met or exceeded the removal and disposal requirements for
polychlorinated biphenyl (PCB) equipment as required by state and federal
regulations. NSP has removed nearly all known PCB capacitors from its
distribution system. NSP also has removed nearly all known network PCB
transformers and equipment in power plants containing PCBs. NSP continues to
test and dispose of PCB-contaminated mineral oil and equipment in accordance
with regulations. PCB-contaminated mineral oil is detoxified and reused or
burned for energy recovery at permitted facilities. Any future cleanup or
remediation costs associated with past PCB disposal practices is unknown at this
time.
Air Emissions Control And Monitoring
In 1994, the U.S. Environmental Protection Agency (EPA) proposed new
air emission guidelines for municipal waste combustors. These proposed
guidelines were finalized in December 1995. In November 1997, the state of
Minnesota put a new draft waste combustor rule on public notice. This rule, when
finalized, will replace the old state waste combustor rule and will be more
restrictive than the federal guidelines. To meet the new federal and state
requirement, the Company must install additional pollution control and
monitoring equipment at the Red Wing plant and additional monitoring equipment
at the Wilmarth plant. The Company is evaluating equipment to meet the
requirements. The required equipment will likely cost between $4 million and $12
million.
The Clean Air Act, including 1990 Amendments, (Clean Air Act) calls for
reductions in emissions of sulfur dioxide and nitrogen oxides from electric
generating plants. These reductions, which will be phased in, began in 1995. The
majority of the rules implementing this complex legislation are finalized. No
additional capital expenditures are anticipated to comply with the sulfur
dioxide emission limits of the Clean Air Act. NSP has expended significant
amounts over the years to reduce sulfur
<PAGE>
dioxide emissions at its plants. Based on revisions to the sulfur dioxide
portion of the program, NSP's emission allowance allocations for the years
1995-1999 were dramatically reduced from prior rulemaking. Burners at the
Company's Sherburne County Generating Plant (Sherco) unit 2 were upgraded in
1994 to further reduce emissions of nitrogen oxides. Other expenditures will be
necessary on the NSP system for compliance in the year 2000. Evaluations are
currently underway to determine if changing operating procedures could reduce or
eliminate future capital expenditures.
In 1997, the EPA revised the National Ambient Air Quality Standards for
ozone and particulate matter. It is anticipated, based on historical monitoring,
that the Company will be in compliance with the new standards and therefore will
not be impacted by the new standards. If however, an area is determined to not
be in compliance with the new standards, reductions in emissions of sulfur
dioxide and oxides of nitrogen could be required.
As part of its Clean Air Act compliance effort, testing of a full scale
prototype wet electrostatic precipitator ("wet" ESP) was completed at Sherco in
1996. The "wet" ESP equipment was installed in 1995 into one of the plant's
existing scrubber modules to determine its effectiveness in reducing particulate
emissions and lowering opacity. Based on operating test results, the Company has
chosen to convert multiple scrubber modules on Units 1 and 2 to the "wet" ESP
design. Capital investment to date for the prototype has been $4 million. The
Company estimates total capital expenditures for this project of $47 million
through 2001.
The Company has conducted testing for air toxics at its major
facilities and has shared these results with state and federal agencies. The
Company also conducted research on ways to further reduce mercury emissions.
This information has also been shared with state and federal agencies. The 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 which recommended
additional investigation on 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 their Mercury
Reduction Initiative. The Initiative is evaluating various strategies to reduce
mercury contamination in fish.
On March 11 and October 7, 1996, the Wisconsin Company received Notices
of Violation (NOV) from the Wisconsin Department of Natural Resources (WDNR)
stating that emissions from unit 2 at the Wisconsin Company's French Island
generating facility had exceeded allowable levels for dioxin. The Company
responded by providing a written response to the WDNR setting forth the
Wisconsin Company's plans for bringing the emission levels back into compliance.
By year end 1997, subsequent compliance tests had demonstrated that dioxins no
longer exceeded acceptable limits. The Wisconsin Company expects that by early
1998 the WDNR will formally close out the NOV. No fines are expected.
In 1996, the Wisconsin Company received a Letter of Non-compliance
(LON) from the WDNR for failing to meet the emission guidelines for carbon
monoxide (CO) at its Bay Front generating facility. The Wisconsin Company worked
with the WDNR to establish mutually agreed-upon CO emission limits for the Bay
Front facility. The Wisconsin Company has been advised by WDNR staff that, based
on monitoring during 1997, that the plant is in compliance with the new emission
limits. The Wisconsin Company has now been advised in writing that the LON has
been formally closed. No enforcement action or fines resulted from the LON.
In December 1997, nearly 160 nations adopted the "Kyoto Protocol to
the United Nations Framework Convention on Climate Change" (Kyoto Protocol).
Kyoto Protocol obligates developed nations to meet certain emissions targets;
specific limits vary from country to country. If the Kyoto Protocol is approved
internationally and 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
seven percent below 1990 levels and its emissions of hydrofluorocarbons,
perfluorocarbons and sulfur hexaflouride by seven percent below 1990 or 1995
levels. The Kyoto Protocol must be ratified by the U.S. Senate in order for the
U.S. to become a party to the protocol. Major provisions of the Kyoto Protocol,
such as an international emissions trading program, have yet to be developed.
Until they are developed, the impact on NSP cannot be determined.
Water Quality Monitoring
In compliance with federal and state laws and state regulatory permit
requirements, and also in conformance with the Company's corporate environmental
policy, the Company has installed environmental monitoring systems at all coal
and RDF ash landfills and coal stockpiles to assess and monitor the impact of
these facilities on the quality of ground and surface waters. Degradation of
water quality in the state is prohibited by law and requires remedial action for
restoration to an agreed upon acceptable clean-up level. The cost of overall
water quality monitoring is not material in relation to NSP's operating results.
Electromagnetic Fields
<PAGE>
Electric and magnetic fields (sometimes referred to as EMF) surround
electric wires and conductors of electricity such as electrical tools, household
wiring, appliances, electric distribution lines, electric substations and
high-voltage electric transmission lines. NSP owns and operates many of these
types of facilities. Some studies have found statistical associations between
surrogates of EMF and some forms of cancer. The nation's electric utilities,
including NSP, have participated in the sponsorship of more than $115 million in
research to determine the possible health effects of EMF. Through its
participation with the Electric Power Research Institute and the EMF Research
and Public Information Dissemination Program, sponsored by the National
Institute of Environmental Health Sciences and the U.S. Department of Energy,
NSP 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 to
incur additional operating expenses for environmental purposes. NSP also cannot
predict whether future environmental regulations might result in significant
reductions in generating capacity or efficiency or otherwise affect NSP's
income, operations or facilities.
CAPITAL SPENDING AND FINANCING
NSP's capital spending program is designed to assure that there will be
adequate generating, transmission and distribution capacity to meet the future
electric and gas needs of its utility service area, and to fund investments in
non-regulated businesses. NSP continually reassesses needs and, when necessary,
appropriate changes are made in the capital expenditure program Current year
capital spending activity and future financing requirements and sources are
discussed in the Management's Discussion and Analysis under Item 7 herein.
On March 11, 1998, the Company 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 will be 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.
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1997 the total number of full- and part-time employees of
NSP was 7,455 and the total number of benefit employees was 6,718. Of this
number approximately 2,800 employees are represented by five local IBEW labor
unions under a three year collective bargaining agreement which expires Dec.
31, 1999.
401(k) CHANGES: NSP currently offers eligible employees a 401(k)
Retirement Savings Plan. In 1994, NSP began matching employees' pre-tax 401(k)
contributions. NSP's matching contributions were $4.4 million in 1997, based on
matching up to $900 for each nonbargaining employee and up to $700 for each
bargaining employee.
WAGE INCREASES: Under a market-based pay structure implemented for
nonbargaining employees in 1994, NSP uses salary surveys that indicate how other
relevant companies pay their employees for comparable positions. In January
1997, nonbargaining employees received an average wage increase of 4 percent,
and bargaining employees received a 2 percent base wage scale increase. In
January 1998, nonbargaining employees received an average wage scale increase of
3.4 percent. Base wage scale increases for bargaining employees in 1998 were 2
percent.
<PAGE>
EXECUTIVE OFFICERS *
--------------------
Present Positions and Business Experience
Name Age During the Past Five Years
- --------------------------------------------------------------------------------
JAMES J HOWARD 62 Chairman of the Board, President and Chief
Executive Officer since 12/01/94; and prior
thereto Chairman of the Board and Chief
Executive Officer.
- --------------------------------------------------------------------------------
LOREN L TAYLOR 51 President - NSP Electric since 10/27/94; and
prior thereto Vice President - Customer
Operations.
- --------------------------------------------------------------------------------
EDWARD L WATZL 58 President - NSP Generation since 02/03/97;
Vice President - Nuclear Generation from
09/07/94 to 02/02/97; and prior thereto
Prairie Island Site General Manager.
- --------------------------------------------------------------------------------
CYNTHIA L LESHER 49 President - NSP Gas since 07/01/97 and prior
thereto Vice President - Human Resources.
- --------------------------------------------------------------------------------
GARY R JOHNSON 51 Vice President & General Counsel since
11/01/91.
- --------------------------------------------------------------------------------
GRADY P BUTTS 51 Vice President - Human Resources since
07/01/97; Area Leader - Human Resources
Management Services from 08/01/93 to
06/30/97; and prior thereto Director of
Human Resources - Electric Utility.
- --------------------------------------------------------------------------------
* As of 3/01/98
<PAGE>
EXECUTIVE OFFICERS *
--------------------
Present Positions and Business Experience
Name Age During the Past Five Years
- --------------------------------------------------------------------------------
EDWARD J MCINTYRE 47 Vice President and Chief Financial Officer
since 01/01/93.
- --------------------------------------------------------------------------------
THOMAS A MICHELETTI 51 Vice President - Public and Government
Affairs since 10/27/94; Vice President -
General Counsel and Secretary of NRG Energy,
Inc. a wholly owned subsidiary of the
Company from 05/11/94 to 10/26/94; Vice
President-General Counsel, NRG from 09/15/93
to 05/10/94; and prior thereto Group Vice
President for Minnesota Power and Light
Company, a public utility located in Duluth,
MN.
- --------------------------------------------------------------------------------
ROGER D SANDEEN 52 Vice President and Controller since
07/01/89; and Chief Information Officer from
04/22/92 to 04/30/97.
- --------------------------------------------------------------------------------
PAUL E PENDER 43 Vice President - Finance and Treasurer since
05/01/97; Assistant Treasurer and Director,
Corporate Finance from 07/01/94 to 04/30/97;
Director, Corporate Finance from 02/01/93 to
06/30/94; and prior thereto Manager,
Financial and Investment Analysis.
- --------------------------------------------------------------------------------
MICHAEL D WADLEY 41 Vice President - Nuclear Generation since
02/03/97; Nuclear Plant Manager - Prairie
Island from 10/26/95 to 02/02/97; Plant
Manager - Prairie Island from 02/01/93 to
10/25/95; and prior thereto General
Superintendent of Operations - Prairie
Island.
- --------------------------------------------------------------------------------
JOHN P MOORE, JR 51 Corporate Secretary since 07/01/97; and
prior thereto General Counsel and Corporate
Secretary for the Wisconsin Company.
- --------------------------------------------------------------------------------
PAUL E ANDERS 54 Vice President and Chief Information Officer
since 05/01/97; and prior thereto Vice
President - Information Services at Chrysler
Financial Corporation located in Detroit,
MI.
- --------------------------------------------------------------------------------
* As of 3/01/98
<PAGE>
ITEM 2 - PROPERTIES
================================================================================
The Company's major electric generating facilities consist of the
following:
1997
Capability Output
Station and Unit Fuel Installed (Mw) (Millions of Kwh)
- ---------------- ---- --------- ---- -----------------
Sherburne
Unit 1 Coal 1976 712 4 440.5
Unit 2 Coal 1977 721 3 853.7
Unit 3 Coal 1987 514 3 743.3
Prairie Island
Unit 1 Nuclear 1973 514 3 521.9
Unit 2 Nuclear 1974 513 3 640.5
Monticello Nuclear 1971 545 3 656.7
King Coal 1968 571 3 501.3
Black Dog
4 Units Coal/Natural 1952-1960 462 1 350.8
Gas
High Bridge
2 Units Coal 1956-1959 263 1 153.8
Riverside
2 Units Coal 1964-1987 372 2 231.9
Other Various Various 1 945 1 816.3
NSP's electric generating facilities provided 76 percent of its Kwh
requirements in 1997. The current generating facilities are expected to be
adequate base load sources of electric energy until 2003-2006, as detailed in
the Company's electric resource plan filed with the MPUC in 1998. All of NSP's
major generating stations are located in Minnesota on land owned by the Company.
================================================================================
At Dec. 31, 1997, NSP had overhead transmission and distribution lines
as follows:
Voltage Length (Pole Miles)
------- -------------------
500Kv 265
345Kv 734
230Kv 283
161Kv 350
115Kv 1,609
Less than 115Kv 32,095
NSP also has approximately 280 transmission and distribution
substations with capacities greater than 10,000 kilovoltamperes (Kva) and
approximately 280 with capacities less than 10,000 Kva.
Manitoba Hydro, Minnesota Power Company and the Company completed the
construction of a 500-Kv transmission interconnection between Winnipeg,
Manitoba, Canada, and the Minneapolis-St Paul, Minnesota, area in 1980. NSP has
a contract with Manitoba Hydro-Electric Board for 500 Mw of firm power utilizing
this transmission line. In addition, the Company is interconnected with Manitoba
Hydro through a 230 Kv transmission line completed in 1970. In 1995 a project
was completed to increase the Manitoba-US transmission interconnection by a
nominal 400 Mw to 1900 Mw. This project was undertaken as part of a contract
where NSP and Manitoba Hydro have established an additional 150 Mw of seasonal
power exchange. (See Note 14 of Notes to Financial Statements under Item 8 for
further discussion of power purchase commitments.)
The electric delivery system utilization has increased during recent
years due to better analytical methods and enhanced Energy Management System
monitoring and control capability. This increased utilization has been achieved
while continuing to operate within reliability parameters established by MAPP
and North American Electric Reliability Council (NERC).
Plans are currently being implemented for electric delivery system
upgrades to accommodate load growth expected in the Minneapolis-St. Paul
geographic area through 2010. Recent studies have indicated load growth of
approximately two percent per year. As the least cost option to accommodate the
load growth, portions of the 69 Kv transmission facilities, especially located
on the outskirts of the Twin Cities, are being reconductored and operated at 115
Kv; distribution development in these areas have 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 as
compared with other alternatives for serving the load growth.
The natural gas properties of NSP include about 8,986 miles of natural
gas transmission and distribution mains. NSP natural gas mains include
<PAGE>
approximately 116 miles with a capacity in excess of 275 pounds per square inch
(psi) and approximately 8,870 miles with a capacity of less than 275 psi. In
addition, Viking owns a 500-mile interstate natural gas pipeline serving
portions of Minnesota, Wisconsin and North Dakota.
Virtually all of the utility plant of the Company and the Wisconsin
Company are subject to the lien of their first mortgage bond indentures pursuant
to which they have issued first mortgage bonds.
For discussion and information concerning nonregulated properties, see
"Nonregulated Subsidiaries", under Item 1, incorporated herein 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.
In 1993, a natural gas explosion occurred on the Company's distribution
system in St. Paul, Minnesota. As a result of this explosion, eighteen lawsuits,
including one lawsuit with multiple plaintiffs, were filed against the Company
and the City of St. Paul. By September 1997, the Company reached a settlement on
all of the lawsuits, and also resolved all known claims that had not advanced to
litigation. The Company's total costs for legal fees, disbursements, and
resolution of claims and lawsuits were $1 million. All expenditures paid by the
Company in excess of $1 million were reimbursed by its insurance provider
through the Company's general liability coverage policy.
On June 20, 1994, the Company along with other major utilities filed a
lawsuit against the DOE in an attempt to clarify the DOE's obligation to dispose
of spent nuclear fuel beginning not later than Jan. 31, 1998. The suit was filed
in the U.S. Court of Appeals for the District of Columbia Circuit (Court). The
primary purpose of the lawsuit was to insure that the Company and its customers
receive timely storage and disposal of spent nuclear fuel in accordance with the
terms of the Company's contract with the DOE. On July 23, 1996, the Court
affirmed the federal government's obligation. The Court unanimously ruled that
the Nuclear Waste Policy Act creates an unconditional obligation for the DOE to
begin acceptance of spent nuclear fuel by Jan. 31, 1998. The DOE did not seek
U.S. Supreme Court review. On Jan. 31, 1997, the Company, along with 30 other
electric utilities and 45 state agencies, filed another lawsuit against the DOE
requesting authority to withhold payments to the DOE for the permanent disposal
program. On May 7, 1997, the Company asked the Court to order the DOE to take
spent nuclear fuel by the Jan. 31, 1998 deadline. On Nov. 14, 1997, the Court
reiterated the unconditional obligation of the DOE to begin acceptance of spent
nuclear fuel by the 1998 deadline. The Court confirmed the obligation exists
under the statute and contract, but denied the request directing the DOE to
accept spent nuclear fuel by the deadline finding the contractual remedies under
the contract may be adequate. The Court also held that the DOE cannot use its
own delays or the unavailability of a permanent disposal or temporary storage
facility as a defense to utilities' actions. On Feb. 19, 1998, the Company and
other utilities asked the Court to order the DOE to develop a disposal program
to dispose of nuclear fuel beginning immediately; relief from an obligation to
pay fees to the Nuclear Waste Fund (Fund) and allow escrow of the funds until
the DOE is in compliance; prohibition of any suspension or termination of the
DOE's disposal contract; prevention of the DOE from paying damages related to
the breach of obligation from the Fund.
The Company is analyzing and preparing continuing legal actions against
the DOE to enforce its statutory and contractual obligations. NSP and other
utilities are currently analyzing claims against the DOE for the costs incurred
as a result of the DOE's failure to meet its statutory and contractual
obligations.
In October 1996, the Company was named in a class action lawsuit
commenced by two commercial customers, who claimed that the expected energy
savings from NSP's lighting efficiency program were misrepresented. On Jan. 22,
1998, a Hennepin County District Court Judge granted NSP's motion for summary
judgment and dismissed the class action lawsuit in its entirety. The plaintiffs
have until June 1, 1998 to appeal the Hennepin County District Court decision.
On June 10, 1997, the Minnesota Office of the Attorney General (OAG)
petitioned the MPUC to investigate the Company's meter reading and billing
practices and to authorize the OAG to pursue civil penalties. The Company
contested the claims before the MPUC. On Jan. 29, 1998, the parties reached an
agreement on settlement terms which will obligate NSP to provide approximately
$3 million in immediate customer credits, up to $3 million of additional
assistance to low-income customers over the next three years, and to meet
certain agreed-to performance standards. The settlement agreement was approved
by the MPUC on March 3, 1998. The Company continues to deny any liability, and
entered into the agreement to avoid potentially significant litigation costs.
The Company recorded an estimated liability for the customer credits in its 1997
financial statements.
On Sept. 15, 1997, NSP sought a determination in which the city of
Oakdale,
<PAGE>
Minnesota (City) must abide by the Company's tariffs filed with the MPUC in the
Washington County District Court. The tariffs require the City to pay the
additional cost of undergrounding electrical facilities prior to installation.
On Feb. 18, 1998, the judge held that NSP must abide by the City's
undergrounding ordinance which is silent on the issue of responsibility for
payment of additional costs. The judge also ruled the tariff requiring the City
to incur the additional costs was not binding on the City. As the judge's ruling
is contrary to prior decisions of the Minnesota Court of Appeals, NSP will
appeal the decision to that court in 1998. If the decision is not overruled, NSP
would have to include the additional costs of undergrounding facilities in
future rate cases or the costs would reduce earnings. Currently, the City has
allowed NSP to construct its facilities overhead and no construction project
will be delayed due to the appeal.
On Jan. 23, 1998, Commonwealth Edison Company (ComEd) filed a complaint
with the FERC against MAPP and its individual members (including the Company and
the Wisconsin Company). The complaint alleged that the electric transmission
curtailment procedures applied under the restated MAPP agreement and the NSP
Open Access Transmission Tariff do not comply with FERC Order No. 888. The
complaint alleges application of the MAPP procedure caused curtailment of
certain ComEd transactions during May 1997, to the detriment of ComEd. On March
9, 1998, MAPP filed an answer denying the ComEd allegations, and NSP submitted a
separate filing asking FERC to dismiss the complaint. ComEd requested that the
FERC order MAPP and its members to revise their procedures and ComEd seeks such
other and further relief that the FERC deems proper, including modifications to
rate schedules or tariffs, if necessary.
For a discussion of environmental proceedings, see "Environmental
Matters" under Item 1, incorporated herein by reference. For a discussion of
proceedings involving NSP's utility rates, see "Utility Regulation and Revenues"
and "Gas Utility Operations" under Item 1, incorporated herein by reference.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
================================================================================
None during the fourth quarter of 1997.
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
================================================================================
Quarterly Stock Data
The Company's common stock is listed on the New York Stock Exchange
(NYSE), Chicago Stock Exchange (CHX) and the Pacific Stock Exchange (PCX).
Following are the reported high and low sales prices based on the NYSE Composite
Transactions for the quarters of 1997 and 1996 and the dividends declared per
share during those quarters:
1997 1996
----- ----
High Low Dividends High Low Dividends
------------------------------------------------------------
First Quarter $49 1/8 $45 1/2 $.690 $53 3/8 $47 5/8 $.675
Second Quarter 52 44 1/2 .705 49 5/8 45 1/2 .690
Third Quarter 52 15/16 48 .705 49 3/4 44 1/2 .690
Fourth Quarter 58 7/8 48 7/16 .705 49 1/8 45 1/2 .690
<PAGE>
1997 1996 1995 1994 1993
----- ------ ------ ------ ------
Shareholders of record
at year-end 83 232 86 337 83 902 85 263 86 404
Book value per share
at year-end $31.78 $30.93 $29.74 $28.35 $27.32
Shareholders of record as of March 15, 1998 were 82,955.
The Company's Restated Articles of Incorporation and First Mortgage
Bond Trust Indenture provide for certain restrictions on the payment of cash
dividends on common stock. At Dec. 31, 1997, the payment of cash dividends on
common stock was not restricted except as described in Note 3 to the Financial
Statements under Item 8 herein.
ITEM 6 - SELECTED FINANCIAL DATA
================================================================================
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
(Dollars in millions except per share data)
<S> <C> <C> <C> <C> <C>
Utility operating revenues $2 734 $2 654 $2 569 $2 487 $2 404
Utility operating expenses $2 372 $2 288 $2 223 $2 178 $2 100
Net income (1) $237 $275 $276 $243 $212
Earnings available for common stock (1) $226 $262 $263 $231 $197
Average number of common shares
outstanding (000) 70 297 68 561 67 323 66 775 65 116
Average number of common and
potentially dilutive shares outstanding (000's) 70 435 68 679 67 416 66 845 65 211
Earnings per average common share:
Basic (1) $3.22 $3.83 $3.91 $3.46 $3.03
Assuming Dilution (1) $3.21 $3.82 $3.91 $3.46 $3.02
Dividends declared per share $2.805 $2.745 $2.685 $2.625 $2.565
Total assets $7 144 $6 637 $6 229 $5 950 $5 588
Long-term debt $1 879 $1 593 $1 542 $1 463 $1 292
Ratio of earnings (excluding undistributed
equity income and including AFC)
to fixed charges 2.9 3.8 3.9 4.0 4.0
</TABLE>
Notes:
AFC - Allowance for Funds Used During Construction
(1) Net income and earnings per share include nonrecurring items in 1997 and
1995, as discussed in Management's Discussion and Analysis under Item 7.
Excluding these nonrecurring items, earnings per share, assuming dilution,
from ongoing operations were $3.54 and $3.69, respectively, and the average
annual growth rate in earnings per share since 1993 was 4.1 percent.
<PAGE>
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND
RESULTS OF OPERATIONS
================================================================================
MANAGEMENT'S DISCUSSION AND ANALYSIS
Northern States Power Company, a Minnesota corporation (the Company), has two
significant subsidiaries: Northern States Power Company, a Wisconsin corporation
(the Wisconsin Company), and NRG Energy, Inc., a Delaware corporation (NRG). The
Company also has several other subsidiaries, including Viking Gas Transmission
Company (Viking), Energy Masters International, Inc. (EMI), which changed its
name from Cenerprise, Inc., effective Sept. 1, 1997, and Eloigne Company
(Eloigne). The Company and its subsidiaries collectively are referred to herein
as NSP.
FINANCIAL OBJECTIVES AND RESULTS
NSP's financial objectives are:
* TO PROVIDE INVESTOR RETURNS IN THE TOP ONE-FOURTH OF THE UTILITY
INDUSTRY AS MEASURED BY A THREE-YEAR AVERAGE RETURN ON EQUITY. NSP's
average return on common equity for the three years ending in 1997 was
12.0 percent. Based on a three-year average, this return places NSP
below the top one-fourth of the industry, which was approximately 12.7
percent, and above the median three-year industry average of
approximately 11.3 percent. The total return to investors (measured by
dividends plus stock price appreciation) on NSP common stock for the
most recent five-year period averaged 12.4 percent per year. For the
same period, the total return for the electric industry averaged 10.7
percent. NSP's stock price rose 27.0 percent over the year, well above
the 22.1 percent average increase of other utilities rated AA by
Standard & Poor's (S&P).
* TO INCREASE DIVIDENDS ON A REGULAR BASIS AND MAINTAIN A LONG-TERM
AVERAGE PAYOUT RATIO IN THE RANGE OF 65 TO 75 PERCENT. NSP has
increased its dividend for 23 consecutive years. In June 1997, NSP's
annualized common dividend rate was increased by 6 cents per share, or
2.2 percent, from $2.76 to $2.82. The dividend payout ratio was 89.4
percent in 1997, above the objective range due to the unusual events
that adversely affected NSP's earnings in 1997. (See discussion under
Results of Operations.) The objective payout ratio is based on
long-term earnings expectations.
* TO MAINTAIN LONG-TERM AVERAGE ANNUAL EARNINGS PER SHARE GROWTH OF 5
PERCENT FROM ONGOING OPERATIONS, AS DESCRIBED BELOW. Excluding the
nonrecurring items discussed later under Factors Affecting Results of
Operations, NSP's earnings per share have grown by an average annual
rate of 4.1 percent since 1993.
1997 1996 1995
---------------------------------------------------------------------------
EARNINGS PER SHARE FROM ONGOING OPERATIONS $3.54 $3.82 $3.69
Earnings (losses) from nonrecurring items (.33) 0.22
---------------------------------------------------------------------------
Total earnings per share $3.21 $3.82 $3.91
===========================================================================
* TO PROVIDE AT LEAST 20 PERCENT OF NSP EARNINGS FROM NRG BUSINESSES BY
THE YEAR 2000. NRG expects to meet this goal through the growing
profitability of existing businesses and the addition of new
businesses. Businesses owned by NRG provided 39 cents, or 11 percent,
of NSP's earnings per share from ongoing operations in 1997, and 29
cents, or 7.6 percent, of NSP's earnings per share from ongoing
operations in 1996.
* TO MAINTAIN CONTINUED FINANCIAL STRENGTH WITH A AA RATING FOR UTILITY
BONDS. The Company's first mortgage bonds continued to be rated AA by
Fitch Investors Service, Inc. In October 1997, S&P's raised NSP's bond
rating to AA, as a part of an industry re-evaluation. In July 1997,
Moody's Investors Services (Moody's) upgraded its rating on NSP's first
mortgage bonds to Aa3. Moody's rating action reflects NSP's progress in
satisfying legislative requirements associated with spent-fuel storage
at Prairie Island and various other factors. Moody's also cited NSP's
healthy competitive position and strong financial condition. Duff &
Phelps, Inc. raised the Company's bond rating to AA in February 1998.
First mortgage bonds issued by the Wisconsin Company carry comparable
ratings. NSP's pretax interest coverage ratio for utility operations,
based on income excluding Allowance for Funds Used During Construction
(AFC), was 3.5 in 1997. A capital structure consisting of 46.7 percent
common equity at year-end 1997 contributes to NSP's financial
flexibility and strength.
<PAGE>
BUSINESS STRATEGIES
NSP's mission is to be a recognized leader in the energy industry by increasing
the value provided to our customers with energy-related products and services.
We will utilize the skills and talents of our people to thrive in a dynamic and
competitive energy environment that provides increased value for our customers
and shareholders and significant growth opportunities for our company.
Strategies to achieve this mission include:
* EXCEEDING CUSTOMER REQUIREMENTS. Anticipate and exceed customer
requirements by balancing costs, benefits and expectations to maximize
value for each customer.
* IMPROVE COMPETITIVENESS. Achieve and maintain best quartile status in
the service and price of providing our electric and gas products.
* SUPPORT EMPLOYEES. Gain competitive advantage by fully utilizing the
diversity, skills and talents of our people.
* SUPPORT THE COMMUNITY AND THE ENVIRONMENT. Preserve and enhance NSP's
name and reputation by protecting the environment and helping to meet
the social and economic needs of the community, thereby contributing to
the growth of the community and creating support for our business
requirements.
* GROW THE BUSINESS PROFITABLY. Build on our core businesses,
subsidiaries and strategic acquisitions to profitably grow our company,
enhance shareholder value and excel in a dynamic industry environment.
FINANCIAL REVIEW
The following discussion and analysis by management focuses on those factors
that had a material effect on NSP's financial condition and results of
operations during 1997 and 1996. It should be read in conjunction with the
accompanying Financial Statements and Notes thereto. Trends and contingencies of
a material nature are discussed to the extent known and considered relevant.
Material changes in balance sheet items are discussed below and in the
accompanying Notes to Financial Statements.
Except for the historical information contained herein, the matters discussed in
the following discussion and analysis are forward-looking statements that are
subject to certain risks, uncertainties and assumptions. Such forward-looking
statements are intended to be identified in this document by the words
"anticipate," "estimate," "expect," "objective," "possible," "potential" and
similar expressions. Actual results may vary materially. Factors that could
cause actual results to differ materially include, but are not limited to:
general economic conditions, including their impact on capital expenditures;
business conditions in the energy industry; competitive factors; unusual
weather; changes in federal or state legislation; regulation; the items
discussed under "Factors Affecting Results of Operations"; and the other risk
factors listed from time to time by the Company in reports filed with the
Securities and Exchange Commission (SEC), including Exhibit 99.01 to the
Company's 1997 report on Form 10-K.
<PAGE>
RESULTS OF OPERATIONS
1997 COMPARED WITH 1996 AND 1995
NSP's 1997 earnings per share from ongoing operations (assuming dilution) were
$3.54, down 28 cents, or 7.3 percent, from the $3.82 earned in 1996 and down 15
cents, or 4.1 percent, from the $3.69 earned in 1995. NSP's total earnings per
share (assuming dilution), including nonrecurring transactions in 1997 and 1995
(as discussed later), were $3.21 in 1997, $3.82 in 1996 and $3.91 in 1995.
Nonrecurring transactions in 1997 include the write-off of costs incurred prior
to the termination of NSP's proposed merger with Wisconsin Energy Corporation
(WEC) and NRG's write-down of a cogeneration project.
Regulated utility businesses generated earnings of $3.24 per share from ongoing
operations in 1997, $3.58 in 1996 and $3.41 in 1995. Earnings from ongoing
regulated operations were lower in 1997, primarily due to higher utility
operations, maintenance and depreciation expenses, the impacts of less favorable
weather, and dilutive effects of stock issuances. Partially offsetting these
earnings decreases were growth in electric sales and reduced administrative
costs.
Nonregulated businesses generated earnings from ongoing operations of 30 cents
per share in 1997, 24 cents in 1996 and 28 cents in 1995. Nonregulated earnings
increased in 1997 primarily due to higher NRG earnings from new projects,
including tax credits. Increased financing costs at NRG and losses incurred by
EMI partially offset these increases.
UTILITY OPERATING RESULTS
ELECTRIC REVENUES Sales to retail customers, which account for more than 90
percent of NSP's electric revenue, increased 1.5 percent in 1997 and 1.0 percent
in 1996. Sales in 1997 included unfavorable weather impacts compared with normal
average temperatures, and sales in 1996 and 1995 included favorable weather
impacts compared with normal average temperatures, with the retail sales impact
for 1996 being less favorable than it was in 1995. Total electric sales volumes
increased 0.6 percent in 1997 and decreased 3.0 percent in 1996. Lower sales
volumes to other utilities in 1997 and 1996 and the loss of several municipal
power customers in 1995 and 1996 partially offset the retail sales growth in
1997 and contributed to the 1996 decrease.
On a weather-adjusted basis, retail electric sales volumes are estimated to have
increased 2.6 percent in 1997 and 1.5 percent in 1996. Retail electric sales
growth for 1998 is estimated to be 2.0 percent over 1997, or 1.5 percent, on a
weather-adjusted basis.
Sales volumes to other utilities decreased 5.2 percent in 1997, while revenues
increased in 1997 (as shown in the following table). Constraints on NSP's system
due to unscheduled plant outages and storms (as discussed later) contributed to
the decrease in volumes in 1997, while higher market prices due to market
conditions contributed to the revenue increase in 1997. Market conditions and
regional transmission system constraints contributed to the sales decrease in
1996.
The table below summarizes the principal reasons for the electric revenue
changes during the past two years:
(Millions of dollars) 1997 VS. 1996 1996 vs. 1995
- --------------------------------------------------------------------------------
Retail sales growth (excluding weather impacts) $47 $ 29
Estimated impact of weather on retail sales volume (23) (15)
Sales to other utilities 14 (20)
Municipal power sales (6) (15)
Conservation cost recovery 10 13
Fuel cost recovery 31 (10)
Other rate changes (1) (5)
Transmission and other electric revenues 19 8
- --------------------------------------------------------------------------------
Total revenue increase (decrease) $91 $(15)
================================================================================
<PAGE>
ELECTRIC PRODUCTION EXPENSES Fuel expense for electric generation in 1997
increased $8.8 million, or 2.9 percent, compared with a decrease of $24.5
million, or 7.5 percent, in 1996. The 1997 increase is primarily due to higher
average fossil fuel prices, mainly reflecting the increased use of higher-cost
plants due to plant outages and transmission line and plant limitations, as
discussed later. In 1997, management decided to take the Company's Monticello
nuclear generating plant, a baseload plant, out of service to accelerate
implementation of a design change originally planned for 1998. In addition,
during the summer of 1997, portions of transmission lines connecting two of
NSP's baseload generating plants, the Monticello nuclear and Sherco fossil
plants, to the Minneapolis-St. Paul metro area were damaged by storms. Until
repairs were completed later in 1997, the Company's generating and transmission
capabilities were temporarily reduced. As a result, NSP increased generation at
its more expensive peaking plants and purchased more power to meet 1997 sales
requirements. The 1996 decrease was primarily due to lower average fuel costs
resulting from a new coal transportation contract in July 1995, and lower plant
output caused by decreased electric sales, planned maintenance outages and
conversion of two plants to peaking status.
Purchased power costs increased $42.7 million, or 17.5 percent, in 1997 after
decreasing $4.1 million, or 1.7 percent, in 1996. The 1997 increase was
primarily due to higher purchases, higher average market prices and higher
demand expenses. The higher purchases were a result of lower plant availability
due to the unplanned nuclear plant outage and storms, as discussed previously,
and higher 1997 sales requirements. The 1996 decrease primarily was due to lower
demand expenses.
GAS REVENUES The majority of NSP's retail gas sales are categorized as firm
(primarily heating customers) and interruptible (commercial/industrial customers
with an alternate energy supply). Firm sales in 1997 decreased 10.8 percent
compared with 1996 sales, while firm sales in 1996 increased 13.2 percent
compared with 1995 sales. The decrease in 1997 was primarily due to the impacts
of favorable weather in 1996 and unfavorable weather in 1997, partially offset
by sales growth. The increase in 1996 primarily was due to strong sales growth
and favorable impacts of weather.
On a weather-adjusted basis, firm gas sales are estimated to have increased 2.2
percent in 1997 and increased 5.1 percent in 1996. The firm sales increase in
1997 was partially offset by lost gas sales as a result of flooding in the Grand
Forks area. Firm gas sales in 1998 are estimated to be 7.0 percent higher
compared with 1997 sales, or 3.3 percent higher on a weather-adjusted basis.
Interruptible sales of gas increased 11.6 percent in 1997 and 3.6 percent in
1996. The increases in both years are the result of favorable gas market prices
compared with alternate fuels that caused large interruptible customers with
alternate fuel sources to use more natural gas. Other gas deliveries, including
Viking sales, increased 0.6 percent in 1997 and 5.3 percent in 1996. Viking gas
transmission deliveries to parties other than NSP increased 4.8 percent in 1997
and 7.7 percent in 1996.
The table below summarizes the principal reasons for the gas revenue changes
during the past two years:
(Millions of dollars) 1997 VS. 1996 1996 vs. 1995
- --------------------------------------------------------------------------------
Sales growth (excluding weather impacts) $13 $ 25
Estimated impact of weather on firm sales volume (41) 13
Purchased gas adjustment clause recovery 28 52
Conservation cost recovery and other rate changes (1) 6
Transportation and other (11) 5
- --------------------------------------------------------------------------------
Total revenue increase (decrease) $(12) $101
================================================================================
COST OF GAS PURCHASED AND TRANSPORTED The cost of gas purchased and transported
decreased $4.2 million, or 1.2 percent, in 1997, primarily due to lower gas
sendout partially offset by a 6.7 percent increase in the per unit cost of
purchased gas. The lower sendout reflects decreased gas sales, as discussed
previously, while the increase in cost per unit of purchased gas, occurring
mainly in the first quarter of 1997, reflects changes in market conditions. The
cost of gas purchased and transported increased $78.7 million, or 30.6 percent,
in 1996, primarily due to a 20.5 percent increase in the per unit cost of
purchased gas and higher gas sendout. The increase in gas sendout reflects
increased gas sales, while the increase in cost per unit of purchased gas
reflects changes in market conditions.
<PAGE>
OTHER OPERATION, MAINTENANCE AND ADMINISTRATIVE AND GENERAL These expenses, in
total, increased by $37.4 million, or 5.9 percent, in 1997, compared with a
decrease of $24.9 million, or 3.8 percent, in 1996. The higher costs in 1997 are
primarily due to increased operating expenses associated with 1997 business
interruptions, higher customer service expenses, increased network transmission
service (NTS) costs, as discussed under Factors Affecting Results of Operations,
higher scheduled plant maintenance outage expenses and higher technology
improvement expenses. Business interruptions in 1997 included flooding in the
Company's service area, the unscheduled Monticello plant outage and storm damage
to transmission lines. Technology improvements included development of customer
information, automated meter reading and other systems, including preparation
for the year 2000. These cost increases were partially offset by a $6.9 million
decrease in administrative and general expenses, reflecting decreases in
insurance and employee benefit costs.
The lower costs in 1996 largely are due to lower administrative and general
costs, partly offset by higher scheduled plant maintenance outage expenses and
provisions for uncollectible accounts. Administrative and general expenses in
1996 reflect fewer employees and decreases in insurance and claims, employee
benefit and other corporate costs. (See Note 8 to the Financial Statements for a
summary of administrative and general expenses.)
CONSERVATION AND ENERGY MANAGEMENT Expenses increased in both 1997 and 1996
mainly due to higher amortization levels of deferred electric and gas
conservation and energy management program costs. Higher cost levels in 1996
also include the effects of expensing currently (rather than amortizing over a
period of time) new conservation expenditures beginning in 1996. These higher
amortization and cost levels are recovered concurrently through retail rate
adjustment clauses in the Company's Minnesota jurisdiction, which are discussed
later under Factors Affecting Results of Operations.
DEPRECIATION AND AMORTIZATION The increases in 1997 and 1996 reflect higher
levels of depreciable plant, including new information systems and equipment in
1997 and 1996 with relatively short useful lives. Information technology
improvements are expected to continue in 1998.
PROPERTY AND GENERAL TAXES Property and general taxes decreased in 1997 and
1996, primarily due to lower property tax rates partially offset by increases
due to property additions.
UTILITY INCOME TAXES The variations in income taxes primarily are attributable
to fluctuations in taxable income and changes to effective tax rates. (See Note
7 to the Financial Statements for a detailed reconciliation of the statutory tax
rate to NSP's effective tax rate.)
NONOPERATING ITEMS RELATED TO UTILITY BUSINESSES
MERGER COSTS In May 1997, NSP and WEC mutually terminated their plans to merge.
NSP's earnings for 1997 include a pretax charge to nonoperating expense of $29
million, or 25 cents per share, to write off its cumulative merger-related costs
incurred. This charge is being reported as a nonrecurring item outside of
earnings from ongoing operations.
UTILITY FINANCING COSTS Interest costs recognized for NSP's utility businesses,
including amounts capitalized to reflect the financing costs of construction
activities, were $120.3 million in 1997, $123.1 million in 1996 and $123.4
million in 1995. The 1997 decrease is due primarily to lower average short-term
borrowing levels, and the retirement of $100 million of first mortgage bonds in
October 1997. The slight 1996 decrease is largely due to lower interest costs on
variable rate long-term debt, partially offset by higher average short-term
borrowing levels. The average short-term debt balance was $208.3 million in
1997, $265.4 million in 1996 and $208.7 million in 1995. In addition to interest
expense, beginning in 1997, financing costs of NSP's utility businesses include
distributions on redeemable preferred securities.
<PAGE>
NONREGULATED BUSINESS RESULTS
NSP's nonregulated operations include diversified businesses such as NRG's
businesses, which are primarily independent power production, commercial and
industrial heating and cooling, and energy-related refuse-derived fuel
production. In addition, EMI's primary business is energy sales and service. NSP
also has investments in affordable housing projects through Eloigne and several
income-producing properties through other subsidiaries. Due to the nature of
these nonregulated businesses, NSP anticipates that the earnings from
nonregulated operations will experience more variability than regulated utility
businesses. As discussed below and shown in Note 8 to the Financial Statements,
NSP's nonregulated earnings for these periods are experiencing such variability.
The following summarizes the earnings contributions of NSP's nonregulated
businesses:
CONTRIBUTION TO NSP'S EARNINGS PER SHARE
1997 1996 1995
- --------------------------------------------------------------------------------
NRG:
Ongoing operations $0.39 $0.29 $0.24
Nonrecurring items (0.08) 0.00 0.22
Eloigne 0.06 0.05 0.02
EMI (0.15) (0.12) (0.02)
Seren Innovations (0.02) .00 .00
Other (1) 0.02 0.02 0.04
- -------------------------------------------------------------------------------
Total $0.22 $0.24 $0.50
===============================================================================
(1) Includes NSP-owned refuse-derived fuel operations managed by NRG
NRG
NRG's earnings from ongoing operations (excluding the nonrecurring transaction
discussed later) increased in 1997, compared with 1996, primarily due to income
from new projects, including tax credits. New projects contributing to NRG's
earnings increase include: Bolivian Power Company Ltd. (COBEE); Pacific
Generation Company (PGC); the Schkopau power generating facility in Germany,
which began operation in July 1996; and the Australian State of Victoria's Loy
Yang A power plant in which NRG, through affiliates, purchased a 25.37 percent
interest in May 1997. NRG's landfill gas subsidiary, NEO, has entered into
projects in 1996 and 1997 that are generating higher levels of energy tax
credits. Also contributing to NRG's increased earnings were the gains on the
sale of equity interests in two projects late in 1997. Higher interest costs due
to the $250 million senior notes issued in mid-1997 partially offset the
increased earnings. NRG's earnings in 1997 were adversely affected by declines
in the value of the Australian dollar and German deutsche mark in relation to
the U.S. dollar. Had exchange rates throughout 1997 stayed the same as the
beginning of the year, NRG's 1997 earnings would have been higher by
approximately 4 cents per share.
As of year-end 1997, NRG and its partner's effort to restructure the debt of the
58-megawatt Sunnyside cogeneration project in Utah was not successful. Due to a
lack of progress in restructuring the project's debt, NRG recorded a
nonrecurring expense of 8 cents per share to write down its investment in the
Sunnyside project late in 1997. This write-down reduced income from nonregulated
businesses before interest and taxes by $9 million for 1997 and is considered a
nonrecurring item.
Excluding the nonrecurring items discussed later, NRG's earnings from ongoing
operations increased in 1996, compared with 1995, due primarily to higher equity
in earnings of projects. Equity in earnings of projects increased in 1996,
primarily due to first-time earnings from Schkopau and NRG Generating (U.S.)
Inc. and higher income from Scudder Latin American Power Projects. These
earnings were partially offset by lower equity earnings from the MIBRAG project.
Equity in earnings from MIBRAG decreased, primarily due to an expected decline
in heating briquette and coal sales. NRG's earnings from ongoing operations were
higher in 1996, as compared with 1995, despite experiencing an increased level
of business development costs in 1996 as it pursued several international and
domestic projects. Until there is substantial assurance that a project in
development will come to financial closure, such costs are expensed.
NRG's earnings for 1995 included two nonrecurring items that added 22 cents to
1995 earnings. A gain of approximately 26 cents per share was recorded for a
power sales contract termination settlement, which was partially offset by a
domestic energy project write-down of 4 cents per share.
Further information on NRG's financial results may be obtained from NRG's annual
report on Form 10-K filed with the SEC.
<PAGE>
EMI
EMI's losses for 1997 were higher than 1996, primarily due to losses incurred by
EMI's gas marketing joint venture, Enerval, the partial write-down of EMI's
investment in Enerval, and increased expenses related to combining operations
with Energy Solutions International, Inc. (ESI) and Energy Masters Corporation
(EMC), both purchased by EMI in July 1997. These increased losses were partially
offset by increased operating margins, primarily due to the curtailment of gas
trading activity in the second quarter of 1996, which had negatively impacted
operating margins during the first half of 1996. EMI is currently in the process
of evaluating proposals for the sale of its interest in Enerval and expects to
finalize the sale during the first quarter of 1998. EMI's investment in and
advances to Enerval have been written down to an estimate of their net
realizable value.
EMI's earnings for 1996 decreased, compared with 1995, largely due to price
volatility in the gas market, which adversely affected earnings from Enerval,
and losses incurred from the gas trading business.
OTHER
Eloigne's earnings have continued to grow in 1997 and 1996 due to investments in
new affordable housing projects. NSP's new communications and data services
subsidiary, Seren Innovations, experienced a loss in its first year, 1997, as it
focused on development of its products and services.
FACTORS AFFECTING RESULTS OF OPERATIONS
NSP's results of operations during 1997, 1996 and 1995 primarily were dependent
upon the operations of the Company's and Wisconsin Company's utility businesses,
consisting of the generation, transmission, distribution and sale of
electricity, and the distribution, transportation and sale of natural gas. NSP's
utility revenues depend on customer usage, which varies with weather conditions,
general business conditions, the state of the economy and the cost of energy
services. Various regulatory agencies approve the prices for electric and gas
service within their respective jurisdictions. In addition, NSP's nonregulated
businesses are contributing to NSP's earnings. The historical and future trends
of NSP's operating results have been and are expected to be affected by the
following factors:
REGULATION NSP's utility rates are approved by the Federal Energy Regulatory
Commission (FERC) and state regulatory commissions in Minnesota, North Dakota,
South Dakota, Wisconsin and Michigan. Rates are designed to recover plant
investment and operating costs and an allowed return on investment, using an
annual period upon which rate case filings are based. NSP requests changes in
rates for utility services as needed through filings with the governing
commissions. The rates charged to retail customers in Wisconsin are reviewed and
adjusted biennially. Because comprehensive rate changes are not requested
annually in Minnesota, NSP's primary jurisdiction, changes in operating costs
can affect NSP's earnings, shareholders' equity and other financial results.
Except for Wisconsin electric operations, NSP's retail rate schedules provide
for cost-of-energy and resource adjustments to billings and revenues for changes
in the cost of fuel for electric generation, purchased energy, purchased gas,
and, in Minnesota, conservation and energy management program costs. For
Wisconsin electric operations, where cost-of-energy adjustment clauses are not
used, the biennial retail rate review process and an interim fuel cost hearing
process provide the opportunity for rate recovery of changes in electric fuel
and purchased energy costs in lieu of a cost-of-energy adjustment clause. In
addition to changes in operating costs, other factors affecting rate filings are
sales growth, conservation and demand-side management efforts and the cost of
capital.
As discussed in Note 1 to the Financial Statements, regulated public utilities
are allowed to record as assets certain costs that would be expensed by
nonregulated enterprises, and to record as liabilities certain gains that would
be recognized as income by nonregulated enterprises. If deregulation or other
changes in the regulatory environment occur, NSP may no longer be eligible to
apply this accounting treatment and may be required to eliminate such regulatory
assets and liabilities from its balance sheet. Such changes could have a
material adverse effect on NSP's results of operations in the period the
write-off is recorded. At Dec. 31, 1997, NSP reported on its balance sheet
approximately $212 million and $129 million of regulatory assets and
liabilities, respectively, that would need to be recognized in the income
statement in the absence of regulation. Included in these regulatory assets are
$87 million of conservation expenditures that are anticipated to be
substantially recovered by the year 2000 based on accelerated recovery available
through resource adjustment clauses to customer rates, as discussed previously.
In addition to a potential write-off of regulatory assets and liabilities,
deregulation and competition (as discussed later) may require recognition of
certain "stranded costs" not recoverable under market pricing. NSP currently is
<PAGE>
recovering its costs in all regulated jurisdictions and does not expect to write
off to expense any "stranded costs" unless and until market price levels change,
or unless cost levels increase above market price levels.
RATE FILINGS On Dec. 2, 1997, the Company filed a natural gas rate case seeking
an annual rate increase of approximately $18.5 million for retail customers in
Minnesota. An interim rate increase totaling $13.9 million on an annual basis
has been approved, subject to refund, effective Feb. 1, 1998.
On Nov. 14, 1997, the Wisconsin Company filed retail electric and natural gas
rate cases for Wisconsin customers requesting that the rate changes become
effective during the second quarter of 1998. The Wisconsin Company is seeking an
annual increase in retail electric rates of approximately $12.7 million and an
annual decrease in retail natural gas rates of approximately $1.7 million.
On February 17, 1998, NSP filed a rate application with the FERC to update its
rates for point to point transmission service. As filed, the proposed rates
increase annual transmission revenues by approximately $4 million. In addition,
the filing is expected to support reductions in NSP's NTS costs, as discussed
later.
COMPETITION The Energy Policy Act of 1992 (the Act) has been a catalyst for
comprehensive and significant changes in the operation of electric utilities,
including increased competition. The Act's reform of the Public Utility Holding
Company Act of 1935 (PUHCA) promoted creation of wholesale nonutility power
generators and authorized the FERC to require utilities to provide wholesale
transmission services to third parties. The legislation allows utilities and
nonregulated companies to build, own and operate power plants nationally and
internationally without being subject to restrictions that previously applied to
utilities under the PUHCA. NSP plans to continue its efforts to be a
competitively priced supplier of electricity and an active participant in the
competitive market for electricity.
In 1996, the FERC issued Orders No. 888 and 889, which have had a significant
impact on wholesale electric markets by giving competitors the ability to
transmit electricity through utilities' transmission systems. Order No. 888
granted nondiscriminatory access to transmission service. Order No. 889 ensures
a fair market by imposing standards of conduct on transmission system owners, by
requiring separation of the wholesale power supply ("merchant") function from
the transmission system operation function and by mandating the posting of
transmission availability and pricing information on an electronic bulletin
board. These new open access rules became effective in 1996 and 1997. In 1997,
the FERC issued clarifying final orders in response to rehearing requests by
numerous market participants regarding Orders No. 888 and 889. These FERC
clarifying final orders are currently being appealed in federal court. NSP has
made transmission filings with the FERC and believes it is taking the proper
steps to comply with the new rules as they become effective. NSP continues to be
generally supportive of the FERC's efforts to increase competition.
In compliance with FERC Orders No. 888 and 889, NSP has separated personnel who
perform the merchant function, which includes power and energy marketing and
trading, from personnel who perform the transmission system operation function.
In 1997, NSP's merchant function, NSP Energy Marketing, expanded its power
trading to focus on new market opportunities created by open transmission
access. NSP is also developing risk management practices to respond to the
rapidly growing electric commodity market. In addition, a significant effort was
put forth in 1997 to enter current and all new requests for transmission service
into the electronic bulletin board, as directed by FERC Order No. 889 and
supported by NSP.
The FERC Order No. 888 requires utilities to offer, among other services,
Network Transmission Service (NTS) to qualifying customers. Under NTS, NSP and
other qualifying regional utilities share the total annual costs of operating
and maintaining the regional transmission network that NSP uses, net of related
network revenues, based on each company's share of the total network load. The
transmission tariff filed with the FERC is used as the cost basis for
FERC-regulated utilities in determining NTS rates. In 1997, NSP conducted a
review of information received from other participating utilities and commenced
settlement negotiations with these utilities regarding the final amount of NTS
costs to be paid by NSP for 1997. Based on this review and discussion, NSP
concluded that its net NTS costs for 1997 were less than the $27 million
previously estimated. NSP recorded a liability for what management believes is a
reasonable estimate of the net NTS costs for 1997. NSP expects that its
transmission tariff filing and settlement negotiations will result in lower NTS
costs in 1998.
Some states have begun to allow retail customers to choose their electricity
supplier, and many other states are considering retail access proposals. NSP
believes that retail competition will result in more innovative services and
<PAGE>
lower prices for all consumers if the transition is managed in a thoughtful
manner. NSP supports fair and equal treatment for all competitors, recovery of
utilities' investments made under traditional regulation and a resolution of
property tax issues. NSP supports a plan that would take two or three years to
resolve these issues and develop infrastructure, and another two to three years
to phase in customers' choice. In 1997, the Minnesota Public Utilities
Commission (MPUC) approved a report by its staff that identifies issues that
must be resolved before retail competition can begin, but did not approve an
action plan or schedule for its implementation. The Minnesota Legislature began
studying the issues in 1997 and concluded that another year of study was
necessary before any action could be taken. The Public Service Commission of
Wisconsin (PSCW) revised its restructuring plan, delaying the start of retail
competition another year to 2002. The Michigan Public Service Commission (MPSC)
approved a plan to begin offering a choice of suppliers to retail customers in
selected markets in 1998. That plan was unsuccessfully challenged by the
affected Michigan utilities, and the courts upheld the MPSC's authority to
implement retail competition. The timing of regulatory actions regarding
restructuring and their impact on NSP cannot be predicted at this time and may
be significant.
USED NUCLEAR FUEL STORAGE AND DISPOSAL In 1994, NSP received legislative
authorization from the state of Minnesota for the use of 17 casks for temporary
spent-fuel storage at the Company's Prairie Island nuclear generating facility.
Based on assumptions in the original Certificate of Need granted by the MPUC,
the Company previously estimated that 17 casks would allow operation of the
Prairie Island facility to continue to 2003. After review of the 1994
legislative authorization which amends the Certificate of Need, and through the
use of longer fuel cycles, the Company has determined 17 casks will allow
operation of the facility until 2007. The first nine casks have been authorized
by the Minnesota Environmental Quality Board (MEQB). The Company had loaded
seven of the casks as of Dec. 31, 1997. As a condition of the authorization, the
Minnesota Legislature established several resource commitments for the Company,
including wind and biomass generation sources, as well as other requirements.
The Company has taken steps to fulfill these requirements. The MEQB has
terminated an alternative siting process, which had been one of the original
legislative requirements.
Regarding permanent fuel storage, in 1996 the Company and other utilities were
successful in a lawsuit against the U.S. Department of Energy (DOE) to compel it
to fulfill its statutory and contractual obligations to store and dispose of
used nuclear fuel as required by the Nuclear Waste Policy Act of 1982. In
January 1997, the Company, other utility parties and state parties filed another
lawsuit against the DOE, requesting authority to withhold payments to the DOE
for the permanent disposal program. In April 1997, the parties filed for
additional relief, asking the U.S. Court of Appeals for the District of Columbia
(the Court) to order the DOE to take spent nuclear fuel by Jan. 31, 1998. In
November, 1997, the Court, in a unanimous ruling, reiterated the unconditional
obligation for the DOE to begin acceptance of spent nuclear fuel by Jan. 31,
1998. The Court confirmed this obligation exists under both the statute and the
standard contract; however, the Court denied the Company's request for an order
directing the DOE to accept spent nuclear fuel by the Jan. 31, 1998 date in the
standard contract, finding that the contractual remedies under the standard
contract, i.e., damages, may be adequate. The Court also held that the DOE
cannot use its own delays or the unavailability of a permanent disposal or
temporary storage facility as defense to utilities' actions for damages.
In its November 1997 decision, the Court did not discuss the request to escrow
payments to the Nuclear Waste Fund. In December 1997, the DOE petitioned the
Court for rehearing. Based on the Court's ruling, NSP and other utilities are
currently analyzing claims against the DOE for the costs incurred as a result of
the DOE's failure to meet its statutory and contractual obligations. However, it
is still unknown when the DOE actually will begin accepting used fuel.
Consequently, the Company continues to rely on interim on-site storage
facilities. Also, the Company is part of a consortium to establish a private
facility for interim storage of used nuclear fuel, the availability of which is
uncertain at this time. (See Notes 13 and 14 to the Financial Statements for
more information.)
TECHNOLOGY CHANGES FOR THE YEAR 2000 Like many other companies, NSP expects to
incur significant costs to modify or replace existing technology, including
computer software, for uninterrupted operation in the year 2000 and beyond. In
1996, NSP's Board of Directors approved funding to address development and
remediation efforts related to the year 2000. A committee made up of senior
management is leading NSP's initiatives to identify year 2000 related issues and
remediate business processes as necessary in 1998. Testing of computer software
modifications and other remediated processes is scheduled for 1999. NSP is also
working with major suppliers so that NSP does not experience business
interruptions due to year 2000 issues in the suppliers' business processes. The
amount of additional development and remediation costs necessary after 1997 for
NSP to prepare for the year
<PAGE>
2000 is estimated to be approximately $20 million, expected mainly in 1998. In
1997 and 1996, NSP expensed approximately $2.3 million and $0.6 million,
respectively, for this modification effort.
ENVIRONMENTAL MATTERS NSP incurs several types of environmental costs, including
nuclear plant decommissioning, storage and ultimate disposal of used nuclear
fuel, disposal of hazardous materials and wastes, remediation of contaminated
sites and monitoring of discharges into the environment. Because of the
continuing trend toward greater environmental awareness and increasingly
stringent regulation, NSP has been experiencing a trend toward increasing
environmental costs. This trend has caused, and may continue to cause, slightly
higher operating expenses and capital expenditures for environmental compliance.
In addition to nuclear decommissioning and used nuclear fuel disposal expenses
(as discussed in Note 13 to the Financial Statements), costs charged to NSP's
operating expenses for environmental monitoring and disposal of hazardous
materials and wastes were approximately $31 million in 1997, $31 million in 1996
and $26 million in 1995, and are expected to average approximately $35 million
per year for the five-year period 1998-2002. However, the precise timing and
amount of environmental costs, including those for site remediation and disposal
of hazardous materials, are currently unknown. In each of the years 1997, 1996
and 1995, the Company spent about $19 million, $10 million and $13 million,
respectively, for capital expenditures on environmental improvements at its
utility facilities. In 1998, the Company expects to incur approximately $18
million in capital expenditures for compliance with environmental regulations
and approximately $142 million for the five-year period 1998-2002. These capital
expenditure amounts include the costs of constructing used nuclear fuel storage
casks. (See Notes 13 and 14 to the Financial Statements for further discussion
of these and other environmental contingencies that could affect NSP.)
WEATHER NSP's earnings can be significantly affected by unusual weather. In
1997, warmer-than-normal weather late in the year decreased earnings over a
normal year by an estimated 11 cents per share. In 1996, colder-than-normal
weather during the heating season increased earnings over a normal year by an
estimated 16 cents per share. In 1995, unusual weather, mainly a hot summer,
increased earnings over a normal year by an estimated 21 cents per share. The
effect of weather is considered part of NSP's ongoing business operations.
IMPACT OF NONREGULATED INVESTMENTS A significant portion of NSP's earnings comes
from nonregulated operations, as discussed in the Results of Operations section.
NSP expects to continue investing in nonregulated projects, including domestic
and international power production projects through NRG, as described under
Future Financing Requirements. The nonregulated projects in which NRG has
invested carry a higher level of risk than NSP's traditional utility businesses.
Current investments in nonregulated projects are subject to competition,
operating risks, dependence on certain suppliers and customers, and domestic and
foreign environmental and energy regulations. Nonregulated project investments
also may be subject to partnership and government actions and foreign
government, political, economic and currency risks. Future nonregulated projects
will be subject to development risks, including uncertainties prior to final
legal closing, in addition to some or all of the previously identified risks.
Most of NRG's current project investments (as listed in Note 10 to the Financial
Statements) consist of minority interests, and a substantial portion of future
investments may take the form of minority interests, which may limit NRG's
financial risk and ability to control the development or operation of the
projects. In addition, significant expenses may be incurred for projects pursued
by NRG that do not materialize. The aggregate effect of these factors creates
the potential for volatility in the nonregulated component of NSP's earnings.
Accordingly, the historical operating results of NSP's nonregulated businesses
may not necessarily be indicative of future operating results.
ACCOUNTING CHANGES The Financial Accounting Standards Board (FASB) has proposed
new accounting standards that would require the full accrual of nuclear plant
decommissioning and certain other site exit obligations. Material adjustments to
NSP's balance sheet would occur upon implementation of the FASB's proposal,
which does not currently have a scheduled effective date. However, the effects
of regulation are expected to minimize or eliminate any impact on operating
expenses and earnings from this future accounting change. (For further
discussion of the expected impact of this change, see Note 13 to the Financial
Statements.)
USE OF DERIVATIVES Through its nonregulated subsidiaries, NSP uses derivative
financial instruments to mitigate the impact of changes in foreign currency
exchange rates and natural gas prices, and changes in interest rates on the cost
of borrowing. Also, to mitigate the interest rate risk associated with fixed
rate debt in a declining interest rate environment, NSP uses interest rate swap
agreements to convert fixed rate debt to variable rate debt. (See Notes 1 and 11
to the Financial Statements for further discussion of NSP's financial
instruments and derivatives.)
<PAGE>
NONRECURRING ITEMS NSP's earnings for 1997 include two significant unusual or
infrequently occurring items. As discussed previously, NSP recorded a
nonrecurring charge of $29 million, or 25 cents per share, to write off costs
previously deferred as a result of the proposed merger with WEC. Also, as
discussed in the Nonregulated Business Results section, NRG wrote down a
cogeneration project, reducing income from nonregulated businesses before
interest and taxes by $9 million, or 8 cents per share.
NSP's earnings for 1995 include two significant unusual or infrequently
occurring items. As discussed in the Nonregulated Business Results section, NRG
recognized a pretax gain of approximately $30 million, or 26 cents per share,
from a power sales contract termination settlement. Partially offsetting this
gain was an asset impairment write-down of $5 million before taxes, or 4 cents
per share, for a nonregulated domestic energy project.
INFLATION Inflation at its current level is not expected to materially affect
NSP's prices to customers or returns to shareholders.
LIQUIDITY AND CAPITAL RESOURCES
1997 FINANCING REQUIREMENTS NSP's need for capital funds primarily is related to
the construction of plant and equipment to meet the needs of electric and gas
utility customers and to fund equity commitments or other investments in
nonregulated businesses. Total NSP utility capital expenditures (including AFC)
were $397 million in 1997. Of that amount, $305 million related to replacements
and improvements of NSP's electric system and nuclear fuel, and $72 million
involved construction of natural gas distribution and transmission facilities.
NSP companies invested approximately $591 million in 1997 for equity interests
in and loans to nonregulated projects, for the acquisition of existing
businesses and for additions to nonregulated property. NRG invested in many
energy projects in 1997, including the $149 million purchase of PGC, and several
equity investments, the largest of which are listed in Note 10 to the Financial
Statements. Eloigne invested in affordable housing projects, including wholly
owned properties and limited partnership ventures.
1997 FINANCING ACTIVITY During 1997, NSP's sources of capital included
internally generated funds and external financings, as discussed later. The
allocation of financing requirements between these capital resources is based on
the relative cost of each resource, regulatory restrictions and the constraints
of NSP's long-range capital structure objectives.
Funds generated internally from operating cash flows in 1997 remained sufficient
to meet working capital needs, debt service, dividend payout requirements and
nonregulated investment commitments, as well as to fund a significant portion of
construction expenditures. NSP's objective pretax interest coverage ratio for
utility operations is 3.5 - 5.0. The utility pretax interest coverage ratio,
excluding AFC, was 3.6 in 1997, 4.4 in 1996, and 4.1 in 1995, which falls within
the objective range. Internally generated funds from utility operations could
have provided financing for more than 100 percent of NSP's utility capital
expenditures for 1997 and approximately 90 percent of the $1.9 billion in
utility capital expenditures incurred for the five-year period 1993-1997. The
pretax interest coverage ratio, excluding AFC, for all NSP operations was 2.8 in
1997, 3.7 in 1996 and 3.8 in 1995. The 1997 decline in the coverage ratio is due
to the unusual events that adversely affected NSP's earnings in 1997, as
discussed previously in the Results of Operations section, and issuance of new
debt by NRG, as discussed later.
NSP had approximately $260 million in short-term borrowings, including $122
million related to NRG, outstanding as of Dec. 31, 1997. Throughout 1997, the
Company used short-term borrowings to temporarily finance a portion of utility
capital expenditures and provide for other cash needs. NRG's line of credit
borrowings were used for the acquisition of PGC and other corporate purposes.
In the utility businesses, during 1997 NSP issued $200 million of 7.875 percent
preferred securities through a wholly owned special purpose subsidiary trust and
used the proceeds to redeem two preferred stock issues and reduce short-term
debt levels. The Company also collateralized $188 million of outstanding
pollution control bonds under its first mortgage indenture, and Viking issued
$14 million of long-term debt to finance an expansion project.
NSP's 1997 business acquisition, equity investments in nonregulated projects,
and construction expenditures were primarily financed through internally
generated funds and the issuance of debt by nonregulated subsidiaries. NRG
issued $250 million of 7.5 percent unsecured publicly traded Senior Notes in
1997 to support equity requirements for projects currently under way and in
development. The Senior Notes were assigned ratings of BBB- by S&P and
<PAGE>
Baa3 by Moody's. Project financing requirements, in excess of equity
contributions from investors, were satisfied with project debt and loans from
NSP's nonregulated businesses (mainly NRG). Project debt associated with many of
NSP's nonregulated investments is not reflected in NSP's balance sheet because
the equity method of accounting is used for such investments. (See Note 10 to
the Financial Statements.) Loans made by NSP to nonregulated projects are
reflected separately on the balance sheet as Notes Receivable from Nonregulated
Projects.
During 1997, the Company issued 5.6 million shares of common stock. Of these
shares, 4.9 million were sold to a group of underwriters in September 1997 at an
offering price to the public of $49.5625 per share. The net proceeds to the
Company of $237 million were used for general corporate purposes, including the
retirement of $100 million of first mortgage bonds that matured Oct. 1, 1997,
expenditures for the Company's construction program and the repayment of
short-term borrowings. Of the remaining new shares, 0.3 million were issued
under the Dividend Reinvestment and Stock Purchase Plan (DRSPP), 0.2 million
were issued under the Employee Stock Ownership Plan (ESOP) and 0.2 million were
issued under the Executive Long-Term Incentive Award Stock Plan.
FUTURE FINANCING REQUIREMENTS Utility financing requirements for 1998-2002 may
be affected in varying degrees by numerous factors, including load growth,
changes in capital expenditure levels, rate changes allowed by regulatory
agencies, new legislation, market entry of competing electric power generators,
changes in environmental regulations and other regulatory requirements. NSP
currently estimates that its utility capital expenditures will be $441 million
in 1998 and $2.1 billion for the five-year period 1998-2002. Of the 1998 amount,
approximately $371 million is scheduled for electric utility facilities and
approximately $49 million for natural gas facilities, including Viking. Approval
of the $1.25 billion Viking Voyageur Project, a proposed natural gas
transmission pipeline, would increase the total gas expenditures approximately
$500 million for the five-year period 1998-2002, with yearly expenditures
dependent on FERC approval. In addition to utility capital expenditures,
expected financing requirements for the five-year period 1998-2002 include
approximately $606 million to retire long-term debt and fund principal
maturities.
Through its subsidiaries, NSP expects to invest significant amounts in
nonregulated projects in the future. Financing requirements for nonregulated
project investments will vary depending on the success, timing and level of
involvement in projects currently under consideration. NSP's potential capital
requirements for nonregulated projects and property are estimated to be
approximately $310 million in 1998 and approximately $940 million for the
five-year period 1998-2002. These amounts include commitments for NRG
investments, as discussed in Note 14 to the Financial Statements, and Eloigne
investments of up to $11 million annually in 1998-2002 for affordable housing
projects. In addition to the estimated potential investments in nonregulated
projects as disclosed above, NSP continues to evaluate opportunities to enhance
shareholder returns and achieve long-term financial objectives through
investments in projects or acquisitions of existing businesses. These
investments could cause significant changes to the capital requirement estimates
for nonregulated projects and property. Long-term nonregulated financing may be
required for such investments.
The Company also will have future financing requirements for the portion of
nuclear plant decommissioning costs not funded externally. Based on the most
recent decommissioning study approved by regulators, these amounts are
anticipated to be approximately $363 million, and are expected to be paid during
the years 2010 to 2022.
FUTURE SOURCES OF FINANCING NSP expects to obtain external capital for future
financing requirements by periodically issuing long-term debt, short-term debt,
common stock and preferred securities as needed to maintain desired
capitalization ratios. Over the long term, NSP's equity investments in
nonregulated projects are expected to be financed at the nonregulated subsidiary
level, from internally generated funds or the issuance of subsidiary debt.
Financing requirements for the nonregulated projects, in excess of equity
contributions from project investors, are expected to be fulfilled through
project or subsidiary debt. In addition, to provide additional capital to NRG,
NSP is considering the public offering of up to 20 percent equity ownership of
NRG in late 1998 or 1999. Eloigne expects to finance approximately 60 percent of
its estimated five-year investments in affordable housing projects with equity
and approximately 40 percent with long-term debt. Decommissioning expenses not
funded by an external trust are expected to be financed through a combination of
internally generated funds, long-term debt and common stock. The extent of
external financing to be required for nuclear decommissioning costs, as
discussed above, is unknown at this time.
NSP's ability to finance its utility construction program at a reasonable cost
and to provide for other capital needs depends on its ability to meet investors'
return expectations. Financing flexibility is enhanced by providing working
capital needs and a high percentage of total capital requirements from internal
sources, and having the ability to
<PAGE>
issue long-term securities and obtain short-term credit. NSP expects to maintain
adequate access to securities markets in 1998. Access to securities markets at a
reasonable cost is determined in large part by credit quality. The Company's
first mortgage bonds are currently rated AA by Standard & Poor's Corporation,
Aa3 by Moody's Investors Service, Inc., AA by Duff & Phelps, Inc., and AA by
Fitch Investors Service, Inc. Ratings for the Wisconsin Company's first mortgage
bonds are generally comparable. These ratings reflect the views of such
organizations, and an explanation of the significance of these ratings may be
obtained from each agency.
The Company's and the Wisconsin Company's first mortgage indentures limit the
amount of first mortgage bonds that may be issued. The MPUC and the PSCW have
jurisdiction over securities issuance. At Dec. 31, 1997, with an assumed
interest rate of 6.75 percent, the Company could have issued about $2.1 billion
of additional first mortgage bonds under its indenture, and the Wisconsin
Company could have issued about $351 million of additional first mortgage bonds
under its indenture.
The Company filed a shelf registration for first mortgage bonds with the SEC in
October 1995. Depending on capital market conditions, the Company expects to
issue the remaining $300 million of registered, but unissued, bonds over the
next several years to raise additional capital or redeem outstanding securities.
The Company's Board of Directors has approved short-term borrowing levels up to
10 percent of capitalization. The Company has received regulatory approval for
up to $575 million in short-term borrowing levels and plans to keep its credit
lines at or above its average level of commercial paper borrowings. Commercial
banks presently provide credit lines of $300 million to the Company and an
additional $245 million to subsidiaries of the Company, including a $175 million
unsecured revolving bank credit facility available to NRG. NSP credit lines make
short-term financing available in the form of bank loans, letters of credit and
support for commercial paper for utility operations.
The Company's Articles of Incorporation authorize the maximum amount of
preferred stock that may be issued. Under these provisions, the Company could
have issued all $500 million of its remaining authorized, but unissued,
preferred stock at Dec. 31, 1997, and remained in compliance with all interest
and dividend coverage requirements.
The Company's Articles of Incorporation authorize an additional 85.4 million
shares of common stock in excess of shares issued at Dec. 31, 1997. In 1996, the
Company filed a registration statement with the SEC to provide for the sale of
up to 1.6 million additional shares of new common stock under the Company's
DRSPP and Executive Long-Term Incentive Award Stock Plan. The Company may issue
new shares or purchase shares on the open market for its stock-based plans. (See
Note 3 to the Financial Statements for discussion of stock awards outstanding.)
The Company plans to issue new shares for its DRSPP, ESOP and Executive
Long-Term Incentive Award Stock plans in 1998. NSP currently has no plans for
any general offerings of common stock in 1998 or 1999.
Internally generated funds from utility operations are expected to equal
approximately 85 percent of anticipated utility capital expenditures for 1998
and approximately 95 percent of the $2.1 billion in anticipated utility capital
expenditures for the five-year period 1998-2002. Internally generated funds from
all operations are expected to equal approximately 60 percent and 85 percent of
the anticipated total capital requirements for 1998 and the five-year period
1998-2002, respectively. Because NSP has generally been reinvesting foreign cash
flows in operations outside the United States, the equity income from foreign
investments is not fully available to provide operating cash flows for domestic
cash requirements such as payment of NSP dividends, domestic capital
expenditures and domestic debt service. Through NRG, NSP is establishing a
diverse portfolio of foreign energy projects with varying levels of cash flows,
income and foreign taxation to allow maximum flexibility of foreign cash flows
in the future.
<PAGE>
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, a Minnesota
corporation, and its subsidiaries at Dec. 31, 1997 and 1996, and the results of
their operations and their cash flows for each of the three years in the period
ended Dec. 31, 1997, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
/s/
PRICE WATERHOUSE LLP
MINNEAPOLIS, MINNESOTA
FEB. 2, 1998
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year Ended Dec. 31
------------------------------------
(Thousands of dollars, except per share data) 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
UTILITY OPERATING REVENUES
Electric $2 218 550 $2 127 413 $2 142 770
Gas 515 196 526 793 425 814
- ------------------------------------------------------------------------------------------------------------------
Total 2 733 746 2 654 206 2 568 584
- ------------------------------------------------------------------------------------------------------------------
UTILITY OPERATING EXPENSES
Fuel for electric generation 309 999 301 201 325 652
Purchased and interchange power 286 239 243 562 247 699
Cost of gas purchased and transported 331 296 335 453 256 758
Other operation 368 545 333 010 318 015
Maintenance 164 542 155 830 158 203
Administrative and general 141 802 148 656 186 147
Conservation and energy management 70 939 69 784 53 466
Depreciation and amortization 325 880 306 432 290 184
Property and general taxes 227 893 232 824 239 433
Income taxes 144 855 161 410 147 148
- ------------------------------------------------------------------------------------------------------------------
Total 2 371 990 2 288 162 2 222 705
- ------------------------------------------------------------------------------------------------------------------
UTILITY OPERATING INCOME 361 756 366 044 345 879
- ------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Income from nonregulated businesses - before interest and taxes 12 078 18 543 49 611
Allowance for funds used during construction---equity 6 401 7 595 6 794
Merger costs (29 005)
Other utility income (deductions)---net (2 886) (1 544) 1 481
Income taxes on nonregulated operations and nonoperating items 48 145 14 600 (5 080)
- ------------------------------------------------------------------------------------------------------------------
Total 34 733 39 194 52 806
- ------------------------------------------------------------------------------------------------------------------
INCOME BEFORE FINANCING COSTS 396 489 405 238 398 685
- ------------------------------------------------------------------------------------------------------------------
FINANCING COSTS
Interest on utility long-term debt 101 250 101 177 103 298
Other utility interest and amortization 19 063 21 950 20 151
Nonregulated interest and amortization 34 627 18 834 9 879
Allowance for funds used during construction---debt (10 208) (11 262) (10 438)
- ------------------------------------------------------------------------------------------------------------------
Total interest charges 144 732 130 699 122 890
Distributions on redeemable preferred securities of subsidiary trust 14 437
- ------------------------------------------------------------------------------------------------------------------
Total Financing Costs 159 169 130 699 122 890
- ------------------------------------------------------------------------------------------------------------------
NET INCOME 237 320 274 539 275 795
Preferred Stock Dividends 11 071 12 245 12 449
- ------------------------------------------------------------------------------------------------------------------
Earnings Available for Common Stock $226 249 $262 294 $263 346
==================================================================================================================
Average Number of Common Shares Outstanding (000's) 70 297 68 561 67 323
Average Number of Common and Potentially Dilutive Shares Outstanding (000's)70 435 68 679 67 416
EARNINGS PER AVERAGE COMMON SHARE - BASIC $3.22 $3.83 $3.91
EARNINGS PER AVERAGE COMMON SHARE - ASSUMING DILUTION $3.21 $3.82 $3.91
Common Dividends Declared per Share $2.805 $2.745 $2.685
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Financial Statements.
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended Dec. 31
------------------------------------
(Thousands of dollars) 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $237 320 $274 539 $275 795
Adjustments to reconcile net income to cash from operating activities:
Depreciation and amortization 358 928 335 605 322 296
Nuclear fuel amortization 40 015 45 774 49 778
Deferred income taxes (5 902) (30 561) (11 076)
Deferred investment tax credits recognized (10 061) (9 352) (9 117)
Allowance for funds used during construction --- equity (6 401) (7 595) (6 794)
Undistributed equity in earnings of unconsolidated affiliates (5 364) (25 976) (24 305)
Undistributed equity in gain from nonregulated contract termination (17 565)
Write-off of prior year merger costs 25 289
Cash provided by (used for) changes in certain working capital items
(see below) 36 117 (58 634) (791)
Conservation program expenditures --- net of amortization (9 207) (2 854) (21 668)
Cash provided by changes in other assets and liabilities 29 051 23 518 17 234
- -------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 689 785 544 464 573 787
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures:
Utility plant additions (including nuclear fuel) (396 605) (386 655) (386 022)
Additions to nonregulated property (35 928) (25 807) (14 984)
Increase (decrease) in construction payables 2 563 (3 716) (12 588)
Allowance for funds used during construction --- equity 6 401 7 595 6 794
Investment in external decommissioning fund (41 261) (40 497) (33 196)
Equity investments, loans and deposits for nonregulated projects (395 495) (299 173) (55 884)
Collection of loans made to nonregulated projects 87 128 116 126 1 766
Business acquisitions (159 600)
Other investments --- net (15 692) (15 873) (998)
- -------------------------------------------------------------------------------------------------------------------
NET CASH USED FOR INVESTING ACTIVITIES (948 489) (648 000) (495 112)
- -------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in short-term debt --- net issuances (repayments) (108 023) 152 173 (22 245)
Proceeds from issuance of long-term debt - net 299 779 197 824 277 174
Loan to ESOP (15 000)
Repayment of long-term debt, including reacquisition premiums (141 681) (67 628) (195 683)
Proceeds from issuance of preferred securities - net 193 315
Proceeds from issuance of common stock - net 267 965 41 725 56 185
Redemption of preferred stock, including reacquisition premiums (41 278)
Dividends paid (207 726) (198 234) (191 367)
- -------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED FOR) FINANCING ACTIVITIES 262 351 125 860 (90 936)
- -------------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 3 647 22 324 (12 261)
Cash and Cash Equivalents at Beginning of Period 51 118 28 794 41 055
- -------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $54 765 $51 118 $28 794
===================================================================================================================
CASH PROVIDED BY (USED FOR) CHANGES IN CERTAIN WORKING CAPITAL ITEMS:
Customer accounts receivable and unbilled utility revenues $47 878 $(41 495) $(66 311)
Materials and supplies inventories (8 547) (9 891) 14 290
Payables and accrued liabilities (excluding construction payables) (7 342) 1 179 51 316
Other 4 128 (8 427) (86)
- -------------------------------------------------------------------------------------------------------------------
Net $36 117 $(58 634) $(791)
===================================================================================================================
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $144 062 $121 697 $113 705
Income taxes (net of refunds received) $113 009 $165 146 $131 452
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Financial Statements.
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
Dec. 31
----------------------
(Thousands of dollars) 1997 1996
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
UTILITY PLANT
Electric---including construction work in progress:
1997, $92,302; 1996, $132,705 $6 964 888 $6 766 896
Gas 821 119 750 449
Other 343 950 331 441
- ---------------------------------------------------------------------------------------------------------------
Total 8 129 957 7 848 786
Accumulated provision for depreciation (3 868 810) (3 611 244)
Nuclear fuel---including amounts in process:
1997, $23,381; 1996, $6,916 932 335 892 484
Accumulated provision for amortization (832 162) (792 146)
- ---------------------------------------------------------------------------------------------------------------
Net utility plant 4 361 320 4 337 880
- ---------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 54 765 51 118
Customer accounts receivable --- net of accumulated provisions
for uncollectible accounts: 1997, $10,406; 1996, $10,195 269 455 288 330
Unbilled utility revenues 121 619 147 366
Notes receivable from nonregulated projects 55 787 5 753
Other receivables 80 803 77 571
Materials and supplies inventories---at average cost:
Fuel 56 434 45 013
Other 107 254 109 425
Prepayments and other 55 674 72 647
- ---------------------------------------------------------------------------------------------------------------
Total current assets 801 791 797 223
- ---------------------------------------------------------------------------------------------------------------
OTHER ASSETS
Equity investments in nonregulated projects 740 734 409 729
External decommissioning fund and other investments 400 290 302 250
Regulatory assets 340 122 354 128
Nonregulated property---net of accumulated depreciation:
1997, $105,526; 1996, $93,320 256 726 192 790
Notes receivable from nonregulated projects 77 639 75 811
Other long-term receivables 42 600 63 684
Long-term prepayments and deferred charges 30 015 57 237
Intangible assets - net of accumulated amortization 92 829 46 168
- ---------------------------------------------------------------------------------------------------------------
Total other assets 1 980 955 1 501 797
- ---------------------------------------------------------------------------------------------------------------
TOTAL $7 144 066 $6 636 900
===============================================================================================================
LIABILITIES AND EQUITY
CAPITALIZATION (See Consolidated Statements of Capitalization)
Common stockholders' equity $2 371 728 $2 135 880
Preferred stockholders' equity 200 340 240 469
Company obligated mandatorily redeemable preferred securities of subsidiary trust
holding as its sole asset junior subordinated deferrable debentures of the Company 200 000
Long-term debt 1 878 875 1 592 568
- ---------------------------------------------------------------------------------------------------------------
Total capitalization 4 650 943 3 968 917
- ---------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year 22 820 119 618
Other long-term debt potentially due within one year 141 600 141 600
Short-term debt 260 352 368 367
Accounts payable 249 813 236 341
Taxes accrued 186 369 204 348
Interest accrued 28 724 34 722
Dividends payable on common and preferred stocks 54 778 50 409
Accrued payroll, vacation and other 89 562 80 995
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 1 034 018 1 236 400
- ---------------------------------------------------------------------------------------------------------------
OTHER LIABILITIES
Deferred income taxes 792 569 804 342
Deferred investment tax credits 138 509 149 606
Regulatory liabilities 305 765 302 647
Postretirement and other benefit obligations 135 612 114 312
Other long-term obligations and deferred income 86 650 60 676
- ---------------------------------------------------------------------------------------------------------------
Total other liabilities 1 459 105 1 431 583
- ---------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENT LIABILITIES (SEE NOTES 13 AND 14)
- ---------------------------------------------------------------------------------------------------------------
TOTAL $7 144 066 $6 636 900
===============================================================================================================
</TABLE>
See Notes to Financial Statements.
<PAGE>
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
CUMULATIVE
CURRENCY
NUMBER OF RETAINED SHARES HELD TRANSLATION
(Dollar amounts in thousands) SHARES ISSUED PAR VALUE PREMIUM EARNINGS BY ESOP ADJUSTMENTS
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT DEC. 31, 1994 66 922 144 $167 305 $545 875 $1 183 191 $(2 990) $3 586
- -------------------------------------------------------------------------------------------------------------------------
Net income 275 795
Dividends declared:
Cumulative preferred stock (12 450)
Common stock (180 510)
Issuances of common stock - net 1 253 790 3 135 53 050
Tax benefit from stock options exercised 169
Loan to ESOP to purchase shares (15 000)
Repayment of ESOP loan * 7 333
Currency translation adjustments (1 098)
- -------------------------------------------------------------------------------------------------------------------------
BALANCE AT DEC. 31, 1995 68 175 934 $170 440 $599 094 $1 266 026 $(10 657) $2 488
- -------------------------------------------------------------------------------------------------------------------------
Net income 274 539
Dividends declared:
Cumulative preferred stock (12 245)
Common stock (187 521)
Issuances of common stock - net 887 778 2 219 39 256
Tax benefit from stock options exercised 369
Loan to ESOP to purchase shares * (15 000)
Repayment of ESOP loan * 6 566
Currency translation adjustments 306
- -------------------------------------------------------------------------------------------------------------------------
BALANCE AT DEC. 31, 1996 69 063 712 $172 659 $638 719 $1 340 799 $(19 091) $2 794
- -------------------------------------------------------------------------------------------------------------------------
Net income 237 320
Dividends declared:
Cumulative preferred stock (9 923)
Common stock (202 173)
Premium on redeemed preferred stock (1,148)
Issuances of common stock - net 5 554 670 13 887 253 999
Tax benefit from stock options exercised 1 009
Repayment of ESOP loan * 8 558
Currency translation adjustments (65 681)
- -------------------------------------------------------------------------------------------------------------------------
BALANCE AT DEC. 31, 1997 74 618 382 $186 546 $893 727 $1 364 875 $(10 533) $(62 887)
=========================================================================================================================
</TABLE>
* Did not affect NSP cash flows
See Notes to Financial Statements.
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
Dec. 31
---------------------------
(Thousands of dollars) 1997 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
COMMON STOCKHOLDERS' EQUITY
Common stock---authorized 160,000,000 shares of $2.50 par value;
issued shares: 1997, 74,618,382; 1996, 69,063,712 $186 546 $172 659
Premium on common stock 893 727 638 719
Retained earnings 1 364 875 1 340 799
Leveraged common stock held by Employee Stock Ownership Plan (ESOP)
---shares at cost: 1997, 230,253; 1996, 381,313 (10 533) (19 091)
Currency translation adjustments---net (62 887) 2 794
- -------------------------------------------------------------------------------------------------------------------
Total common stockholders' equity $2 371 728 $2 135 880
===================================================================================================================
CUMULATIVE PREFERRED STOCK---authorized 7,000,000 shares of $100 par value;
outstanding shares: 1997, 2,000,000; 1996, 2,400,000
Minnesota Company
$3.60 series, 275,000 shares $27 500 $27 500
4.08 series, 150,000 shares 15 000 15 000
4.10 series, 175,000 shares 17 500 17 500
4.11 series, 200,000 shares 20 000 20 000
4.16 series, 100,000 shares 10 000 10 000
4.56 series, 150,000 shares 15 000 15 000
6.80 series, 200,000 shares 20 000
7.00 series, 200,000 shares 20 000
Variable Rate series A, 300,000 shares 30 000 30 000
Variable Rate series B, 650,000 shares 65 000 65 000
- -------------------------------------------------------------------------------------------------------------------
Total 200 000 240 000
Premium on preferred stock 340 469
- -------------------------------------------------------------------------------------------------------------------
Total preferred stockholders' equity $200 340 $240 469
===================================================================================================================
MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST (See Note 2)
7 7/8% series, 8,000,000 shares, due Jan. 31, 2037 $200 000
===================================================================================================================
LONG-TERM DEBT
First Mortgage Bonds - Minnesota Company
Series due:
Oct. 1, 1997, 5 7/8% $100 000
Feb. 1, 1999, 5 1/2% $200 000 200 000
Dec. 1, 2000, 5 3/4% 100 000 100 000
Oct. 1, 2001, 7 7/8% 150 000 150 000
March 1, 2002, 7 3/8% 50 000 50 000
Feb. 1, 2003, 7 1/2% 50 000 50 000
April 1, 2003, 6 3/8% 80 000 80 000
Dec. 1, 2005, 6 1/8% 70 000 70 000
Dec. 1, 1996-2006, 6.65% 18 400** 19 800**
March 1, 2011, Variable Rate 13 700* 13 700*
July 1, 2025, 7 1/8% 250 000 250 000
April 1, 2007, 6.80% 60 000*
March 1, 2019, Variable Rate 27 900*
Sept. 1, 2019, Variable Rate 100 000*
- -------------------------------------------------------------------------------------------------------------------
Total 1 170 000 1 083 500
Less redeemable bonds classified as current (See Note 5) (141 600) (13 700)
Less current maturities (1 500) (101 400)
- -------------------------------------------------------------------------------------------------------------------
Net $1 026 900 $968 400
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
* POLLUTION CONTROL FINANCING
** RESOURCE RECOVERY FINANCING
See Notes to Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
Dec. 31
-------------------------------
(Thousands of dollars) 1997 1996
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
LONG-TERM DEBT---CONTINUED
First Mortgage Bonds - Wisconsin Company
Series due:
Oct. 1, 2003, 5 3/4% $40 000 $40 000
March 1, 2023, 7 1/4% 110 000 110 000
Dec. 1, 2026, 7 3/8% 65 000 65 000
- -------------------------------------------------------------------------------------------------------------------
Total 215 000 $215 000
- -------------------------------------------------------------------------------------------------------------------
Guaranty Agreements---Minnesota Company
Series due:
Feb. 1, 1997 - 2003, 5.41% $5 300* $ 5 500*
May 1, 1997 - 2003, 5.70% 23 250* 23 750*
Feb. 1, 2003, 7.40% 3 500* 3 500*
- -------------------------------------------------------------------------------------------------------------------
Total 32 050 32 750
Less current maturities (700) (700)
- -------------------------------------------------------------------------------------------------------------------
Net $31 350 $32 050
- -------------------------------------------------------------------------------------------------------------------
Other Long-Term Debt
City of Becker Pollution Control Revenue Bonds---Series due
Dec. 1, 2005, 7.25% $9 000* $ 9 000*
April 1, 2007, 6.80% 60 000*
March 1, 2019, Variable Rate 27 900*
Sept. 1, 2019, Variable Rate 100 000*
Anoka County Resource Recovery Bond---Series due
Dec. 1, 1997 - 2008, 7.09% 21 850** 23 050**
City of La Crosse Resource Recovery Bond---Series due
Nov. 1, 2021, 6% 18 600** 18 600**
Viking Gas Transmission Company Senior Notes---Series due
Oct. 31, 2008, 6.65% 23 111 25 244
Nov. 30, 2011, 7.1% 5 010 5 370
Sept. 30, 2012, 7.31% 13 767
NRG Energy, Inc. Senior Notes---Series due
Feb. 1, 2006, 7.625% 125 000 125 000
June 15, 2007, 7.5% 250 000
NRG Energy Center, Inc. (Minneapolis Energy Center) Senior Secured Notes---Series due
June 15, 2013, 7.31% 74 481 76 992
Pacific Generation Company debt due 2000-2007, 4.7% - 9.9% 33 424
Various NEO Corporation debt due Oct. 30, 2000, 6.9% - 9.4% 5 618
United Power & Land Notes due
March 31, 2000, 7.62% 6 875 7 708
Various Eloigne Company Affordable Housing Project Notes due
1997 - 2024, 1.0% - 9.9% 27 223 24 755
Employee Stock Ownership Plan Bank Loans due
1997 - 2003, Variable Rate 10 535 17 571
Miscellaneous 7 385 7 533
- -------------------------------------------------------------------------------------------------------------------
Total 631 879 528 723
Less redeemable bonds classified as current (see Note 5) (127 900)
Less current maturities (20 620) (17 518)
- -------------------------------------------------------------------------------------------------------------------
Net $611 259 $383 305
- -------------------------------------------------------------------------------------------------------------------
Unamortized discount on long-term debt-net (5 634) (6 187)
- -------------------------------------------------------------------------------------------------------------------
Total long-term debt $1 878 875 $1 592 568
===================================================================================================================
Total capitalization $4 650 943 $3 968 917
===================================================================================================================
</TABLE>
* POLLUTION CONTROL FINANCING
** RESOURCE RECOVERY FINANCING
See Notes to Financial Statements.
<PAGE>
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
SYSTEM OF ACCOUNTS Northern States Power Company, a Minnesota corporation (the
Company), is predominantly a regulated public utility serving customers in
Minnesota, North Dakota and South Dakota. Northern States Power Company, a
Wisconsin corporation (the Wisconsin Company), a wholly owned subsidiary of the
Company, is a regulated public utility serving customers in Wisconsin and
Michigan. Another wholly owned subsidiary, Viking Gas Transmission Company
(Viking), is a regulated natural gas transmission company that operates a
500-mile interstate natural gas pipeline. Consequently, the Company, the
Wisconsin Company and Viking maintain accounting records in accordance with
either the uniform system of accounts prescribed by the Federal Energy
Regulatory Commission (FERC) or those prescribed by state regulatory
commissions, whose systems are the same in all material respects.
PRINCIPLES OF CONSOLIDATION The consolidated financial statements include all
material companies in which the Company holds a controlling financial interest,
including: the Wisconsin Company; NRG Energy, Inc. (NRG); Viking; Energy Masters
International, Inc. (EMI), formerly Cenerprise, Inc.; and Eloigne Company
(Eloigne). The Company and its subsidiaries collectively are referred to herein
as NSP. As discussed in Note 10, NSP has investments in partnerships, joint
ventures and projects for which the equity method of accounting is applied.
Earnings from equity in international investments are recorded net of foreign
income taxes. All significant intercompany transactions and balances have been
eliminated in consolidation except for intercompany and intersegment profits for
sales among the electric and gas utility businesses of the Company, the
Wisconsin Company and Viking, which are allowed in utility rates.
REVENUES Revenues are recognized based on products and services provided to
customers each month. Because utility customer meters are read and billed on a
cycle basis, unbilled revenues (and related energy costs) are estimated and
recorded for services provided from the monthly meter-reading dates to
month-end.
The Company's rate schedules, applicable to substantially all of its utility
customers, include cost-of-energy and resource adjustment clauses, under which
rates are adjusted to reflect changes in average costs of fuels, purchased
energy, purchased gas and, in Minnesota, conservation and energy management
program costs. As ordered by its primary regulator, Wisconsin Company retail
rate schedules include a cost-of-energy adjustment clause for purchased gas but
not for electric fuel and purchased energy. For Wisconsin electric operations
where cost-of-energy adjustment clauses are not used, the biennial retail rate
review process and an interim fuel cost hearing process provide the opportunity
for rate recovery of changes in electric fuel and purchased energy costs in lieu
of a cost-of-energy adjustment.
UTILITY PLANT AND RETIREMENTS Utility plant is stated at original cost. The cost
of additions to utility plant includes direct labor and materials, contracted
work, allocable overhead costs and allowance for funds used during construction.
The cost of units of property retired, plus net removal cost, is charged to the
accumulated provision for depreciation and amortization. Maintenance and
replacement of items determined to be less than units of property are charged to
operating expenses.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFC) AFC, a noncash item, is
computed by applying a composite pretax rate, representing the cost of capital
used to finance utility construction activities, to qualified Construction Work
in Progress (CWIP). The AFC rate was 5.75 percent in 1997, 5.5 percent in 1996
and 6.0 percent in 1995. The amount of AFC capitalized as a construction cost in
CWIP is credited to other income (for equity capital) and interest charges (for
debt capital). AFC amounts capitalized in CWIP are included in rate base for
establishing utility service rates. In addition to construction-related amounts,
AFC is also recorded to reflect returns on capital used to finance conservation
programs.
DEPRECIATION For financial reporting purposes, depreciation is computed by
applying the straight-line method over the estimated useful lives of various
property classes. The Company files with the Minnesota Public Utilities
Commission (MPUC) an annual review of remaining lives for electric and gas
production properties. The most recent studies, as approved by the MPUC,
recommended immaterial changes in annual depreciation accruals for 1997 and
1996.
<PAGE>
The Company also submitted in 1997, as required every five years, an average
service life filing for transmission, distribution and general properties. The
filing, as approved by the MPUC, decreased depreciation approximately $1 million
from 1996 levels. Depreciation provisions, as a percentage of the average
balance of depreciable utility property in service, were 3.78 percent in 1997,
3.68 percent in 1996 and 3.64 percent in 1995.
DECOMMISSIONING As discussed in Note 13, NSP currently is recording the future
costs of decommissioning the Company's nuclear generating plants through annual
depreciation accruals. The provision for the estimated decommissioning costs has
been calculated using an annuity approach designed to provide for full expense
accrual (with full rate recovery) of the future decommissioning costs, including
decontamination and removal, over the estimated operating lives of the Company's
nuclear plants. The Financial Accounting Standards Board (FASB) has proposed new
accounting standards that would require the full accrual of nuclear plant
decommissioning and certain other site exit obligations beginning no sooner than
1999. (See Note 13 for more discussion of this proposed standard.)
NUCLEAR FUEL EXPENSE The original cost of nuclear fuel is amortized to fuel
expense based on energy expended. Nuclear fuel expense also includes assessments
from the U.S. Department of Energy (DOE) for costs of future fuel disposal and
DOE facility decommissioning, as discussed in Note 13.
ENVIRONMENTAL COSTS Accruals for environmental costs are recognized when it is
probable that a liability has been incurred and the amount of the liability can
be reasonably estimated. Costs are charged to expense if they relate to the
remediation of conditions caused by past operations, or if they are not expected
to mitigate or prevent contamination from future operations. Costs may be
deferred as a regulatory asset based on expected recovery in future rates. Where
environmental expenditures relate to facilities currently in use, such as
pollution control equipment, the costs may be capitalized and depreciated over
the future service periods. Estimated remediation costs are recorded at
undiscounted amounts, independent of any insurance or rate recovery, based on
prior experience, assessments and current technology. Accrued obligations are
regularly adjusted as environmental assessments and estimates are revised, and
remediation efforts proceed. For sites where NSP has been designated as one of
several potentially responsible parties, the amount accrued represents NSP's
estimated share of the cost. NSP intends to treat any future costs incurred
related to decommissioning and restoration of its nonnuclear power plants and
substation sites, where operation may extend indefinitely, as a capitalized
removal cost of retirement in utility plant. Depreciation expense levels
currently recovered in rates include a provision for an estimate of removal
costs, based on historical experience.
INCOME TAXES Under the liability method used by NSP, income taxes are deferred
for all temporary differences between pretax financial and taxable income and
between the book and tax bases of assets and liabilities, using the tax rates
scheduled by law to be in effect when the temporary differences reverse. Due to
the effects of regulation, current income tax expense is provided for the
reversal of some temporary differences previously accounted for by the
flow-through method. Also, regulation has created certain regulatory assets and
liabilities related to income taxes, as summarized in Note 9. NSP's policy for
income taxes related to international operations is discussed in Note 7.
Investment tax credits were deferred and are being amortized over the estimated
lives of the related property.
FOREIGN CURRENCY TRANSLATION The local currencies are generally the functional
currency of NSP's foreign operations. Foreign currency denominated assets and
liabilities are translated at end-of-period rates of exchange. Income, expense
and cash flows are translated at weighted-average rates of exchange for the
period. The resulting currency translation adjustments are accumulated and
reported as a separate component of stockholders' equity. During 1997, the
effects of changes in currency exchange rates on NRG's international project
investments, mainly in Australia, reduced equity by $66 million.
Exchange gains and losses that result from foreign currency transactions (e.g.,
converting cash distributions made in one currency to another) and derivative
arrangements that do not qualify for hedge accounting (see Note 11) are included
in the results of operations as a component of income from nonregulated
businesses before interest and taxes. The earnings impact of these items was not
material to NSP's results for the periods presented.
DERIVATIVE FINANCIAL INSTRUMENTS NSP's policy is to hedge projected foreign
currency denominated cash flows, where appropriate hedging instruments are
available, to preserve their U.S. dollar value. NRG has entered into currency
hedging transactions through the use of forward foreign currency exchange
agreements with terms of less than one to three years. Gains and losses on these
agreements offset the effect of foreign currency exchange rate fluctuations on
NRG's known and anticipated cash flows. Gains on agreements that hedge firm
commitments of
<PAGE>
cash flows are deferred and included in the measurement of the related foreign
currency transaction in the period the transaction occurs, and losses on these
agreements are deferred in the same manner unless it is estimated that deferral
would lead to recognizing losses in later periods. Gains and losses on
agreements that hedge cash flows not meeting the criteria of a firm commitment
are recorded in the current period as a component of NSP's nonregulated income
before interest and taxes. Prior to July 1997, NSP's policy was to hedge foreign
currency denominated investments as they were made, where appropriate hedging
instruments were available, to preserve their U.S. dollar value. Gains and
losses on these agreements offset the effects of foreign currency exchange rate
fluctuations on the valuation of the investments underlying the hedges. Hedging
gains and losses, net of income tax effects, on these agreements were reported
with other currency translation adjustments as a separate component of
stockholders' equity. While NRG is not currently hedging foreign currency
denominated investments, NRG will hedge such investments when management
believes that preserving the U.S. dollar value of the investment is appropriate.
NRG is not hedging currency translation adjustments related to future operating
results. NRG does not speculate in foreign currencies.
Where appropriate, NRG also uses interest rate hedging instruments to protect
against increases in the cost of borrowing at both the corporate and project
level. Gains and losses on interest rate hedging instruments are deferred and
included in the measurement of the underlying equity investment when made.
Another derivative arrangement is the use of natural gas futures contracts by
EMI to manage the risk of gas price fluctuations. The cost or benefit of natural
gas futures contracts is recorded when related sales commitments are fulfilled
as a component of EMI's nonregulated operating expenses. NSP does not speculate
in natural gas futures. A final derivative instrument used by NSP is interest
rate swaps that convert fixed-rate debt to variable-rate debt. The cost or
benefit of the interest rate swap agreements is recorded as a component of
interest expense. None of these derivative financial instruments are reflected
on NSP's balance sheet.
USE OF ESTIMATES In recording transactions and balances resulting from business
operations, NSP uses estimates based on the best information available.
Estimates are used for such items as plant depreciable lives, tax provisions,
uncollectible accounts, environmental costs, unbilled revenues and actuarially
determined benefit costs. As better information becomes available, or actual
amounts are determinable, the recorded estimates are revised. Consequently,
operating results can be affected by revisions to prior accounting estimates.
The depreciable lives of certain plant assets are reviewed and, if appropriate,
revised each year, as discussed previously.
CASH EQUIVALENTS NSP considers investments in certain debt instruments,
primarily commercial paper and money market funds, with an original maturity to
NSP of three months or less at the time of purchase to be cash equivalents.
REGULATORY DEFERRALS As regulated utilities, the Company, the Wisconsin Company
and Viking account for certain income and expense items under the provisions of
Statement of Financial Accounting Standards (SFAS) No. 71---Accounting for the
Effects of Regulation. In doing so, certain costs that would otherwise be
charged to expense are deferred as regulatory assets based on expected recovery
from customers in future rates. Likewise, certain credits that otherwise would
be reflected as income are deferred as regulatory liabilities based on expected
flowback to customers in future rates. Management's expected recovery of
deferred costs and expected flowback of deferred credits are generally based on
specific ratemaking decisions or precedent for each item. Regulatory assets and
liabilities are amortized consistent with ratemaking treatment established by
regulators. Note 9 describes the nature and amounts of these regulatory
deferrals.
STOCK-BASED EMPLOYEE COMPENSATION NSP has several stock-based compensation
plans, as described in Note 3. Under the intrinsic-value-based method of
accounting followed by NSP, no compensation expense is recorded for stock
options because there is no difference between the market price and purchase
price at the grant date, which is the measurement date for determining
compensation expense. NSP does, however, record compensation expense for stock
that is awarded to certain employees, but held by NSP until the restrictions
lapse or the stock is forfeited. Effective for 1996, the FASB issued a new
accounting standard, SFAS No. 123---Accounting for Stock-Based Compensation,
which provides an optional accounting method for compensation from stock option
and other stock award programs. NSP did not elect the new optional accounting
method. If the provisions of the optional method had been adopted as of the
beginning of 1995, the effect on net income and earnings per share for 1997,
1996 and 1995 would have been immaterial.
<PAGE>
DEVELOPMENT COSTS As it pursues projects under development, NRG expenses
development costs incurred until a sales agreement or letter of intent is signed
and the project has received capital authorization. Additional costs incurred
after this point are capitalized as part of equity investments in projects. When
project operations begin, such capitalized costs are amortized on a
straight-line basis over the lesser of the life of the project's related assets
or revenue contract period.
OTHER ASSETS The purchase of various nonregulated entities at a price exceeding
the underlying fair value of net assets acquired has resulted in recorded
goodwill of $43 million ($38 million net of accumulated amortization) at Dec.
31, 1997. This goodwill and other intangible assets acquired are being amortized
using the straight-line method over periods of three to 30 years. NSP
periodically evaluates the recovery of goodwill based on an analysis of
estimated undiscounted future cash flows.
Intangible and other assets also include deferred financing costs (net of
amortization) of approximately $22 million at Dec. 31, 1997. These financing
costs are being amortized over the remaining maturity period of the related
debt.
RECLASSIFICATIONS Certain reclassifications have been made to the 1996 and 1995
income statements to conform to 1997 presentation. These classifications had no
effect on net income or earnings per share.
2. Preferred Securities
The Company has two series of adjustable rate preferred stock. The dividend
rates are calculated quarterly and are based on prevailing rates of certain
taxable government debt securities indices. At Dec. 31, 1997, the annualized
dividend rates were $5.50 for both series A and series B.
At Dec. 31, 1997, various preferred stock series were callable at prices per
share ranging from $100.00 to $103.75, plus accrued dividends.
In January 1997, a wholly owned special purpose subsidiary trust of NSP issued
$200 million in 7.875 percent preferred securities that mature in 2037. A
portion of the proceeds was used to redeem the Company's $6.80 and $7.00 series
of preferred stock in February 1997. Distributions paid to preferred security
holders are reflected as a financing cost in the Consolidated Statement of
Income along with interest expense. Distributions paid by the subsidiary trust
on the preferred securities are financed through interest payments from the
Company on debentures issued by the Company and held by the subsidiary trust,
which are eliminated in NSP's consolidation. The preferred securities are
redeemable at $25 per share beginning in 2002. Distributions and redemption
payments are guaranteed by NSP.
3. Common Stock and Incentive Stock Plans
The Company's Articles of Incorporation and First Mortgage Indenture provide for
certain restrictions on the payment of cash dividends on common stock. At Dec.
31, 1997, the Company could have paid, without restrictions, additional cash
dividends of more than $1 billion on common stock.
Nonqualified stock options and restricted stock may be granted under NSP's
Executive Long-Term Incentive Award Stock Plan. The awards granted in any
calendar year cannot exceed 1 percent of the number of outstanding shares of NSP
common stock at the end of the previous calendar year. When options are
exercised, or restricted stock granted, the Company may either issue new shares
or purchase market shares. Using the treasury stock method of accounting for
stock options unexercised, the weighted average number of shares of common stock
outstanding for the calculation of Earnings Per Share - Assuming Dilution
includes any dilutive effects of stock options and other stock awards as
potential common shares.
Stock options currently granted may be exercised one year from the date of grant
and are exercisable thereafter for up to nine years. The options are forfeited
if employment ceases before the one-year vesting term. If employment ceases
after the one-year vesting term, options will either be forfeited, or would need
to be exercised within three or 36 months, depending on the circumstances. The
exercise price of an option is the market price of NSP common stock on the date
of grant. The plan, in previous years, granted other types of performance
awards, some of which are still outstanding. Most of these performance awards
were valued in dollars, but paid in shares based on the market price at the time
of payment. Transactions under the various incentive stock programs, with the
corresponding weighted average exercise price, were as follows:
<PAGE>
Stock Option and Performance Awards
<TABLE>
<CAPTION>
1997 1996 1995
----------------- ------------------ ------------------
AVERAGE Average Average
(Thousands of shares) SHARES PRICE Shares Price Shares Price
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding Jan. 1 1 117 43.97 990 $41.97 782 $40.58
Options granted in January 287 47.44 263 $50.94 278 $45.50
Options and awards exercised (260) 42.23 (105) $41.98 (64) $40.26
Options and awards forfeited (30) 47.19 (27) $47.70 (6) $44.58
Options and awards expired (11) 50.94 (4) $40.00
- ----------------------------------------------------------------------------------------------
Outstanding at Dec. 31 1 103 45.13 1 117 $43.97 990 $41.97
Exercisable at Dec. 31 843 44.41 870 $41.96 716 $40.60
==============================================================================================
</TABLE>
The following table summarizes information about stock options outstanding at
Dec. 31, 1997:
Range of Exercise Prices
-----------------------------
$33.25-40.94 $42.19-50.94
- --------------------------------------------------------------------------------
Options Outstanding:
Number outstanding at Dec. 31, 1997 170 346 923 517
Weighted-average remaining contractual life (years) 3.1 7.4
Weighted-average exercise price $37.15 $46.60
Options Exercisable:
Number exercisable at Dec. 31, 1997 170 346 663 156
Weighted-average exercise price $37.15 $46.27
In addition to stock options, restricted stock is granted based on a dollar
value of the award. The market price on the date of grant is used to determine
the number of restricted shares awarded. The stock is held by NSP until the
restrictions lapse: 50 percent of the stock will vest one year from the date of
the award and the remaining 50 percent vests two years from the date of the
award. Dividends on the shares held while the restrictions are in place are
reinvested to obtain additional shares, and the restrictions apply to these
additional shares. In each of the years 1995 through 1997, NSP granted
restricted stock awards of 15,898, 18,584 and 26,344 shares, respectively, at
then-current market prices of NSP stock. Compensation expense related to these
awards was immaterial.
4. Short-Term Borrowings
As of Dec. 31, 1997 and 1996, the Company had a $300 million revolving credit
facility under a commitment fee arrangement. This facility provides short-term
financing in the form of bank loans, letters of credit and support for
commercial paper sales. There were no borrowings against this facility at Dec.
31, 1997 and 1996. At Dec. 31, 1997 and 1996, credit lines of $245 million and
$75 million, respectively, were provided primarily by commercial banks to wholly
owned subsidiaries of the Company. There were $122 million and approximately $4
million in outstanding loans against these subsidiary credit lines at Dec. 31,
1997 and 1996, respectively. In addition, at Dec. 31, 1997 and 1996, $49 million
and $21 million, respectively, in letters of credit were outstanding (as
discussed in Note 11), which reduced the available credit lines.
At Dec. 31, 1997 and 1996, the Company had $138 million and $362 million,
respectively, in short-term commercial paper borrowings outstanding, and another
$122 million and $7 million, respectively, in short-term bank loans outstanding,
mainly for nonregulated subsidiaries. The weighted average interest rates on all
short-term borrowings were 6.2 percent as of Dec. 31, 1997, and 5.7 percent as
of Dec. 31, 1996.
5. Long-Term Debt
Except for minor exclusions, all real and personal property of the Company and
the Wisconsin Company is subject to the liens of the First Mortgage Indentures.
Other debt securities are secured by a lien on the related property, as
indicated on the Consolidated Statements of Capitalization.
The annual sinking-fund requirements of the Company's and the Wisconsin
Company's First Mortgage Indentures are the amounts necessary to redeem 1
percent of the highest principal amount of each series of first mortgage bonds
at any time outstanding, excluding those series issued for pollution control and
resource recovery financings, and excluding certain other series totaling $1
billion. The Company may, and has, applied property additions in lieu of cash
payments on all series, as permitted by its First Mortgage Indenture. The
Wisconsin Company also may apply property additions in lieu of cash on all
series as permitted by its First Mortgage Indenture.
<PAGE>
The Company's 2011 and 2019 series First Mortgage Bonds have variable interest
rates, which currently change at various periods up to 270 days, based on
prevailing rates for certain commercial paper securities or similar issues. The
interest rates applicable to these issues averaged 4.0 percent and 3.8 percent,
respectively, at Dec. 31, 1997. The 2011 series bonds are redeemable upon seven
days notice at the option of the bondholder. The Company also is potentially
liable for repayment of the 2019 series when the bonds are tendered, which
occurs each time the variable interest rates change. The principal amount of all
of these variable rate bonds outstanding represents potential short-term
obligations and, therefore, is reported under current liabilities on the balance
sheet.
Maturities and sinking-fund requirements on long-term debt (in millions) are:
1998, $22.8; 1999, $217.3; 2000, $122.4; 2001, $167.8; and 2002, $76.6.
6. Benefit Plans and Other Postretirement Benefits
NSP offers the following benefit plans to its benefit employees, of whom
approximately 40 percent are represented by five local labor unions under a
collective-bargaining agreement, which expires Dec. 31, 1999.
PENSION BENEFITS NSP has a noncontributory, defined benefit pension plan that
covers substantially all employees. Benefits are based on a combination of years
of service, the employee's highest average pay for 48 consecutive months and
Social Security benefits.
NSP's policy is to fully fund into an external trust the actuarially determined
pension costs recognized for ratemaking and financial reporting purposes,
subject to the limitations under applicable employee benefit and tax laws. Plan
assets principally consist of common stock of public companies, corporate bonds
and U.S. government securities. The funded status of NSP's pension plan as of
Dec. 31 is as follows:
(Thousands of dollars) 1997 1996
- -------------------------------------------------------------------------------
Actuarial present value of benefit obligation:
Vested $701 219 $660 920
Nonvested 165 004 147 278
- -------------------------------------------------------------------------------
Accumulated benefit obligation $866 223 $808 198
===============================================================================
Projected benefit obligation $1 048 251 $993 821
Plan assets at fair value 1 978 538 1 634 696
- -------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 930 287 640 875
Unrecognized prior service cost 18 663 19 734
Unrecognized net actuarial gain (953 825) (651 368)
Unrecognized net transitional asset (463) (539)
- -------------------------------------------------------------------------------
Net pension asset (liability) recorded $(5 338) $8 702
===============================================================================
For ratemaking purposes, the Company's pension costs are determined and recorded
under the aggregate-cost actuarial method. As required by SFAS No.
87---Employers' Accounting for Pensions, the difference between the pension
costs recorded for ratemaking purposes and the amounts determined under SFAS No.
87 is recorded as a regulatory liability on the balance sheet. Net annual
periodic pension cost includes the following components:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost-benefits earned during the period $27 680 $29 971 $24 499
Interest cost on projected benefit obligation 72 651 70 863 69 742
Actual return on assets (420 174) (265 370) (344 837)
Net amortization and deferral 285 048 139 874 240 458
- ----------------------------------------------------------------------------------------------
Net periodic pension cost determined under SFAS No. 87 (34 795) (24 662) (10 138)
Additional costs recognized due to actions of regulators 30 862 23 572 10 454
- ----------------------------------------------------------------------------------------------
Net periodic pension cost recognized for financial reporting $(3 933) $(1 090) $316
==============================================================================================
</TABLE>
The weighted average discount rate used in determining the actuarial present
value of the projected obligation was 7 percent for Dec. 31, 1997 and 7.5
percent for Dec. 31, 1996. The rate of increase in future compensation levels
used in determining the actuarial present value of the projected obligation was
5 percent in 1997 and 1996. The assumed long-term rate of return on assets used
for cost determinations under SFAS No. 87 was 9 percent for
<PAGE>
1997, 1996 and 1995. Assumption changes decreased 1997 pension costs (determined
under SFAS No. 87) by approximately $6.9 million and increased 1996 costs by
approximately $12.6 million. However, because the Company's pension expense is
determined under the aggregate-cost method (not SFAS No. 87) for ratemaking and
financial reporting purposes, the effects of regulation prevented the majority
of assumption changes from affecting earnings.
401(k) NSP has a contributory, defined contribution Retirement Savings Plan,
which complies with section 401(k) of the Internal Revenue Code and covers
substantially all employees. Since 1994, NSP has been matching specified amounts
of employee contributions to this plan. NSP's matching contributions were $4.4
million in 1997, $4.3 million in 1996 and $3.7 million in 1995.
POSTRETIREMENT HEALTH CARE NSP has a contributory health and welfare benefit
plan that provides health care and death benefits to substantially all employees
after their retirement. The plan is intended to provide for sharing the costs of
retiree health care between NSP and retirees. For employees retiring after Jan.
1, 1994, a six-year cost-sharing strategy was implemented with retirees paying
15 percent of the total cost of health care in 1994, increasing to a total of 40
percent in 1999. In conjunction with the 1993 adoption of SFAS No.
106-Employers' Accounting for Postretirement Benefits Other Than Pensions, NSP
elected to amortize on a straight-line basis over 20 years the unrecognized
accumulated postretirement benefit obligation (APBO) of $215.6 million for
current and future retirees.
Before 1993, NSP funded payments for retiree benefits internally. While NSP
generally prefers to continue using internal funding of benefits paid and
accrued, significant levels of external funding, including the use of
tax-advantaged trusts, have been required by NSP's regulators, as discussed
later. Plan assets held in such trusts principally consist of investments in
equity mutual funds and cash equivalents. The funded status of NSP's retiree
health care plan as of Dec. 31 is as follows:
(Thousands of dollars) 1997 1996
- ----------------------------------------------------------------------------
APBO:
Retirees $149 081 $144 180
Fully eligible plan participants 21 245 23 438
Other active plan participants 108 904 101 065
- -----------------------------------------------------------------------------
Total APBO 279 230 268 683
Plan assets at fair value 19 784 15 514
- -----------------------------------------------------------------------------
APBO in excess of plan assets 259 446 253 169
Unrecognized net actuarial loss (14 408) (12 467)
Unrecognized transition obligation (161 700) (172 480)
- ------------------------------------------------------------------------------
Net benefit liability recorded $83 338 $ 68 222
=============================================================================
The assumed health care cost trend rates used in measuring the APBO at Dec. 31,
1997 and 1996, were 9.2 percent and 9.8 percent for those under age 65, and 6.8
percent and 7.1 percent for those age 65 and over, respectively. The assumed
cost trend rates are expected to decrease each year until they reach 5.5 percent
for both age groups in the year 2004, after which they are assumed to remain
constant. A 1 percent increase in the assumed health care cost trend rate for
each year would increase the APBO by approximately 14.5 percent as of Dec. 31,
1997. Service and interest cost components of the net periodic postretirement
cost would increase by approximately 15.4 percent with a similar 1 percent
increase in the assumed health care cost trend rate. The assumed discount rate
used in determining the APBO was 7 percent for Dec. 31, 1997, and 7.5 percent
for Dec. 31, 1996, compounded annually. The assumed long-term rate of return on
assets used for cost determinations under SFAS No. 106 was 8 percent for 1997,
1996 and 1995. Assumption changes decreased costs by approximately $4.0 million
in 1997 and approximately $2.0 million in 1996.
<PAGE>
The net annual periodic postretirement benefit cost recorded consists of the
following components:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost-benefits earned during the year $5 095 $ 6 380 $ 5 206
Interest cost (on service cost and APBO) 18 872 19 283 19 201
Actual return on assets (1 461) (947) (1 046)
Amortization of transition obligation 10 780 10 780 10 780
Net amortization and deferral 222 140 406
- -------------------------------------------------------------------------------------------------
Net periodic postretirement health care cost under SFAS No. 106 33 508 35 636 34 547
Additional costs recognized due to actions of regulators 4 033 4 033
- -------------------------------------------------------------------------------------------------
Net postretirement cost recognized for financial reporting $33 508 $39 669 $38 580
=================================================================================================
</TABLE>
Regulators for nearly all of NSP's retail and wholesale customers have allowed
full recovery of increased benefit costs under SFAS No. 106, effective in 1993.
Increased 1993 accrual costs of approximately $12 million for Minnesota retail
customers were amortized over the years 1994 through 1996, consistent with
approved rate recovery. External funding was required by Minnesota and Wisconsin
retail regulators to the extent it is tax advantaged; funding began for
Wisconsin in 1993 and will begin in 1998 for Minnesota. For wholesale
ratemaking, the FERC has required external funding for all benefits paid and
accrued under SFAS No. 106 since 1993.
ESOP NSP has a leveraged Employee Stock Ownership Plan (ESOP) that covers
substantially all employees. Employer contributions to this non-contributory,
defined contribution plan are generally made to the extent NSP realizes a tax
savings on its income statement from dividends paid on certain shares held by
the ESOP. Contributions to the ESOP in 1997, 1996 and 1995, which represent
compensation expense, were $4.4 million, $4.6 million and $5.0 million,
respectively. ESOP contributions have no material effect on NSP earnings because
the contributions (net of tax) are essentially offset by the tax savings
provided by the dividends paid on ESOP shares. Leveraged shares held by the ESOP
are allocated to participants when dividends on stock held by the plan are used
to repay ESOP loans. NSP's ESOP held 5.6 million and 5.9 million shares of the
Company's common stock as of Dec. 31, 1997 and 1996, respectively. An average of
0.3 million, 0.2 million and 0.2 million uncommitted leveraged ESOP shares were
excluded from earnings-per-share calculations in 1997, 1996 and 1995,
respectively. The fair value of NSP's leveraged ESOP shares was approximately
the same as cost at Dec. 31, 1997 and 1996.
<PAGE>
7. Income Taxes
Total income tax expense from operations differs from the amount computed by
applying the statutory federal income tax rate to income before income tax
expense. The reasons for the difference are as follows:
<TABLE>
<CAPTION>
1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal statutory rate 35.0% 35.0% 35.0%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit 4.3% 5.2% 5.1%
Tax credits recognized (7.9)% (4.1)% (3.4)%
Equity income from unconsolidated affiliates (2.5)% (2.6)% (2.5)%
Regulatory differences---utility plant items 1.1% 0.9% 1.0%
Other---net (1.0)% 0.4% 0.4%
- ------------------------------------------------------------------------------------------------------------------
Effective income tax rate 29.0% 34.8% 35.6%
==================================================================================================================
(Thousands of dollars)
Income taxes are comprised of the following expense (benefit) items:
Included in utility operating expenses:
Current federal tax expense $125 202 $154 421 $137 011
Current state tax expense 28 812 39 923 33 359
Deferred federal tax expense (88) (19 933) (12 019)
Deferred state tax expense (23) (3 958) (2 396)
Deferred investment tax credits (9 048) (9 043) (8 807)
- ------------------------------------------------------------------------------------------------------------------
Total 144 855 161 410 147 148
- ------------------------------------------------------------------------------------------------------------------
Included in income taxes on nonregulated operations
and nonoperating items:
Current federal tax expense (19 470) (906) 5 481
Current state tax expense (5 804) 712 1 629
Current foreign tax expense 236 616 233
Current federal tax credits (17 006) (8 044) (5 292)
Deferred federal tax expense (2 237) (5 150) 2 646
Deferred state tax expense (662) (1 520) 693
Deferred foreign tax expense (2 892) 0 0
Deferred investment tax credits (310) (308) (310)
- ------------------------------------------------------------------------------------------------------------------
Total (48 145) (14 600) 5 080
- ------------------------------------------------------------------------------------------------------------------
Total income tax expense $96 710 $146 810 $152 228
==================================================================================================================
</TABLE>
Income before income taxes includes net foreign equity income of $27 million,
$28 million and $32 million in 1997, 1996 and 1995, respectively. Except to the
extent NSP's earnings from foreign operations are subject to current U.S. income
taxes, NSP's management intends to reinvest indefinitely such earnings in its
foreign operations. Accordingly, U.S. income taxes and foreign withholding taxes
have not been provided on a cumulative amount of unremitted earnings of foreign
subsidiaries of approximately $112 million at Dec. 31, 1997. The additional U.S.
income tax and foreign withholding tax on the unremitted foreign earnings, if
repatriated, would be offset in whole or in part by foreign tax credits. Thus,
it is impracticable to estimate the amount of tax that might be payable.
<PAGE>
The components of NSP's net deferred tax liability (current and noncurrent
portions) at Dec. 31 were:
(Thousands of dollars) 1997 1996
- --------------------------------------------------------------------------------
Deferred tax liabilities:
Differences between book and tax bases of property $867 155 $850 139
Regulatory assets 100 564 121 232
Tax benefit transfer leases 31 614 43 481
Other 21 715 23 182
- --------------------------------------------------------------------------------
Total deferred tax liabilities $1 021 048 $1 038 034
- --------------------------------------------------------------------------------
Deferred tax assets:
Regulatory liabilities $83 765 $90 485
Deferred compensation, vacation and other
accrued liabilities not currently deductible 70 765 65 690
Deferred investment tax credits 54 741 57 239
Other 26 557 34 509
- --------------------------------------------------------------------------------
Total deferred tax assets $235 828 $247 923
- --------------------------------------------------------------------------------
Net deferred tax liability $785 220 $790 111
================================================================================
8. Detail of Certain Income and Expense Items
Administrative and general (A&G) expense for utility operations consists of the
following:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
A&G salaries and wages $44 514 $47 546 $48 437
Pension, medical and other benefits---all utility employees 57 529 64 733 81 279
Information technology, facilities and administrative support 28 653 21 281 31 863
Insurance and claims 1 087 5 503 13 969
Other 10 019 9 593 10 599
- ----------------------------------------------------------------------------------------------
Total $141 802 $148 656 $186 147
==============================================================================================
</TABLE>
Income from nonregulated businesses consists of the following:
<TABLE>
<CAPTION>
(Thousands of dollars, except per share amounts) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $217 844 $303 903 $313 082
Equity in earnings of unconsolidated affiliates:
Earnings from operations 18 600 30 668 28 055
Gains from contract terminations 29 850
Operating and development expenses * (251 087) (326 332) (327 894)
Interest and other income 26 721 10 304 6 518
- ----------------------------------------------------------------------------------------------------
Income from nonregulated businesses before interest and taxes 12 078 18 543 49 611
Interest and amortization expense (34 627) (18 834) (9 879)
Income tax benefit (expense) 38 032 16 576 (6 119)
- -----------------------------------------------------------------------------------------------------
Net Income $15 483 $16 285 $33 613
====================================================================================================
Contribution of nonregulated businesses to NSP's earnings per share* $0.22 $0.24 $0.50
====================================================================================================
</TABLE>
* Includes nonrecurring project write-downs of $9 million in 1997 and $5 million
in 1995
<PAGE>
9. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory
assets and liabilities shown on the Consolidated Balance Sheets at Dec. 31:
<TABLE>
<CAPTION>
Remaining
(Thousands of dollars) Amortization Period 1997 1996
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
AFC recorded in plant on a net-of-tax basis * Plant Lives $128 364 $137 412
Conservation and energy management programs * Primarily 3 Years 86 508 95 716
Losses on reacquired debt Term of Related Debt 59 353 63 481
Environmental costs Primarily 10 Years 45 849 42 322
State commission accounting adjustments * Plant Lives 7 286 7 296
Unrecovered purchased gas costs 1-2 Years 8 020 3 885
Other Various 4 742 4 016
- -----------------------------------------------------------------------------------------------------------
Total regulatory assets $340 122 $354 128
===========================================================================================================
Deferred income tax adjustments 88 035 $92 390
Investment tax credit deferrals 91 146 97 636
Unrealized gains from decommissioning investments 85 482 43 008
Pension costs-regulatory differences 27 107 45 080
Fuel costs, refunds and other 13 995 24 533
- -----------------------------------------------------------------------------------------------------------
Total regulatory liabilities $305 765 $302 647
===========================================================================================================
</TABLE>
* Earns a return on investment in the ratemaking process
10. Investments Accounted for by the Equity Method
Through its nonregulated subsidiaries, NSP has investments in various
international and domestic energy projects and domestic affordable housing and
real estate projects. The equity method of accounting is applied to such
investments in affiliates, which include joint ventures and partnerships,
because the ownership structure prevents NSP from exercising a controlling
influence over operating and financial policies of the projects. Under this
method, equity in the pretax income or losses of domestic partnerships and in
the net income or losses of international projects is reflected as Equity in
Earnings of Unconsolidated Affiliates. A summary of NSP's significant
equity-method investments is as follows:
<TABLE>
<CAPTION>
Name Geographic Area Economic Interest
- ------------------------------------------------------------------------------------
<S> <C> <C>
Loy Yang Power * Australia 25.37%
Pacific Generation Company * USA/Canada 8.50%-28.70%
Gladstone Power Station Australia 37.50%
COBEE South America 48.30%
MIBRAG mbH Europe 33.33%
NRG Generating (U.S.) Inc. USA 45.21%
Schkopau Power Station Europe 20.55%
Energy Development, Limited * Australia 19.97%
Scudder Latin American Trust
for Independent Power Energy Projects Latin America 25%
Various independent power production facilities * USA 45%-50%
Various affordable housing limited partnerships * USA 20%-99%
</TABLE>
*Acquired in 1997
<PAGE>
SUMMARIZED FINANCIAL INFORMATION OF UNCONSOLIDATED AFFILIATES Summarized
financial information for these projects, including interests owned by NSP and
other parties, was as follows for the years ended and as of Dec. 31:
RESULTS OF OPERATIONS
(Millions of dollars)
1997 1996 1995
---- ---- ----
Operating Revenues $1 698 $958 $790
Operating Income $ 93 $105 $154
Net Income $ 84 $89 $160
NSP's Equity in Earnings of
Unconsolidated Affiliates $19 $31 $59
FINANCIAL POSITION
(Millions of dollars)
1997 1996
---- ----
Current Assets $ 742 $ 681
Other Assets 7 853 3 525
----- ------
Total Assets $8 595 $4 206
====== ======
Current Liabilities $ 514 $ 397
Other Liabilities 6 109 2 798
Equity 1 972 1 011
----- ------
Total Liabilities and Equity $8 595 $4 206
====== ======
NSP's Equity Investment in
Unconsolidated Affiliates $ 741 $410
11. Financial Instruments
FAIR VALUES The estimated Dec. 31 fair values of NSP's recorded financial
instruments are as follows:
<TABLE>
<CAPTION>
1997 1996
- ------------------------------------------------------------------------------------------------------------------
CARRYING FAIR Carrying Fair
(Thousands of dollars) AMOUNT VALUE Amount Value
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash, cash equivalents and short-term investments $54 765 $54 765 $51 118 $51 118
Long-term decommissioning investments $344 491 $344 491 $260 756 $260 756
Long-term debt, including current portion $2 043 295 $2 079 123 $1 853 786 $1 838 408
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
For cash, cash equivalents and short-term investments, the carrying amount
approximates fair value because of the short maturity of those instruments. The
fair values of the Company's long-term investments, mainly debt securities in an
external nuclear decommissioning fund, are estimated based on quoted market
prices for those or similar investments. The fair value of NSP's long-term debt
is estimated based on the quoted market prices for the same or similar issues,
or the current rates for debt of the same remaining maturities and credit
quality.
DERIVATIVES NRG has entered into forward foreign currency exchange contracts
with counterparties to hedge certain exposures to currency fluctuations.
Pursuant to these contracts, transactions have been executed that are designed
to protect the economic value in U.S. dollars of selected known and anticipated
NRG cash flows denominated in Australian dollars and German deutsche marks. As
of Dec. 31, 1997, NRG had in place contracts with a notional value of $10
million to hedge foreign currency denominated known future cash flows. In
addition, NRG has in place forward foreign currency exchange contracts with a
net notional value of $8.6 million to hedge projected construction expenditures,
which do not qualify for hedge accounting and consequently result in currency
fluctuations that can affect earnings. The effect on 1997 earnings from these
contracts was immaterial. The forward foreign currency exchange contracts
terminate in 1998. If all of the contracts had been terminated at Dec. 31, 1997,
$1.0 million would have been payable by NRG for currency exchange rate changes
to date. Management believes NRG's exposure to credit risk due to nonperformance
by the counterparties to its forward exchange contracts is not significant,
based on the investment grade rating of the counterparties.
<PAGE>
NRG also has two agreements in place, with a notional amount of $80 million, to
fix the interest rate at a rate based on U.S. Treasury obligations for known
future borrowings related to project investment commitments. If the agreements
had been terminated at Dec. 31, 1997, $4.2 million would have been payable by
NRG based on the underlying U.S. Treasury interest rate on that date.
EMI has entered into natural gas futures contracts in the notional amount of $23
million at Dec. 31, 1997. The original contract terms range from one month to
two years. The contracts are intended to mitigate risk from fluctuations in the
price of natural gas that will be required to satisfy sales commitments for
future deliveries to customers in excess of EMI's natural gas reserves. EMI's
futures contracts hedge $24 million in anticipated natural gas sales in
1998-1999. Margin balances of $3 million at Dec. 31, 1997, were maintained on
deposit with brokers and recorded as cash and cash equivalents on NSP's balance
sheet. The counterparties to the futures contracts are the New York Mercantile
Exchange, investment banks and major gas pipeline operators. Management believes
that the risk of nonperformance by these counterparties is not significant. If
the contracts had been terminated at Dec. 31, 1997, $0.7 million would have been
payable by EMI for natural gas price fluctuations to date.
NSP has two interest rate swap agreements with notional amounts totaling $220
million. These swaps were entered into in conjunction with first mortgage bonds.
As summarized below, these agreements effectively convert the interest costs of
these debt issues from fixed to variable rates based on the six-month London
Interbank Offered Rate (LIBOR), with the rates changing semiannually.
Term of Net Effective
Notional Amount Swap Interest Cost at
Series (millions of dollars) Agreement at Dec. 31, 1997
- --------------------------------------------------------------------------------
5 1/2% Series due Feb. 1, 1999 $200 Maturity 5.49%
7 1/4% Series due March 1, 2023 $ 20 March 1, 1998 7.96%
Market risks associated with these agreements result from short-term interest
rate fluctuations. Credit risk related to nonperformance of the counterparties
is not deemed significant, but would result in NSP terminating the swap
transaction and recognizing a gain or loss, depending on the fair market value
of the swap. The interest rate swaps serve to hedge the market risk associated
with fixed rate debt in a declining interest rate environment. This hedge is
produced by the tendency for changes in the fair market value of the swap to be
offset by changes in the present value of the liability attributable to the
fixed rate debt issued in conjunction with the interest rate swaps. If the
interest rate swaps had been discontinued on Dec. 31, 1997, $0.6 million would
have been payable by the Company, while the present value of the related fixed
rate debt was $0.6 million below carrying value.
LETTERS OF CREDIT NSP uses letters of credit to provide financial guarantees for
certain operating obligations, including NSP workers' compensation benefits and
ash disposal site costs, and EMI natural gas purchases, generally with terms of
one year which are automatically renewed, unless prior written notice of
cancellation is provided to NSP and the beneficiary by the issuing bank. In
addition, NRG uses letters of credit for nonregulated equity commitments, as
collateral for credit agreements, for fuel purchase and operating commitments
and bids on development projects. At Dec. 31, 1997, letters of credit of $101
million were outstanding, of which $48 million related to NRG commitments. The
contract amounts of these letters of credit approximate their fair value and are
subject to fees competitively determined in the marketplace.
12. Joint Plant Ownership
The Company is a part owner of an 855-megawatt coal-fired electric generating
unit, Sherburne County generating station unit No. 3 (Sherco 3), which began
commercial operation Nov. 1, 1987. Undivided interests in Sherco 3 have been
financed and are owned by the Company (59 percent) and Southern Minnesota
Municipal Power Agency (41 percent). The Company is the operating agent under
the joint ownership agreement. The Company's share of related expenses for
Sherco 3 since commercial operations began are included in Utility Operating
Expenses. The Company's share of the gross cost recorded in Utility Plant at
Dec. 31, 1997 and 1996, was $603.9 million and $588.0 million, respectively. The
corresponding accumulated provisions for depreciation were $196.2 million and
$168.6 million.
<PAGE>
13. Nuclear Obligations
FUEL DISPOSAL NSP is responsible for the temporary storage of used nuclear fuel
from the Company's nuclear generating plants. Under a contract with the Company,
the DOE is obligated to assume the responsibility for permanent storage or
disposal of NSP's used nuclear fuel. The Company has been funding its portion of
the DOE's permanent disposal program since 1981. Funding took place through an
internal sinking fund until 1983, when the DOE began assessing fuel disposal
fees under the Nuclear Waste Policy Act of 1982 based on a charge of 0.1 cent
per kilowatt-hour sold to customers from nuclear generation. Fuel expense
includes DOE fuel disposal assessments of $10.1 million, $11.3 million and $12.3
million in 1997, 1996 and 1995, respectively. The cumulative amount of such
assessments paid by NSP to the DOE through Dec. 31, 1997, was approximately $250
million. Currently, it is not determinable if the amount and method of the DOE's
assessments to all utilities will be sufficient to fully fund the DOE's
permanent storage or disposal facility.
The Nuclear Waste Policy Act stipulated that the DOE execute contracts with
utilities that require DOE to begin accepting spent nuclear fuel no later than
Jan. 31, 1998. Accordingly, NSP has been providing, with regulatory and
legislative approval, its own temporary on-site storage facilities at its
Monticello and Prairie Island nuclear plants. In December 1996, the DOE notified
commercial spent fuel owners of an anticipated delay in accepting used nuclear
fuel by the required date of Jan. 31, 1998, and conceded that a permanent
storage or disposal facility will not be available until at least 2010.
The Company and other affected parties have commenced lawsuits against the DOE
to require the DOE to meet its statutory and contractual obligations, which can
include damages for nonperformance. NSP and other utilities are currently
analyzing claims against the DOE for the costs incurred as a result of the DOE's
failure to meet its statutory and contractual obligations. With the dry cask
storage facilities approved in 1994 for the Prairie Island nuclear generating
plant, the Company believes it has adequate storage capacity to continue
operation of its Prairie Island nuclear plant until at least 2007. The
Monticello nuclear plant has storage capacity to continue operations until 2010.
Storage availability to permit operation beyond these dates is not assured at
this time. In the meantime, NSP is investigating all of its alternatives for
used fuel storage until a DOE facility is available, including pursuing the
establishment of a private facility for interim storage of used nuclear fuel as
part of a consortium of electric utilities. If on-site temporary storage at
NSP's nuclear plants reaches approved capacity, the Company could seek interim
storage at this or another contracted private facility, if available.
Nuclear fuel expenses in 1997, 1996 and 1995 include about $4 million, $4
million and $5 million, respectively, for payments to the DOE for the
decommissioning and decontamination of the DOE's uranium enrichment facilities.
The DOE's initial assessment of $46 million to the Company was recorded in 1993.
This assessment will be payable in annual installments from 1993-2008 and each
installment is being amortized to expense on a monthly basis in the 12 months
following each payment. The most recent installment paid in 1997 was $3.9
million; future installments are subject to inflation adjustments under DOE
rules. The Company is obtaining rate recovery of these DOE assessments through
the cost-of-energy adjustment clause as the assessments are amortized.
Accordingly, the unamortized assessment of $38 million at Dec. 31, 1997, has
been deferred as a regulatory asset and is reported under the caption
Environmental Costs in Note 9.
PLANT DECOMMISSIONING Decommissioning of all Company nuclear facilities is
planned for the years 2010-2022, using the prompt dismantlement method. The
Company currently is following industry practice by ratably accruing the costs
for decommissioning over the approved cost recovery period and including the
accruals in Utility Plant---Accumulated Depreciation, as discussed in Note 1.
Consequently, the total decommissioning cost obligation and corresponding asset
currently are not recorded in NSP's financial statements. The FASB has proposed
new accounting standards, which, if approved, would require the full accrual of
nuclear plant decommissioning and certain other site exit obligations no sooner
than 1999. Using Dec. 31, 1997, estimates, NSP's adoption of the proposed
accounting would result in the recording of the total discounted decommissioning
obligation of $698 million as a liability, with the corresponding costs
capitalized as plant and other assets and depreciated over the operating life of
the plant. The obligation calculation methodology proposed by the FASB is
slightly different from the ratemaking methodology that derives the
decommissioning accruals currently being recovered in rates, as discussed later.
The Company has not yet determined the potential impact of the FASB's proposed
changes in the accounting for site exit obligations other than nuclear
decommissioning (such as costs of removal). However, the ultimate
decommissioning and site exit costs to be accrued are the same under both
methods and, accordingly, the effects of regulation are expected to minimize or
eliminate any impact on operating expenses and results of operations from this
future accounting change.
<PAGE>
Consistent with cost recovery in utility customer rates, the Company records
annual decommissioning accruals based on periodic site-specific cost studies and
a presumed level of dedicated funding. Cost studies quantify decommissioning
costs in current dollars. Since the costs are expected to be paid in 2010-2022,
funding presumes that current costs will escalate in the future at a rate of 4.5
percent per year. The total estimated decommissioning costs that will ultimately
be paid, net of income earned by external trust funds, is currently being
accrued using an annuity approach over the approved plant recovery period. This
annuity approach uses an assumed rate of return on funding, which is currently 6
percent (net of tax) for external funding and approximately 8 percent (net of
tax) for internal funding.
The total obligation for decommissioning currently is expected to be funded
approximately 82 percent by external funds and 18 percent by internal funds, as
approved by the MPUC. Rate recovery of internal funding began in 1971 through
depreciation rates for removal expense, and was changed to a sinking fund
recovery in 1981. Contributions to the external fund started in 1990 and are
expected to continue until plant decommissioning begins. Costs not funded by
external trust assets, including accumulated earnings, will be funded through
internally generated funds and issuance of Company debt or stock. The assets
held in trusts as of Dec. 31, 1997, primarily consisted of investments in fixed
income securities, such as tax-exempt municipal bonds and U.S. government
securities, which mature in two to 26 years, and common stock of public
companies. The Company plans to reinvest matured securities until
decommissioning commences.
At Dec. 31, 1997, the Company has recorded and recovered in rates cumulative
decommissioning accruals of $465 million. The following table summarizes the
funded status of the Company's decommissioning obligation at Dec. 31, 1997:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997
- ---------------------------------------------------------------------------------------------------------
<S> <C>
Estimated decommissioning cost obligation from most recent approved study (1993 dollars) $750 824
Effect of escalating costs to 1997 dollars (at 4.5% per year) 144 548
- ---------------------------------------------------------------------------------------------------------
Estimated decommissioning cost obligation in current dollars 895 372
Effect of escalating costs to payment date (at 4.5% per year) 949 413
- ---------------------------------------------------------------------------------------------------------
Estimated future decommissioning costs (undiscounted) 1 844 785
Effect of discounting obligation (using risk-free interest rate) (1 147 177)
- ---------------------------------------------------------------------------------------------------------
Discounted decommissioning cost obligation 697 608
External trust fund assets at fair value 344 491
- ---------------------------------------------------------------------------------------------------------
Discounted decommissioning obligation in excess of assets currently held in external trust $353 117
=========================================================================================================
</TABLE>
Decommissioning expenses recognized include the following components:
<TABLE>
<CAPTION>
(Thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Annual decommissioning cost accrual reported as depreciation expense:
Externally funded $33 178 $33 178 $33 178
Internally funded (including interest costs) 1 368 1 268 1 174
Interest cost on externally funded decommissioning obligation 7 690 5 246 5 966
Earnings from external trust funds (7 690) (6 294) (5 620)
- -----------------------------------------------------------------------------------------------------
Net decommissioning accruals recorded $34 546 $33 398 $34 698
====================================================================================================
</TABLE>
Decommissioning and interest accruals are included with the accumulated
provision for depreciation on the balance sheet. Interest costs and trust
earnings associated with externally funded obligations are reported in Other
Utility Income and Deductions on the income statement.
The MPUC last approved a nuclear decommissioning study and related nuclear plant
depreciation capital recovery request in April 1997, using cost data from the
1993 study. Although management expects to operate the Prairie Island units
through the end of each unit's licensed life, the approved capital recovery
would allow for the plant to be fully depreciated, including the accrual and
recovery of decommissioning costs, in 2008, about six years earlier than the end
of each unit's licensed life. The approved recovery period for Prairie Island
has been reduced because of the uncertainty regarding used fuel storage, as
discussed previously. The Company believes future decommissioning cost accruals
will continue to be recovered in customer rates.
<PAGE>
14. Commitments and Contingent Liabilities
CAPITAL COMMITMENTS NSP estimates utility capital expenditures, including
acquisitions of nuclear fuel, will be $441 million in 1998 and $2.1 billion for
1998-2002. There also are contractual commitments for the disposal of used
nuclear fuel. (See Note 13.)
As of Dec. 31, 1997, NRG is contractually committed to additional equity
investments of approximately $35 million in 1998 and approximately $172 million
for 1998-2002 for various international power generation projects. In addition,
in 1996, NRG executed an agreement whereby NRG is obligated to provide to NRG
Generating (U.S.) Inc. (NRGG), an unconsolidated affiliate of NRG, power
generation investment opportunities in the United States over a three-year
period. These projects must have in aggregate, over the three-year term, an
equity value of at least $60 million or a minimum of 150 net megawatts. In
addition, NRG has committed to finance NRGG's investment in the projects to the
extent funds are not available to NRGG on comparable terms from other sources.
As required by the agreement, NRG provided several investment opportunities to
NRGG in 1997, and, as a result, NRGG purchased the Millennium project from NRG.
NRGG financed the Millennium purchase from sources other than NRG.
LEGISLATIVE RESOURCE COMMITMENTS In 1994, the Minnesota Legislature established
several energy resource and other commitments for NSP to obtain the Prairie
Island temporary nuclear fuel storage facility approval. The commitments, which
can be met by building, purchasing or, in the case of biomass, converting
generation resources, are:
Power Type Megawatts Required Contract Deadline
- ----------------------------------------------------------------------------
Wind 100 (Additional) 12/31/96
Wind 100 (Additional) 12/31/98
Wind 200 (Additional) 12/31/02
Total Wind 400
Biomass 50 (Additional) 12/31/98
Biomass 75 (Additional) 12/31/98
--
Total Biomass 125
The Company is complying with the requirements of these resource commitments as
follows:
Power Type Developer Megawatts Operation Date
- --------------------------------------------------------------------------------
Wind Lake Benton Power Partners LLC (1) 107.25 June 1998 (2)
Wind Northern Alternative Energy, Inc. 22.65 Oct. 1998 (2)
Wind Lake Benton Power Partners II LLC 100.50 Mid-1999 (3)
Wind Woodstock Wind Farm, LLC 10.20 Oct. 1998 (2)
-------
Total Wind 240.60
Biomass Minnesota Valley Alfalfa Producers (4) 75.00 Dec. 2001 (5)
Biomass District Energy St. Paul Inc. 25.00 Summer 2002 (6)
Biomass Lindroc Energy 25.00 Summer 2002 (6)
-------
Total Biomass 125.00
(1) Formerly Zond Minnesota Development Corporation II
(2) Approved by MPUC
(3) Selected after a competitive negotiation process
(4) Formerly Minnesota Agri-Power Project
(5) Agreement signed
(6) Selected after a competitive bid process
<PAGE>
In 1994, the Company received Minnesota legislative approval for additional
on-site temporary storage facilities at NSP's Prairie Island plant, provided the
Company satisfies certain requirements. Seventeen dry cask containers, each of
which can store approximately one-half year's used fuel, were approved to become
available. The first four casks were available in 1994. In late 1996, the MEQB
certified that NSP has met the requirements necessary to use the sixth through
ninth casks at the Prairie Island nuclear generating facility. The final eight
casks become available in 1999 unless the above resource commitments are not met
and the Minnesota Legislature revokes its approval. As of Dec. 31, 1997, the
Company had loaded seven casks.
Other commitments established by the Legislature include a discount for
low-income electric customers, required conservation improvement expenditures
and various study and reporting requirements to a legislative electric energy
task force. In 1995, the MPUC approved the Company's low-income discount
programs in accordance with the statute. The Company has implemented programs to
begin meeting the other legislative commitments. The Company's capital
commitments, disclosed below, include the known effects of the 1994 Prairie
Island legislation. The impact of the legislation on power purchase commitments
and other operating expenses is not yet determinable.
GUARANTEES In 1997 and 1996, the Company sold a portion of its other
receivables, consisting of energy loans made to customers, to a third party. The
portion of the receivables sold consisted of customer loans to local government
entities for energy efficiency improvements under various conservation programs
offered by the Company. Under the sale agreements, the Company is required to
guarantee repayment to the third party of the remaining loan balances. At Dec.
31, 1997, the outstanding balance of the loans was approximately $28 million.
Based on prior collection experience of these loans, the Company believes that
losses under the loan guarantees, if any, would have an immaterial impact on the
results of operations.
LEASES Rentals under operating leases were approximately $32 million, $29
million and $27 million for 1997, 1996 and 1995, respectively. Future
commitments under these leases generally decline from current levels.
FUEL CONTRACTS NSP has contracts providing for the purchase and delivery of a
significant portion of its current coal, nuclear fuel and natural gas
requirements. These contracts, which expire in various years between 1998 and
2013, require minimum purchases and deliveries of fuel, and additional payments
for the right to purchase coal in the future. In total, NSP is committed to the
minimum purchase of approximately $341 million of coal, $29 million of nuclear
fuel and $291 million of natural gas and related transportation, or to make
payments in lieu thereof, under these contracts. In addition, NSP is required to
pay additional amounts depending on actual quantities shipped under these
agreements. As a result of FERC Order 636, NSP has developed a mix of gas
supply, transportation and storage contracts designed to meet its needs for
retail gas sales. The contracts are with several suppliers and for various
periods of time. Because NSP has other sources of fuel available and suppliers
are expected to continue to provide reliable fuel supplies, risk of loss from
nonperformance under these contracts is not considered significant. In addition,
NSP's risk of loss, in the form of increased costs, from market price changes in
fuel is mitigated through the cost-of-energy adjustment provision of the
ratemaking process, which provides for recovery of nearly all fuel costs.
POWER AGREEMENTS The Company has executed several agreements with the Manitoba
Hydro-Electric Board (MH) for hydroelectricity. A summary of the agreements is
as follows:
Years Megawatts
Participation Power Purchase 1998-2005 500
Seasonal Diversity Exchanges:
Summer exchanges from MH 1998-2014 150
1998-2016 200
Winter exchanges to MH 1998-2014 150
1998-2015 200
2015-2017 400
2018 200
The cost of the 500-megawatt participation power purchase commitment is based on
80 percent of the costs of owning and operating the Company's Sherco 3
generating plant, adjusted to 1993 dollars. The future annual capacity costs for
the 500-megawatt MH agreement is estimated to be approximately $55 million.
There are no capacity payments for the diversity exchanges. These commitments to
MH represent about 17 percent of MH's system capability in 1998 and account for
approximately 10 percent of NSP's 1998 electric system capability. The
<PAGE>
risk of loss from nonperformance by MH is not considered significant, and the
risk of loss from market price changes is mitigated through cost-of-energy rate
adjustments.
The Company has an agreement with Minnkota Power Cooperative for the purchase of
summer season capacity and energy. From 1998 through 2001, the Company will buy
150 megawatts of summer season capacity for $12 million annually. From 2002
through 2015, the Company will purchase 100 megawatts of capacity for $10
million annually. Under the agreement, energy will be priced at the cost of fuel
consumed per megawatt-hour at the Coyote Generating Station in North Dakota. The
Company also has a seasonal (summer) purchase power agreement with Minnesota
Power for the purchase of 173 megawatts, including reserves, from 1998-2000.
The annual cost of this capacity will be approximately $2 million.
The Company has agreements with several nonregulated power producers to purchase
electric capacity and associated energy. The 1998 cost of these commitments for
nonregulated capacity is approximately $46 million for 360 megawatts of summer
capacity. This commitment is expected to remain at this level until 2012, at
which time it will decrease to approximately $39 million annually and then
gradually decrease to approximately $26 million in the year 2027 due to the
expiration of existing agreements.
NUCLEAR INSURANCE The Company's public liability for claims resulting from any
nuclear incident is limited to $8.9 billion under the 1988 Price-Anderson
amendment to the Atomic Energy Act of 1954. The Company has secured $200 million
of coverage for its public liability exposure with a pool of insurance
companies. The remaining $8.7 billion of exposure is funded by the Secondary
Financial Protection Program, available from assessments by the federal
government in case of a nuclear accident. The Company is subject to assessments
of up to $79 million for each of its three licensed reactors to be applied for
public liability arising from a nuclear incident at any licensed nuclear
facility in the United States. The maximum funding requirement is $10 million
per reactor during any one year.
The Company purchases insurance for property damage and site decontamination
cleanup costs with coverage limits of $1.5 billion for each of the Company's two
nuclear plant sites. The coverage consists of $500 million from Nuclear Mutual
Limited (NML) and $1.0 billion from Nuclear Electric Insurance Limited (NEIL).
NEIL also provides business interruption insurance coverage, including the cost
of replacement power obtained during certain prolonged accidental outages of
nuclear generating units. Premiums billed to NSP from NML and NEIL are expensed
over the policy term. All companies insured with NML and NEIL are subject to
retrospective premium adjustments if losses exceed accumulated reserve funds.
Capital has been accumulated in the reserve funds of NML and NEIL to the extent
that the Company would have no exposure for retrospective premium assessments in
case of a single incident under the business interruption and the property
damage insurance coverages. However, in each calendar year, the Company could be
subject to maximum assessments of approximately $4.6 million for business
interruption insurance (five times the amount of its annual premium) and $19.0
million for property damage insurance (generally five times the amount of its
annual premium) if losses exceed accumulated reserve funds.
ENVIRONMENTAL CONTINGENCIES Other long-term liabilities include an accrual of
$34 million, and other current liabilities include an accrual of $6 million at
Dec. 31, 1997, for estimated costs associated with environmental remediation.
Approximately $31 million of the long-term liability and $4 million of the
current liability relate to a DOE assessment for decommissioning a federal
uranium enrichment facility, as discussed in Note 13. Other estimates have been
recorded for expected environmental costs associated with manufactured gas plant
sites formerly used by the Company, and other waste disposal sites, as discussed
below.
These environmental liabilities do not include accruals recorded, and collected
from customers in rates, for future nuclear fuel disposal costs or
decommissioning costs related to the Company's nuclear generating plants. (See
Note 13 for further discussion.)
The Environmental Protection Agency (EPA) or state environmental agencies have
designated the Company as a "potentially responsible party" (PRP) for 15 waste
disposal sites to which the Company allegedly sent hazardous materials. Ten of
these 15 sites have been remediated and, consistent with settlements reached
with the EPA and other PRPs, the Company has paid $1.7 million for its share of
the remediation costs. While these remediated sites will continue to be
monitored, the Company expects that future remediation costs, if any, will be
immaterial. Under applicable law, the Company, along with each PRP, could be
held jointly and severally liable for the total remediation costs of PRP sites.
Of the five unremediated sites, the total remediation costs are currently
estimated to be approximately $11 million. If additional remediation is
necessary or unexpected costs are incurred, the amount
<PAGE>
could be higher. The Company is not aware of the other parties' inability to
pay, nor does it know if responsibility for any of the sites is in dispute. For
these five sites, neither the amount of remediation costs nor the final method
of their allocation among all designated PRPs has been determined. However, the
Company has recorded an estimate of approximately $750,000 for its share of
future costs for these five sites, including $700,000 that is expected to be
paid in 1998. While it is not feasible to determine the ultimate impact of PRP
site remediation at this time, the amounts accrued represent the best current
estimate of the Company's future liability. It is the Company's practice to
vigorously pursue and, if necessary, litigate with insurers to recover incurred
remediation costs whenever possible. Through litigation, the Company has
recovered a portion of the remediation costs paid to date. Management believes
remediation costs incurred, but not recovered, from insurance carriers or other
parties should be allowed recovery in future ratemaking. Until the Company is
identified as a PRP, it is not possible to predict the timing or amount of any
costs associated with sites, other than those discussed above.
The Wisconsin Company potentially may be involved in the cleanup and remediation
at four sites. Three sites are solid and hazardous waste landfill sites in Eau
Claire, Rice Lake and Amery, Wis. The Wisconsin Company contends that it did not
dispose of hazardous wastes in these landfills during the time period in
question. Because neither the amount of cleanup costs nor the final method of
their allocation among all designated PRPs has been determined, it is not
feasible to predict the outcome of these matters at this time. The Wisconsin
Department of Natural Resources (WDNR) named the Wisconsin Company as one of
three Responsible Parties for creosote and coal tar contamination at a fourth
site in Ashland, Wis. WDNR's consultant is preparing a remedial option study for
the entire Ashland site, which includes the Wisconsin Company's portion and two
other adjacent portions. Until this study is completed and more information is
known concerning the extent of the final remediation required by the WDNR, the
remediation method selected, the related costs, the various parties involved,
and the extent of the Wisconsin Company's responsibility, if any, for sharing
the costs, the ultimate cost to the Wisconsin Company and timing of any payments
related to the Ashland site are not determinable. At Dec. 31, 1997, the Company
had recorded an estimated liability of $880,000 for future remediation costs
associated with the Wisconsin Company-owned portion of the Ashland site. Through
Dec. 31, 1997, the Wisconsin Company has incurred approximately $646,000 in
actual expenditures to date. Based on a recent Public Service Commission of
Wisconsin decision to allow recovery of incremental costs incurred for this site
beginning in 1997, the Wisconsin Company has recorded a regulatory asset for the
accrued and actual expenditures related to the Ashland site. The ultimate
cleanup and remediation costs at the Eau Claire, Amery, Rice Lake and Ashland
sites and the extent of the Wisconsin Company's responsibility, if any, for
sharing such costs are not known at this time, but may be significant.
The Company also is continuing to investigate various properties, which it
presently or previously owned. The properties were formerly sites of gas
manufacturing, gas storage plants or gas pipelines. The purpose of this
investigation is to determine if waste materials are present, if they are an
environmental or health risk, if the Company has any responsibility for remedial
action and if recovery under the Company's insurance policies can contribute to
any remediation costs. The Company has already remediated one site, which
continues to be monitored. The Company has paid $2.5 million to remediate this
site and expects to incur in the future only immaterial monitoring costs related
to this remediated site. Another 14 gas sites remain under investigation, and
the Company is actively taking remedial action at four of the sites. In
addition, the Company has been notified that two other sites eventually will
require remediation, and a study was initiated in 1996 to determine the cost and
method of cleanup at these two sites, which began in 1997. As of Dec. 31, 1997,
the Company has paid $8.1 million for the six active sites and has recorded an
estimated liability of approximately $3.0 million for future costs, with payment
expected over the next 10 years. This estimate is based on prior experience and
includes investigation, remediation and litigation costs. As for the eight
inactive sites, no liability has been recorded for remediation or investigation
because the present land use at each of these sites does not warrant a response
action. While it is not feasible to determine at this time the ultimate costs of
gas site remediation, the amounts accrued represent the best current estimate of
the Company's future liability for any required cleanup or remedial actions at
these former gas operating sites. Environmental remediation costs may be
recovered from insurance carriers, third parties, or in future rates. The MPUC
allowed the Company to defer certain remediation costs of four active sites in
1994 and the Company requested, in its December 1997 gas rate case, recovery of
these accumulated costs. In January 1998, the MPUC allowed the recovery of these
gas site remediation costs in the interim gas rates that went into effect in
February 1998. Accordingly, the Company has recorded an environmental regulatory
asset for these costs (see Note 9). The Company may request recovery of costs to
remedy the other two active sites following the completion of preliminary
investigations.
The Clean Air Act, including the Amendments of 1990 (the Clean Air Act), calls
for reductions in emissions of sulfur dioxide and nitrogen oxides from electric
generating plants. These reductions, which will be phased in, began in 1995. The
majority of the rules implementing this complex legislation have been finalized.
NSP has invested significantly over the years to reduce sulfur dioxide emissions
at its plants. No additional capital
<PAGE>
expenditures are anticipated to comply with the sulfur dioxide emission limits
of the Clean Air Act. NSP is still evaluating how best to implement the nitrogen
oxides standards. The Company's capital expenditures include some costs for
ensuring compliance with the Clean Air Act's other emission requirements; other
expenditures may be necessary upon EPA's finalization of remaining rules.
Because NSP is still in the process of implementing some provisions of the Clean
Air Act, its total financial impact is unknown at this time. Capital
expenditures for opacity compliance are considered in the capital expenditure
commitments disclosed previously. The depreciation of these capital costs will
be subject to regulatory recovery in future rate proceedings.
Several of NSP's facilities have asbestos-containing material, which represents
a potential health hazard to people who come in contact with it. Governmental
regulations specify the timing and nature of disposal of asbestos-containing
materials. Under such requirements, asbestos not readily accessible to the
environment need not be removed until the facilities containing the material are
demolished. Although the ultimate cost and timing of asbestos removal is not yet
known, it is estimated that removal under current regulations would cost $45
million in 1997 dollars. Depending on the timing of asbestos removal, such costs
would be recorded as incurred as operating expenses for maintenance projects,
capital expenditures for construction projects, or removal costs for demolition
projects.
Environmental liabilities are subject to considerable uncertainties that affect
NSP's ability to estimate its share of the ultimate costs of remediation and
pollution control efforts. Such uncertainties involve the nature and extent of
site contamination, the extent of required cleanup efforts, varying costs of
alternative cleanup methods and pollution control technologies, changes in
environmental remediation and pollution control requirements, the potential
effect of technological improvements, the number and financial strength of other
potentially responsible parties at multi-party sites and the identification of
new environmental cleanup sites. NSP has recorded and/or disclosed its best
estimate of expected future environmental costs and obligations, as discussed
previously.
LEGAL CLAIMS In the normal course of business, NSP is a party to routine claims
and litigation arising from prior and current operations. NSP is actively
defending these matters and has recorded an estimate of the probable cost of
settlement or other disposition.
15. Segment Information
<TABLE>
<CAPTION>
Year Ended December 31
---------------------------------------
(Thousands of dollars) 1997 1996 1995
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Utility operating income before income taxes
Electric $456 489 $469 321 $444 687
Gas 50 122 58 133 48 340
- -----------------------------------------------------------------------------------------------
Total utility operating income before income taxes $506 611 $527 454 $493 027
===============================================================================================
Utility depreciation and amortization
Electric $299 226 $279 828 $266 231
Gas 26 654 26 604 23 953
- -----------------------------------------------------------------------------------------------
Total utility depreciation and amortization $325 880 $306 432 $290 184
===============================================================================================
Utility capital expenditures
Electric $305 292 $323 532 $317 750
Gas 71 386 42 225 37 215
Common 19 927 20 898 31 057
- -----------------------------------------------------------------------------------------------
Total utility capital expenditures $396 605 $386 655 $386 022
===============================================================================================
Identifiable utility assets
Electric $4 845 306 $4 735 330 $4 751 650
Gas 675 030 649 218 600 738
- -----------------------------------------------------------------------------------------------
Total identifiable utility assets $5 520 336 $5 384 548 $5 352 388
Other corporate assets * 1 623 730 1 252 352 876 197
- -----------------------------------------------------------------------------------------------
Total assets $7 144 066 $6 636 900 $6 228 585
===============================================================================================
</TABLE>
* Includes equity investments for nonregulated energy projects outside of the
United States of $517 million in 1997, $295 million in 1996 and $185 million
in 1995.
Note: The gas utility segment includes Viking.
<PAGE>
16. Summarized Quarterly Financial Data (Unaudited)
<TABLE>
<CAPTION>
Quarter Ended
- ------------------------------------------------------------------------------------------------------------------
(Thousands of dollars) March 31, 1997 June 30, 1997* Sept. 30,1997 Dec. 31, 1997*
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Utility operating revenues $742 496 $594 323 $697 443 699 484
Utility operating income 88 456 65 586 118 540 89 174
Net income 65 773 18 253 87 912 65 382
Earnings available for common stock 61 816 15 882 85 541 63 010
Earnings per average common share:
Basic $0.90 $0.23 $1.23 $0.85
Assuming dilution $0.90 $0.23 $1.23 $0.85
Dividends declared per common share $0.690 $0.705 $0.705 $0.705
Stock prices---high $49 1/8 $52 $52 15/16 $58 7/8
---low $45 1/2 $44 1/2 $48 $48 7/16
Quarter Ended
- ------------------------------------------------------------------------------------------------------------------
(Thousands of dollars) March 31, 1996 June 30, 1996 Sept. 30, 1996 Dec. 31, 1996
- ------------------------------------------------------------------------------------------------------------------
Utility operating revenues $718 709 $592 258 $633 258 $709 981
Utility operating income 89 277 70 801 105 456 100 510
Net income 67 210 43 382 84 239 79 708
Earnings available for common stock 64 149 40 321 81 178 76 646
Earnings per average common share:
Basic $0.94 $0.59 $1.18 $1.12
Assuming dilution $0.94 $0.59 $1.18 $1.11
Dividends declared per common share $0.675 $0.690 $0.690 $0.690
Stock prices---high $53 3/8 $49 5/8 $49 3/4 $49 1/8
---low $47 5/8 $45 1/2 $44 1/2 $45 1/2
</TABLE>
* 1997 results include two nonrecurring items: a $29 million pretax charge,
which reduced second quarter earnings by 25 cents per share, for the
write-off of merger costs; and a $9 million pretax charge, which reduced
fourth quarter earnings by 8 cents per share, for the write-down of an NRG
cogeneration project.
<PAGE>
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
================================================================================
During 1997 there were no disagreements with the Company's independent
public accountants on accounting procedures or accounting and financial
disclosures.
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
================================================================================
Information required under this Item with respect to directors is set
forth in the Registrant's 1998 Proxy Statement for its Annual Meeting of
Shareholders to be held April 22, 1998, on pages 2 through 10 under the caption
"Election of Directors," which is incorporated herein by reference. Information
with respect to Executive Officers is included under the caption "Executive
Officers" in Item 1 of this report, and is incorporated herein by reference.
ITEM 11 - EXECUTIVE COMPENSATION
================================================================================
Information required under this Item is set forth in the Registrant's
1998 Proxy Statement for its Annual Meeting of Shareholders to be held April 22,
1998, on pages 11 through 19 under the caption "Compensation of Executive
Officers," which is incorporated herein by reference.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
================================================================================
Information required under this item is set forth in the Registrant's
1998 Proxy Statement for its Annual Meeting of Shareholders to be held April 22,
1998, on page 10 under the caption "Share Ownership of Directors, Nominees and
Named Executive Officers," which is incorporated herein by reference.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
================================================================================
Information required under this Item is set forth in the Registrant's
1998 Proxy Statement for its Annual Meeting of Shareholders to be held April 22,
1998 on pages 3 through 7 under the captions "Class III - Nominees for Terms
expiring in 2001," "Class II Directors whose Terms expire in 2000," "Class I -
Directors whose Terms Expire in 1999," which is incorporated herein by
reference.
<PAGE>
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, 1997, 1996 and 1995. 50
Consolidated Statements of Income for the three years
ended Dec. 31, 1997. 51
Consolidated Statements of Cash Flows for the three years
ended Dec. 31, 1997 52
Consolidated Balance Sheets, Dec. 31, 1997 and 1996. 53
Consolidated Statements of Changes in Common Stockholders'
Equity for the three years ended Dec. 31, 1997. 54
Consolidated Statements of Capitalization, Dec. 31, 1997
and 1996. 55
Notes to Financial Statements. 57
(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
3.01* Restated Articles of Incorporation of the
Company and Amendments, effective as of April 2,
1992. (Exhibit 3.01 to Form 10-Q for the quarter
ended March 31, 1992, File No. 1-3034).
3.02 Bylaws of the Company as amended March 26, 1997
and ratified by the Company's shareholders on
June 25, 1997.
4.01* Trust Indenture, dated Feb. 1, 1937, from the
Company to Harris Trust and Savings Bank, as
Trustee. (Exhibit B-7 to File No. 2-5290).
4.02* Supplemental and Restated Trust Indenture, dated
May 1, 1988, from the Company to Harris Trust
and Savings Bank, as Trustee. (Exhibit 4.02 to
Form 10-K for the year 1988, File No. 1-3034).
Supplemental Indenture between the Company and
said Trustee, supplemental to Exhibit 4.01,
dated as follows:
4.03* 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).
4.10* Sept. 1, 1956 (Exhibit 2.09 to File No.
2-13463).
<PAGE>
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
================================================================================
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* Mar. 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).
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).
<PAGE>
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
================================================================================
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.
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 the
Wisconsin Company to Firstar Trust Company
(formerly First Wisconsin Trust Company), as
Trustee. (Exhibit 7.01 to File No. 2-6982).
Supplemental Indentures between the Wisconsin
Company and said Trustee, supplemental to
Exhibit 4.49 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 the Wisconsin Company 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 the Company and
Norwest Bank Minnesota, National Association, as
trustee. (Exhibit 4.02 to Form 8-K dated Jan.
28, 1997, File No. 001-03034).
4.66* Preferred Securities Guarantee Agreement, dated
as of Jan. 31, 1997, between the Company 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).
<PAGE>
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
================================================================================
4.68* Supplemental Indenture, dated as of Jan. 31,
1997, between the Company 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 the Company 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 the Company.
(Exhibit 4.14 to Form 8-K dated Jan 28, 1997,
File No. 001 - 03034).
10.01* Facilities Agreement, dated July 21, 1976,
between the Company and the Manitoba
Hydro-Electric Board relating to the
interconnection of the 500 Kv Line. (Exhibit
5.06I to File No. 2-54310).
10.02* Transactions Agreement, dated July 21, 1976,
between the Company and the Manitoba
Hydro-Electric Board relating to the
interconnection of the 500 Kv Line. (Exhibit
5.06J to File No. 2-54310).
10.03* Coordinating Agreement, dated July 21, 1976,
between the Company and the Manitoba
Hydro-Electric Board relating to the
interconnection of the 500 Kv Line. (Exhibit
5.06K to File No. 2-54310).
10.04* Ownership and Operating Agreement, dated March
11, 1982, between the Company, Southern
Minnesota Municipal Power Agency and United
Minnesota Municipal Power Agency concerning
Sherburne County Generating Unit No. 3. (Exhibit
10.01 to Form 10-Q for the quarter ended Sept.
30, 1994, File No. 1-3034).
10.05* Transmission Agreement, dated April 27, 1982,
and Supplement No. 1, dated July 20, 1982,
between the Company and Southern Minnesota
Municipal Power Agency. (Exhibit 10.02 to Form
10-Q for the quarter ended Sept. 30, 1994, File
No. 1-3034).
10.06* Power Agreement, dated June 14, 1984, between
the Company and the Manitoba Hydro-Electric
Board, extending the agreement scheduled to
terminate on April 30, 1993, to April 30, 2005.
(Exhibit 10.03 to Form 10-Q for the quarter
ended Sept. 30, 1994, File No. 1-3034).
10.07* Power Agreement, dated August 1988, between the
Company and Minnkota Power Company. (Exhibit
10.08 to Form 10-K for the year 1988, File No.
1-3034).
Executive Compensation Arrangements and Benefit Plans
-----------------------------------------------------
Covering Executive Officers and Directors
-----------------------------------------
10.08* Terms and Conditions of Employment - James J
Howard, President and Chief Executive Officer,
effective Feb. 1, 1987, as amended. (Agreement
filed as Exhibit 10.11 to Form 10-K for the year
1986, File No. 1-3034, Acknowledgement of
Amendment to Terms and Conditions of Employment
of James J. Howard filed as Exhibit 10.01 to
Form 10-Q for the quarter ended June 30, 1995,
File No. 1-3034).
10.09* NSP Severance Plan. (Exhibit 10.12 to Form 10-K
for the year 1994, File No. 1-3034).
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* Executive Long-Term Incentive Award Stock Plan.
(Exhibit 10.10 to Form 10-K for 1988, File No.
1-3034).
10.14* Annual Executive Incentive Plan for 1997.
(Exhibit 10.14 to Form 10-K for the year 1996,
File No. 1-3034).
10.15 Stock Equivalent Plan for Non-Employee Directors
of Northern States Power Company (As Amended and
Restated Effective Oct. 1, 1997).
<PAGE>
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
================================================================================
12.01 Statement of Computation of Ratio of Earnings to
Fixed Charges.
21.01 Subsidiaries of the Registrant.
23.01 Consent of Independent Accountants - Price
Waterhouse LLP, Minneapolis, MN.
99.01 Statement pursuant to Private Securities
Litigation Reform Act of 1995.
99.02 Description of Common Stock.
99.03* 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,
1997, File No. 333-33397).
27.01 Financial Data Schedule for 1997.
27.02 Restated Financial Data Schedule for 1996.
27.03 Restated Financial Data Schedule for 1995.
27.04 Restated Financial Data Schedule for the quarter
ended September 1997.
27.05 Restated Financial Data Schedule for the quarter
ended June 1997.
27.06 Restated Financial Data Schedule for the quarter
ended March 1997.
27.07 Restated Financial Data Schedule for the quarter
ended September 1996.
27.08 Restated Financial Data Schedule for the quarter
ended June 1996.
27.09 Restated Financial Data Schedule for the quarter
ended March 1996.
(b) Reports on Form 8-K. The following reports on Form 8-K were
filed either during the three months ended Dec. 31, 1997, or
between Dec. 31, 1997 and the date of this report.
Dec. 19, 1997 (Filed Dec. 19, 1997) - Item 5. Other Events. Re:
Disclosure of indication that fourth quarter 1997 earnings per
share will be below 1996 results.
Dec. 31, 1997 (Filed March 5, 1998) - Item 5. Other Events. Item
7. Financial Statements and Exhibits. Re: Disclosure of
agreement and plan of merger with Black Mountain Gas Company of
Cave Creek, Arizona.
March 4, 1998 (Filed March 4, 1998) - Item 5. Other Events. Item
7. Financial Statements and Exhibits. Re: Disclosure of the
Company's consolidated financial statements for the year ended
Dec. 31, 1997 and the related management's discussion and
analysis.
March 5, 1998 (Filed March 5, 1998) - Item 5. Other Events. Item
7. Financial Statements and Exhibits. Re: Disclosure of
announcement that the Company will redeem all 300,000 shares of
its Cumulative Preferred Stock Adjustable Rate Series A and all
650,000 shares of its Cumulative Preferred Stock Adjustable Rate
B on March 31, 1998.
March 11, 1998 (Filed March 16, 1998) Item 5. Other Events. Item
7. Financial Statements and Exhibits. Re: Disclosure of the
Company entering into two underwriting agreements and filing of
two prospectus supplements relating to $350,000,000, in
aggregate principal amount of the Company's First Mortgage
Bonds.
<PAGE>
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 25, 1998 /s/
------------------------------------------
E J MCINTYRE
Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report signed below by the following persons on behalf of the registrant
and in the capacities and on the date indicated.
<TABLE>
<CAPTION>
<S> <C>
/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 DALE L HAAKENSTAD
Director Director
/s/ /s/
- ------------------------------------------ ------------------------------------------
RICHARD M KOVACEVICH DOUGLAS W LEATHERDALE
Director Director
/s/ /s/
- ------------------------------------------ ------------------------------------------
MARGARET R PRESKA A PATRICIA SAMPSON
Director Director
</TABLE>
<PAGE>
EXHIBIT INDEX
-------------
Method of Exhibit
Filing No. Description
--- -----------
DT 3.02 Bylaws of the Company as amended March 26, 1997
and ratified by the Company's shareholders on
June 25, 1997.
DT 4.47 Supplemental Trust Indenture between the
Company and Harris Trust and Savings Bank,
as Trustee, dated April 1, 1997.
DT 10.15 Stock Equivalent Plan for Non-Employee Directors
of Northern States Power Company (As Amended and
Restated Effective Oct. 1, 1997).
DT 12.01 Statement of Computation of Ratio of Earnings to
Fixed Charges.
DT 21.01 Subsidiaries of the Registrant.
DT 23.01 Consent of Independent Accountants - Price
Waterhouse LLP, Minneapolis, MN.
DT 99.01 Statement pursuant to Private Securities
Litigation Reform Act of 1995.
DT 99.02 Description of Common Stock.
DT 27.01 Financial Data Schedule for 1997.
DT 27.02 Restated Financial Data Schedule for 1996.
DT 27.03 Restated Financial Data Schedule for 1995.
DT 27.04 Restated Financial Data Schedule for the quarter
ended September 1997.
DT 27.05 Restated Financial Data Schedule for the quarter
ended June 1997.
DT 27.06 Restated Financial Data Schedule for the quarter
ended March 1997.
DT 27.07 Restated Financial Data Schedule for the quarter
ended September 1996.
DT 27.08 Restated Financial Data Schedule for the quarter
ended June 1996.
DT 27.09 Restated Financial Data Schedule for the quarter
ended March 1996.
DT = Filed electronically with this direct transmission.
Exhibit 3.02
BYLAWS
OF
NORTHERN STATES POWER COMPANY
(A MINNESOTA CORPORATION)
(AS AMENDED AT A REGULAR MEETING OF THE BOARD OF DIRECTORS HELD ON MARCH 26,
1997 AND RATIFIED BY THE COMPANY'S SHAREHOLDERS ON JUNE 25, 1997)
ARTICLE 1.
NAME, REGISTERED OFFICE, AND CORPORATE SEAL
Section 1. The name of the Company is NORTHERN STATES POWER COMPANY.
Section 2. The location and post office address of its registered
office and principal place of business is 414 Nicollet Mall, Minneapolis,
Hennepin County, Minnesota.
Section 3. The Company may establish and maintain an office or offices
at such other places within or without the State of Minnesota as the Board of
Directors may from time to time determine.
Section 4. The corporate seal of the Company shall have inscribed
thereon the name of the Company and the words "Corporate Seal, Minnesota". In
lieu of causing the corporate seal to be impressed upon any bond, debenture,
note, contract, or other instrument required or authorized to bear the corporate
seal of the Company, the Board of Directors may authorize a facsimile of said
seal to be engraved or printed thereon, and such facsimile, when so engraved or
printed, shall be and constitute the
<PAGE>
corporate seal of the Company for such purpose.
ARTICLE 2.
BOARD OF DIRECTORS
Section 1. The business and property of the Company shall be managed
and controlled by a Board composed of seven (7) directors, which may be
increased to such greater number, not exceeding fifteen (15), as may be
determined by the Board of Directors or by shareholders in accordance with the
provisions of this Article. The number of directors shall be determined by the
Board of Directors, and if the Board fails to make such determination, then the
number may be determined by the shareholders at any annual or special meeting of
shareholders.
Section 2. A director shall hold office until the next annual meeting
of the shareholders and until his successor is elected and qualifies. At the
annual meeting of shareholders in 1974, the Board of Directors of the Company
shall be divided into three classes as nearly equal in number as possible, with
the term of office of one class expiring each year. Directors in Class I shall
be elected to hold office until the next succeeding annual meeting; directors in
Class II shall be elected to hold office until the second succeeding annual
meeting; and directors in Class III shall be elected to hold office until the
third succeeding annual meeting, and, in each of the foregoing cases, until
their respective successors are duly elected and qualify. At each subsequent
annual meeting of shareholders, the successors to the class of directors whose
term shall then expire shall be elected by the shareholders to hold office until
the third succeeding annual meeting, and until their respective successors are
duly elected and qualify. If, at
<PAGE>
any meeting of shareholders, commencing with the annual meeting of shareholders
in 1974, due to the initiation of the classified method of electing directors or
due to a vacancy or vacancies on the Board of Directors, or otherwise, directors
of more than one class are to be elected, each class of directors to be elected
at the meeting shall be nominated and voted for in a separate election.
Section 3. During the intervals between annual meetings the number of
directors may be increased, and may be decreased by the number of vacancies then
existing, by the Board of Directors, within the limitations of Section 1 of this
Article, and in case of any such increase the Board may fill the vacancies so
created but in such event there shall be no classification of the additional
directors until the next annual meeting of the shareholders. No decrease in the
Board shall shorten the term of any incumbent director.
Section 4. Vacancies in the Board of Directors may be filled by the
remaining members of the Board though less than a quorum. Each person so elected
to fill a vacancy shall remain a director for the unexpired term in respect of
which such vacancy occurred and until his successor is elected and qualifies.
Section 5. In addition to the powers and authority expressly conferred
upon them by these Bylaws, the Board of Directors may exercise all such powers
and do all such acts and things as may be exercised or done by the Company, but
subject, nevertheless, to the provisions of statute, the Articles of
Incorporation, and these Bylaws.
Section 6. Without limiting the general powers conferred by Section 5
of this Article, and other powers conferred by statute, by the Articles of
Incorporation, and
<PAGE>
by these Bylaws, it is hereby expressly declared that the Board of Directors
shall have the following powers, that is to say:
(a) To purchase or otherwise acquire for the Company any property,
rights, or privileges which the Company is authorized to acquire, for such
consideration and on such terms and conditions as it deems proper.
(b) At its discretion to pay for any property or rights acquired by the
Company either wholly or partly in money or in stock, bonds, debentures, or
other securities or property of the Company.
(c) To appoint any person or persons to accept and hold in trust for
the Company any property belonging to the Company, or in which it is interested,
and to do and execute all such things as may be requisite in relation to any
such trust.
(d) To in any manner aid, facilitate, and assist, in behalf of the
Company, in the construction, extension, improvement, equipment, maintenance,
and operation of any electric light plant or distribution system, electric
transmission or distribution lines, steam plant for heating and power or
distribution system, natural, manufactured, mixed, or liquid petroleum gas plant
or distribution system, gas or oil pipe lines, barge lines, coal mines, water
power or water plants, or telephone systems, and all property and things
appurtenant to or used in connection therewith, and for that purpose to use the
cash or capital stock or other securities or obligations of the Company to buy,
refund, guarantee, or otherwise secure the indebtedness against any such
properties and guarantee the bonds, debentures, indebtedness, dividends,
contracts, or other obligations of firms or other corporations.
(e) To authorize one or more officers, on behalf of the Company, to
borrow money, make and issue notes, bonds, and other evidences or indebtedness,
<PAGE>
execute mortgages, deeds of trust, trust agreements, and instruments of pledge
or hypothecation, and do all other acts necessary to effectuate the same.
(f) To designate the persons authorized, on the Company's behalf, to
make and sign notes, receipts, acceptances, endorsements, drafts, checks, or
other orders for the payment of money, releases, contracts, and other
instruments, and, when appropriate, to make provision for the use of facsimile
signatures thereon.
(g) To designate the persons authorized, on the Company's behalf, to
vote upon or to assign and transfer any shares of stock, bonds, or Zother
securities of other corporations held by the Company.
Section 7. Meetings of the Board of Directors shall be held at the
registered office of the Company, but the chairman of the Board, the President,
or a majority of the Board may from time to time designate some other place
within or without the State of Minnesota for the holding of any such meeting or
meetings.
Section 8. Regular meetings of the Board of Directors may be held,
without notice, at such times as shall be determined from time to time by
resolution of the Board.
Section 9. Special meetings of the Board of Directors shall be held
whenever called by the Chairman of the Board, by the President, or by a majority
of the Board.
Section 10. The Secretary shall give notice of a special meeting of the
Board of Directors to each director, either by mail or by telegraph, at least
two days before said meeting. Any director may in writing, either before or
after the meeting, waive notice thereof; and, without notice, any director by
his attendance at any meeting shall be deemed to have waived notice.
<PAGE>
Section 11. Unless otherwise indicated in the notice thereof, any and
all business may be transacted at a special meeting.
Section 12. At the first regular meeting following the annual meeting
of the shareholders, the Board of Directors shall elect the officers of the
Company, who shall hold office for one year and until their successors are
elected. Any office not filled at such meeting may be filled at any subsequent
meeting of the Board.
Section 13. A majority of the Board of Directors shall constitute a
quorum for the transaction of business, and the acts of a majority of the
directors present at a meeting at which a quorum is present shall be the acts of
the Board of Directors, except as may be otherwise specifically provided by
statute, by the Articles of Incorporation, or by these Bylaws. At any meeting at
which there is less than a quorum present, the director or directors present
shall have power by a majority vote to adjourn the meeting from time to time
without notice other than announcement at the meeting. At any adjourned meeting
at which a quorum is present any business may be transacted which might have
been transacted by a quorum of the directors at the meeting as originally
convened.
Section 14. Any action which might be taken at a meeting of the Board
of Directors may be taken without a meeting if done in writing signed by all of
the directors.
Section 15. Inasmuch as the directors of the Company are men of large
and diversified business interests and are likely to be connected with other
corporations with which this Company may have business dealings from time to
time, no contract or other transaction between this Company and any other
corporation shall be affected by the fact that directors of this Company are
interested in, or are directors or officers of,
<PAGE>
such other corporation, and any director individually may be a party to or may
be interested in any contract or transaction of this Company, provided that any
such contract or transaction referred to in this section shall be approved or be
ratified by the affirmative vote of a majority of the members of the Board not
so interested.
Section 16. The Board of Directors may provide for the payment to each
director of a fixed annual fee, a fixed fee for attendance at each meeting of
the Board or of any committee thereof, or a combination of the foregoing fees,
and the expenses of each director for attendance at each meeting of the Board or
of any committee thereof; provided, however, that no part of any such fee shall
be paid to any director during any year when there is in effect a prior written
request from such director that all or a portion of said fees not be paid to
him. Nothing herein shall be construed to preclude any director from serving the
Company in any other capacity as an officer or otherwise and receiving
compensation therefor.
ARTICLE 3.
OFFICERS
Section 1. (a) The officers of the Company shall be a Chairman of the
Board, a President, one or more Vice Presidents any of whom may have such
additional designation as the Board of Directors may provide, a Secretary and
one or more Assistant Secretaries, a Treasurer and one or more Assistant
Treasurers, and such other officers as may from time to time be elected or
appointed by the Board of Directors. The filling of the office of Chairman of
the Board shall be discretionary with the Board of Directors. Any two of the
offices, except those of President and Vice President, may be held by the same
person.
<PAGE>
(b) At its discretion, the Board of Directors at any time, be
resolution, may recognize the outstanding services of an individual to the
Company by conferring upon him the honorary title of "Honorary Chairman of the
Board", such title to be held for such limited period of time, or for life, as
may be determined by the Board. Except when used in Article 4 of these Bylaws,
the words "director", "directors", "Board of Directors", "members of the Board",
"Board", "officer", and "officers", wherever used in the Articles of
Incorporation or in these Bylaws, shall not be construed to mean or to include
the Honorary Chairman of the Board.
(c) At its discretion, the Board of Directors at any time, by
resolution, may recognize the outstanding services of an individual who has
served as Chairman of the Board of the Company by conferring upon him the
honorary title of "Chairman Emeritus", such title to be held for such limited
period of time, or for life, as may be determined by the Board. The action of
the Board of Directors in conferring the honorary title of "Chairman Emeritus"
upon such individual shall not constitute such individual an officer of the
Company and shall not otherwise affect the status of such individual as a member
of the Board.
(d) The Board of Directors shall designate the Chief Executive Officer
of the Company who shall have general active management of the business of the
Company.
Section 2. The Chairman of the Board shall preside at all meetings of
the shareholders and the Board of Directors, shall be ex officio member of all
standing committees and shall have such other powers and perform such other
duties as may be prescribed by the Board.
Section 3. The President, in the absence of the Chairman of the Board,
<PAGE>
shall preside at all meetings of the shareholders and the Board of Directors and
shall be an ex officio member of all standing committees. The President shall
have general supervision and direction of the affairs of the Company and shall
have all the powers and duties appurtenant to the office of President of a
corporation. The President shall report to the Board all matters within his or
her knowledge which the interests of the Company may require to be brought to
their notice; shall make such other reports to the shareholders and the Board as
may be required; and shall perform all such duties as are properly required by
the Board.
Section 4. The Vice Presidents shall be vested with all the powers and
shall perform all the duties of the President in the order designated by the
President in case of his absence and in the order designated by the President or
by the Board of Directors in case of his disability, and shall have such other
powers and perform such other duties as may be prescribed by the President or by
the Board.
Section 5. The Secretary shall give, or cause to be given, all notices
required by statute, by the Articles of Incorporation, or by these Bylaws. He
shall act as secretary of all the meetings of the shareholders and of the Board
of Directors and shall record the proceedings of all such meetings in the book
or books kept for that purpose. Unless otherwise prescribed by the Chief
Executive Officer of the Company, he shall keep, or cause to be kept, a record
of all certificates of stock issued and all transfers thereof, which shall show
the names and addresses of the holders of such certificates and dates of
issuance and transfer, and shall perform such other duties as may be prescribed
by the Chief Executive Officer or by the Board.
Section 6. The Assistant Secretaries shall be vested with all the
powers
<PAGE>
and shall perform all the duties of the Secretary in the absence or disability
of the latter, and shall perform such other duties as may be prescribed by the
President or by the Board of Directors.
Section 7. (a) The Controller, unless otherwise provided by the Board
of Directors, shall be the principal accounting officer of the Company. He shall
have executive direction of all accounting functions, and shall keep, or cause
to be kept, appropriate and complete books of account, and shall render to the
President and to the Board of Directors such reports as may be required from
time to time. He shall have such other powers and duties as are commonly
incidental to the office of controller and as may be prescribed for him by the
Board of Directors or the President.
(b) The Treasurer shall have the care and custody of the Company's
funds, securities, evidences of indebtedness, and other valuable financial
documents and shall deposit, or cause to be deposited, all moneys and other
valuable effects in the name of and to the credit of the Company in such
depositories as shall be designated by the Board of Directors. He shall have the
power to endorse for deposit all checks, notes, and drafts payable to the
Company. He shall disburse the funds of the Company when authorized by proper
vouchers for such disbursements. He shall have such other powers and duties as
are commonly incidental to the officer of Treasurer and as may be prescribed for
him by the Board of Directors, the President, or such other officer as may be
directed by the President.
Section 8. The Assistant Treasurers shall be vested with all the powers
and shall perform all the duties of the Treasurer in the absence or disability
of the latter, and shall perform such other duties as may be prescribed by the
President or by the Board of Directors.
<PAGE>
Section 9. In case of the absence or disability of any officer of the
Company, or for any other reason deemed sufficient by it, the Board of Directors
may delegate the powers and duties of such officer to any other officer or to
any director for the time being.
Section 10. A bond in such sum, in such form, and with such security,
surety or sureties, as may be satisfactory to the Board of Directors, may be
required by the Board from the Treasurer, and such other officers, employees,
and agents of the Company as the Board may specify, conditioned on the faithful
performance of the duties of their office, and for the restoration to the
Company, when demanded, of all books, papers, vouchers, money, securities, and
property of whatever kind in their possession belonging to the Company. All
premiums on such bonds shall be paid by the Company.
Section 11. The salaries of all officers shall be fixed by the Board of
Directors.
Section 12. The officers shall hold office for one year and until their
successors are elected and qualify. Any officer may be removed by the Board of
Directors with or without cause.
Section 13. A vacancy in any office may be filled by the Board of
Directors for the unexpired term in respect of which the vacancy occurred.
ARTICLE 4.
INDEMNIFICATION OF DIRECTORS,
OFFICERS, EMPLOYEES, AND AGENTS
Section 1. The Company shall indemnify any person made or threatened to
be made a party to a proceeding by reason of the former or present official
capacity
<PAGE>
of the person acting for the Company or acting in an official capacity with
another entity at the direction or request of the Company, according to the
terms and under the procedures provided in Minnesota Statutes Sec. 302A.521.
Section 2. The indemnification provided by this Article shall inure to
the benefit of the heirs, executors, administrators and personal representatives
of any person acting in an official capacity for the Company.
Section 3. The Company may purchase and maintain insurance on behalf of
a person in that person's official capacity against any liability asserted
against and incurred by the person in or arising from that capacity, whether or
not the Company would be required by law to indemnify the person against the
liability.
ARTICLE 5.
ISSUANCE AND TRANSFER
OF CERTIFICATES OF SHARES
Section 1. Every certificate of shares shall be numbered and shall be
entered on the books of the Company as it is issued. It shall be signed by the
Chairman of the Board, President or a Vice President and by the Secretary or an
Assistant Secretary and shall bear the corporate seal, but when a certificate is
signed by a transfer agent or registrar the signature of any such officer and
the corporate seal upon such certificate may be facsimiles, engraved or printed.
Section 2. Transfers of shares shall be made on the books of the
Company only by the person named in the certificate, or by his attorney lawfully
constituted in writing, and upon surrender of such certificate.
Section 3. In case of the loss, destruction, or theft of a certificate
of shares, a new certificate may be issued in its place upon the submission of
satisfactory
<PAGE>
proof of such loss, destruction, or theft and a bond of indemnity satisfactory
to the Treasurer.
Section 4. The Company shall be entitled to treat the holder of record
of any share or shares as the holder in fact thereof and shall not be bound to
recognize any equitable or other claim to or interest in such share on the part
of any other person whether or not it shall have express or other notice
thereof, save as expressly provided by statute.
Section 5. The Board of Directors shall have authority to appoint one
or more registrars or transfer agents for any or all classes of shares of the
Company, to make such rules and regulations as it may deem expedient concerning
the issuance, registration, and transfer of such shares, and to remove such
registrars or transfer agents, or any of them, and appoint another or others in
its or their stead. A certificate of shares of any class for which one or more
registrars or transfer agents shall have been so appointed shall not be valid
until countersigned by a registrar or a transfer agent, or both, as the case may
be.
ARTICLE 6.
SHAREHOLDERS
Section 1. The annual and special meetings of shareholders
shall be held at the registered office of the Company, but the Board of
Directors may designate some other place within or without the State of
Minnesota for the holding of any such meeting or meetings. Written notice of
each meeting of shareholders, stating the time and place, and, in case of a
special meeting, the purpose, shall be given by the Secretary to each
shareholder entitled to vote at such meeting, not less than ten days prior to
the
<PAGE>
date of such meeting.
Section 2. The Chairman of the Board shall preside at all meetings of
the shareholders, and in his absence or disability or at his request the
President shall preside, and in the absence or disability of both said officers
a Vice President shall preside.
Section 3. The Board of Directors may, within the limitations of the
statute, fix a record date for the determination of shareholders entitled to
receive notice of and to vote at any meeting of shareholders, and a record date
for the determination of shareholders entitled to receive payments of any
dividend or distribution or allotment of rights or to exercise rights with
respect to any change, conversion, or exchange of shares, and may close the
books of the Company against the transfer of shares during the whole or any part
of the period so fixed.
Section 4. The annual meeting of shareholders shall be held on the date
and time and at the location designated by the Board of Directors.
Section 5. Special meetings of the shareholders may be called and held
as provided by Minnesota Statutes.
Section 6. The holders of a majority of the voting power of the shares
issued and outstanding and entitled to vote, present in person or by proxy,
shall constitute a quorum at all meetings of shareholders for the transaction of
business, except as otherwise provided by statute, by the Articles of
Incorporation, or by these Bylaws. In the absence of a quorum,
any meeting may be adjourned from time to time. The shareholders present at a
duly called or held meeting at which a quorum is present may continue to
transact business until adjournment, notwithstanding the withdrawal of enough
shareholders to leave less than a quorum.
<PAGE>
Section 7. At each meeting of shareholders every shareholder of record,
or his legal representatives, at the date fixed by the Board of Directors for
the determination of the persons entitled to vote at a meeting of shareholders,
or, if no date has been so fixed, then at the close of the thirtieth day
preceding the date of the meeting, shall be entitled at such meeting to one vote
for each share standing in his name on the books of the Company and such
additional votes for such share as may be provided for by the Articles of
Incorporation. A shareholder may cast his vote in person or by proxy. The
appointment of a proxy shall be in writing filed with the Secretary at or before
the meeting. The vote for directors, and, upon the demand of any shareholder,
the vote upon any question before the meeting, shall be by ballot. All elections
shall be had and all questions decided by a plurality vote.
Section 8. In advance of any meeting of shareholders, the Chairman of
the Board shall appoint three or more inspectors of election, who need not be
shareholders, as to the matters to be submitted to a vote at any such meeting,
or any adjournment thereof. The inspectors of election when so appointed shall
take charge of all proxies and ballots and shall determine the number of shares
outstanding, the voting power of each, the shares represented at the meeting,
and the existence of a quorum. They shall determine all questions relating to
the qualifications of voters, the authenticity, validity, and effect of proxies,
and the acceptance or rejection of votes, challenges, and questions arising in
any way in connection with the right to vote and the counting and tabulation of
such votes. They shall determine the number of votes cast for any office or for
or against any proposal, and shall determine and report the results to the
meeting. The inspectors shall take an oath that they will perform their duties
<PAGE>
impartially, in good faith, and to the best of their ability and as
expeditiously as is practical. If, for any reason, an inspector previously
appointed shall fail to attend or refuse or be unable to serve, the vacancy
shall be filled by the Chairman of the Board in advance of convening the
meeting, or at the meeting by the person acting as Chairman. Each report of the
inspectors shall be in writing and signed by the inspectors. The report of a
majority shall be the report of the inspectors.
Section 9. (a) At any annual meeting or any special meeting of
shareholders, only such business shall be conducted, and only such proposals
shall be acted upon as shall have been brought before the meeting (i) by, or at
the direction of, the Board of Directors, or (ii) by any shareholder of the
Company who complies with the requirements of Rule 14a-8 under the Securities
Exchange Act of 1934, as amended, or (iii) by any shareholder of the Company who
complies with the notice procedures set forth in this Section 9.
(b) For a proposal to be properly brought before an annual or special
meeting by a shareholder, the shareholder must have given timely notice thereof
in writing to the Secretary of the Company. To be timely, a shareholder's notice
must be delivered to, or mailed and received at, the principal executive offices
of the Company not less than twenty (20) days nor more than ninety (90) days
prior to the scheduled meeting, regardless of any postponements, deferrals or
adjournments of that meeting to a later date; provided, however, that if less
than thirty (30) days' notice or prior public disclosure of the date of the
scheduled meeting is given or made, notice by the shareholder, to be timely,
must be so delivered or received not later than the close of business on the
tenth (10th) day following the earlier of the day on which such notice of the
date of the scheduled meeting was mailed or the day on which such public
<PAGE>
disclosure was made.
(c) A shareholder's notice to the Secretary shall set forth as to each
matter the shareholder proposes to bring before the meeting (i) a brief
description of the proposal desired to be brought before the meeting and the
reasons for conducting such business at the meeting, (ii) the name and address,
as they appear on the Company's books, of the shareholder proposing such
business and any other shareholder known by such shareholder to be supporting
such proposal who is the record or beneficial owner (as such term is defined in
Rule 13d-3 or 13d-5 under the Securities Exchange Act of 1934, as amended) of
any equity security of the Company, (iii) the class and number of shares of the
Company's equity securities which are beneficially owned (as defined above) and
owned of record by the shareholder giving the notice on the date of such
shareholder notice and by any other record or beneficial owners of the Company's
equity securities known by such shareholder to be supporting such proposal on
the date of such shareholder notice, and (iv) any financial or other interest of
the shareholder in such proposal.
(d) The Chairman of the Board may reject any shareholder proposal not
timely made in accordance with the terms of this Section 9. If the Chairman of
the Board determines that the information provided in a shareholder's notice
does not satisfy the informational requirements of this Section 9 in any
material respect, the Secretary of the Company shall promptly notify such
shareholder of the deficiency in the notice. The shareholder shall have an
opportunity to cure the deficiency by providing additional information to the
Secretary within such period of time, not to exceed five (5) days from the date
such deficiency notice is given to the shareholder, as the Chairman of the Board
shall reasonably determine. If the deficiency is not cured
<PAGE>
within such period, or if the Chairman of the Board determines that the
additional information provided by the shareholder, together with the
information previously provided, does not satisfy the requirements of this
Section 9 in any material respect, then the Chairman of the Board may reject
such shareholder's proposal. The Secretary of the Company shall notify a
shareholder in writing whether such person's proposal has been made in
accordance with the time and information requirements of this Section 9.
Notwithstanding the procedures set forth in this paragraph, if the Chairman of
the Board does not make a determination as to the validity of any shareholder
proposal under Section 9(c), the chairman of the annual or special meeting of
shareholders shall determine and declare at the meeting whether the shareholder
proposal was made in accordance with the terms of Section 9. If the chairman of
such meeting determines that a shareholder proposal was not made in accordance
with the terms of this Section 9, he or she shall so declare at the meeting and
any such proposal shall not be acted upon at the meeting.
(e) This provision shall not prevent the consideration and approval or
disapproval at any meeting of reports of officers, directors and committees of
the Board of Directors, but, in connection with such reports, no new business
shall be acted upon at such meeting unless stated, filed and received as herein
provided.
ARTICLE 7.
FISCAL YEAR
Section 1. The fiscal year of the Company shall begin on the first day
of
<PAGE>
January and terminate on the last day of December in each year.
ARTICLE 8.
INTERPRETATION
Section 1. In these Bylaws, unless there shall be something in the
subject or context inconsistent therewith:
(a) "Notice" means a notice in writing given by mail to any director,
officer, or shareholder by depositing the same in the United States mail, with
postage prepaid, and addressed to such director, officer, or shareholder at his
address as the same appears on the books of the Company; and the time of mailing
shall be deemed to be the time of the giving of the notice.
(b) "Qualify" means filing with the Secretary a written acceptance, or
entering upon the duties, of an office.
(c) "Statute" means any applicable statute of the State of Minnesota.
(d) The specification in these Bylaws of rights, powers, duties, and
procedures shall not be deemed to exclude other applicable rights, powers,
duties, and procedures provided for by statute or by the Articles of
Incorporation which are not incorporated herein and which are not inconsistent
with these Bylaws.
(e) Words importing the singular number include the plural and vice
versa. Words importing males include females, and words importing natural
persons include corporations.
ARTICLE 9.
<PAGE>
AMENDMENTS
Section 1. These Bylaws may be amended by the shareholders or by the
Board of Directors as provided by the Articles of Incorporation.
* * * * * * * * * *
Exhibit 4.47
SUPPLEMENTAL TRUST INDENTURE
FROM
NORTHERN STATES POWER COMPANY
TO
HARRIS TRUST AND SAVINGS BANK
TRUSTEE
-------
DATED APRIL 1, 1997
-------
SUPPLEMENTAL TO TRUST INDENTURE
DATED FEBRUARY 1, 1937
AND
SUPPLEMENTAL AND RESTATED
TRUST INDENTURE
DATED MAY 1, 1988
<PAGE>
TABLE OF CONTENTS
-------
<TABLE>
<CAPTION>
<S> <C>
Parties............................................................................................................ 1
Recitals........................................................................................................... 1
Form of Bonds of Pollution Control Series M, N, O and P............................................................ 5
Form of Trustee's Certificate...................................................................................... 8
Further Recitals................................................................................................... 8
ARTICLE I SPECIFIC SUBJECTION OF ADDITIONAL PROPERTY TO THE LIEN OF THE ORIGINAL INDENTURE.................. 8
Section 1.01 Grant of certain property, including personal property to comply with the Uniform Commercial
Code, subject to permitted liens and other exceptions contained in 1937 Indenture................. 8
ARTICLE II PROVISIONS OF BONDS OF POLLUTION CONTROL SERIES M, N, O AND P..................................... 9
Section 2.01 Terms of Bonds of Pollution Control Series M...................................................... 9
Section 2.02 Payment of principal and interest of Bonds of Pollution Control Series M.......................... 10
Section 2.03 Bonds of Pollution Control Series M deemed fully paid upon payment of Series 1989-A Pollution
Control Revenue Bonds............................................................................. 11
Section 2.04 Terms of Bonds of Pollution Control Series N...................................................... 11
Section 2.05 Payment of principal and interest of Bonds of Pollution Control Series N.......................... 11
Section 2.06 Bonds of Pollution Control Series N deemed fully paid upon payment of Series 1992-A Pollution
Control Revenue Bonds............................................................................. 12
Section 2.07 Terms of Bonds of Pollution Control Series O...................................................... 13
Section 2.08 Payment of principal and interest of Bonds of Pollution Control Series O.......................... 13
Section 2.09 Bonds of Pollution Control Series O deemed fully paid upon payment of Series 1993-A Pollution
Control Revenue Bonds............................................................................. 14
Section 2.10 Terms of Bonds of Pollution Control Series P...................................................... 14
Section 2.11 Payment of principal and interest of Bonds of Pollution Control Series P.......................... 14
Section 2.12 Bonds deemed fully paid upon payment of Series 1993-B Pollution Control Revenue Bonds............. 15
Section 2.13 Interchangeability of bonds....................................................................... 16
Section 2.14 Charges upon exchange or transfer of bonds........................................................ 16
ARTICLE III FINANCING STATEMENT TO COMPLY WITH THE UNIFORM COMMERCIAL CODE.................................... 17
Section 3.01 Names and addresses of debtor and secured party................................................... 17
Section 3.02 Property subject to lien.......................................................................... 17
Section 3.03 Maturity dates and principal amounts of obligations secured....................................... 17
Section 3.04 Financing Statement adopted for all First Mortgage Bonds listed in Section 3.03................... 17
Section 3.05 Recording data for the 1937 Indenture and prior Supplemental Trust Indentures..................... 17
Section 3.06 Financing Statement covers additional series of First Mortgage Bonds.............................. 18
<PAGE>
ARTICLE IV AMENDMENTS TO INDENTURE........................................................................... 19
Section 4.01 Consent of holders of Bonds....................................................................... 19
ARTICLE V MISCELLANEOUS..................................................................................... 19
Section 5.01 Recitals of fact, except as stated, are statements of the Company................................. 19
Section 5.02 Supplemental Trust Indenture to be construed as a part of the 1937 Indenture, as supplemented..... 19
Section 5.03(a) Trust Indenture Act to control.................................................................... 19
(b) Severability of conditions contained in Supplemental Trust Indenture and bonds.................... 19
Section 5.04 Word "Indenture" as used herein includes in its meaning the 1937 Indenture and all indentures
supplemental thereto.............................................................................. 19
Section 5.05 References to either party in Supplemental Trust Indenture include successors or assigns.......... 19
Section 5.06(a) Provision for execution in counterparts........................................................... 20
(b) Table of Contents and descriptive headings of Articles not to affect meaning...................... 20
Schedule A......................................................................................................... A-1
</TABLE>
<PAGE>
SUPPLEMENTAL TRUST INDENTURE, MADE AS OF THE 1ST DAY OF APRIL, 1997, BY
AND BETWEEN NORTHERN STATES POWER COMPANY, a corporation duly organized and
existing under and by virtue of the laws of the State of Minnesota, having its
principal office in the City of Minneapolis, Minnesota (the "Company"), party of
the first part, and HARRIS TRUST AND SAVINGS BANK, a corporation duly organized
and existing under and by virtue of the laws of the State of Illinois, having
its principal office in the City of Chicago, Illinois, as Trustee (the
"Trustee"), party of the second part;
WITNESSETH:
WHEREAS, the Company has heretofore executed and delivered to the
Trustee its Trust Indenture (the "1937 Indenture"), made as of February 1, 1937,
whereby the Company granted, bargained, sold, warranted, released, conveyed,
assigned, transferred, mortgaged, pledged, set over and confirmed to the Trustee
and to its respective successors in trust, all property, real, personal and
mixed then owned or thereafter acquired or to be acquired by the Company (except
as therein excepted from the lien thereof) and subject to the rights reserved by
the Company in and by the provisions of the 1937 Indenture, to be held by said
Trustee in trust in accordance with the provisions of the 1937 Indenture for the
equal pro rata benefit and security of all and each of the bonds issued and to
be issued thereunder in accordance with the provisions thereof; and
WHEREAS, the Company heretofore has executed and delivered to the
Trustee a Supplemental Trust Indenture, made as of June 1, 1942, whereby the
Company conveyed, assigned, transferred, mortgaged, pledged, set over, and
confirmed to the Trustee, and its respective successors in said trust,
additional property acquired by it subsequent to the date of the 1937 Indenture;
and
WHEREAS, the Company heretofore has executed and delivered to the
Trustee the following additional Supplemental Trust Indentures which, in
addition to conveying, assigning, transferring, mortgaging, pledging, setting
over, and confirming to the Trustee, and its respective successors in said
trust, additional property acquired by it subsequent to the preparation of the
next preceding Supplemental Trust Indenture and adding to the covenants,
conditions, and agreements of the 1937 Indenture certain additional covenants,
conditions, and agreements to be observed by the Company, created the following
series of First Mortgage Bonds:
DATE OF SUPPLEMENTAL
TRUST INDENTURE DESIGNATION OF SERIES
- -------------------- ---------------------
February 1, 1944 Series due February 1, 1974 (retired)
October 1, 1945 Series due October 1, 1975 (retired)
July 1, 1948 Series due July 1, 1978 (retired)
August 1, 1949 Series due August 1, 1979 (retired)
June 1, 1952 Series due June 1, 1982 (retired)
October 1, 1954 Series due October 1, 1984 (retired)
September 1, 1956 Series due 1986 (retired)
August 1, 1957 Series due August 1, 1987 (redeemed)
July 1, 1958 Series due July 1, 1988 (retired)
December 1, 1960 Series due December 1, 1990 (retired)
August 1, 1961 Series due August 1, 1991 (retired)
June 1, 1962 Series due June 1, 1992 (retired)
September 1, 1963 Series due September 1, 1993 (retired)
August 1, 1966 Series due August 1, 1996 (redeemed)
June 1, 1967 Series due June 1, 1995 (redeemed)
October 1, 1967 Series due October 1, 1997 (redeemed)
May 1, 1968 Series due May 1, 1998 (redeemed)
October 1, 1969 Series due October 1, 1999 (redeemed)
February 1, 1971 Series due March 1, 2001 (redeemed)
May 1, 1971 Series due June 1, 2001 (redeemed)
February 1, 1972 Series due March 1, 2002
January 1, 1973 Series due February 1, 2003
<PAGE>
DATE OF SUPPLEMENTAL
TRUST INDENTURE DESIGNATION OF SERIES
- -------------------- ---------------------
January 1, 1974 Series due January 1, 2004 (redeemed)
September 1, 1974 Pollution Control Series A (redeemed)
April 1, 1975 Pollution Control Series B (redeemed)
May 1, 1975 Series due May 1, 2005 (redeemed)
March 1, 1976 Pollution Control Series C (retired)
June 1, 1981 Pollution Control Series D, E and F (redeemed)
December 1, 1981 Series due December 1, 2011 (redeemed)
May 1, 1983 Series due May 1, 2013 (redeemed)
December 1, 1983 Pollution Control Series G (redeemed)
September 1, 1984 Pollution Control Series H (redeemed)
December 1, 1984 Resource Recovery Series I
May 1, 1985 Series due June 1, 2015 (redeemed)
September 1, 1985 Pollution Control Series J, K and L
July 1, 1989 Series due July 1, 2019 (redeemed)
June 1, 1990 Series due June 1, 2020 (redeemed)
October 1, 1992 Series due October 1, 1997
April 1, 1993 Series due April 1, 2003
December 1, 1993 Series due December 1, 2000, and December 1, 2005
February 1, 1994 Series due February 1, 1999
October 1, 1994 Series due October 1, 2001
June 1, 1995 Series due July 1, 2025
April 1, 1997 Pollution Control Series M, N, O and P; and
WHEREAS, the 1937 Indenture and all of the foregoing Supplemental Trust
Indentures are referred to herein collectively as the "Original Indenture"; and
WHEREAS, the Company heretofore has executed and delivered to the
Trustee a Supplemental and Restated Trust Indenture, dated May 1, 1988 (the
"Restated Indenture"), which, in addition to conveying, assigning, transferring,
mortgaging, pledging, setting over, and confirming to the Trustee, and its
respective successors in said trust, additional property acquired by it
subsequent to the preparation of the next preceding Supplemental Trust
Indenture, amended and restated the Original Indenture; and
WHEREAS, the Restated Indenture will not become effective and operative
until all bonds of each series issued under the Original Indenture prior to May
1, 1988 shall have been retired through payment or redemption (including those
bonds "deemed to be paid" within the meaning of that term as used in Article
XVII of the 1937 Indenture) or until, subject to certain exceptions, the holders
of the requisite principal amount of such bonds shall have consented to the
amendments contained in the Restated Indenture (such date being herein called
the "Effective Date"); and
WHEREAS, the Original Indenture and the Restated Indenture are referred
to herein collectively as the "Indenture"; and
WHEREAS, the City of Becker, in the County of Sherburne, a municipal
corporation existing under the Constitution and laws of the State of Minnesota
(the "City") has issued $60,000,000 principal amount of its Pollution Control
Revenue Refunding Bonds (Northern States Power Company--Sherburne County
Generating Station Units 1 and 2 Project), Series 1989-A (the "Series 1989-A
Pollution Control Revenue Bonds") pursuant to the provisions of the Indenture of
Trust, dated as of July 1, 1989, as supplemented by Supplemental Indenture No. 1
dated as of April 1, 1997 (as supplemented, the "Series 1989-A Pollution Control
Indenture"), between the City and First Trust National Association, as Trustee
(said Trustee or any successor trustee under the Series 1989-A Pollution Control
Indenture being hereinafter referred to as the "Series 1989-A Pollution Control
Trustee"); and
<PAGE>
WHEREAS, the net proceeds of the Series 1989-A Pollution Control
Revenue Bonds were loaned by the City to the Company pursuant to the provisions
of a Loan Agreement dated as of July 1, 1989 as amended by Amendment No. 1 dated
as of April 1, 1997, between the City and the Company (as amended the "Series
1989-A Agreement"), to provide a portion of the funds to finance the
acquisition, construction and equipping of certain pollution control facilities
relating to the first and second electric generating units located in the City
at the Company's Sherburne County Generating Station, owned jointly by the
Company and Southern Minnesota Municipal Power Agency; and
WHEREAS, payments by the Company under and pursuant to the Series
1989-A Agreement have been assigned by the City to the Series 1989-A Pollution
Control Trustee in order to secure the payment of the Series 1989-A Pollution
Control Revenue Bonds; and
WHEREAS, in order to further secure the payment of the Series 1989-A
Pollution Control Revenue Bonds, the Company desires to provide for the issuance
under the Indenture to the Series 1989-A Pollution Control Trustee of a new
series of bonds designated "First Mortgage Bonds, Pollution Control Series M"
(sometimes called "Bonds of Pollution Control Series M"), in a principal amount
equal to the principal amount of the Series 1989-A Pollution Control Revenue
Bonds, and with corresponding terms and maturity, the Bonds of Pollution Control
Series M to be issued as registered bonds without coupons in denominations of a
multiple of $5,000; and
WHEREAS, the City has issued $27,900,000 principal amount of its
Pollution Control Revenue Bonds (Northern States Power Company--Sherburne County
Generating Station Unit 3 Project), Series 1992-A (the "Series 1992-A Pollution
Control Revenue Bonds") pursuant to the provisions of the Indenture of Trust,
dated as of March 1, 1992, as supplemented by Supplemental Indenture No. 1 dated
as of April 1, 1997 (as supplemented, the "Series 1992-A Pollution Control
Indenture"), between the City and Norwest Bank Minnesota, National Association,
as Trustee (said Trustee or any successor trustee under the Series 1992-A
Pollution Control Indenture being hereinafter referred to as the "Series 1992-A
Pollution Control Trustee"); and
WHEREAS, the net proceeds of the Series 1992-A Pollution Control
Revenue Bonds were loaned by the City to the Company pursuant to the provisions
of a Loan Agreement dated as of March 1, 1992, as amended by Amendment No. 1
dated as of April 1, 1997, between the City and the Company (as amended, the
"Series 1992-A Agreement"), to provide a portion of the funds to finance the
acquisition, construction and equipping of certain pollution control facilities
relating to the third electric generating unit located in the City at the
Company's Sherburne County Generating Station, owned jointly by the Company and
Southern Minnesota Municipal Power Agency; and
WHEREAS, payments by the Company under and pursuant to the Series
1992-A Agreement have been assigned by the City to the Series 1992-A Pollution
Control Trustee in order to secure the payment of the Series 1992-A Pollution
Control Revenue Bonds; and
WHEREAS, in order to further secure the payment of the Series 1992-A
Pollution Control Revenue Bonds, the Company desires to provide for the issuance
under the Indenture to the Series 1992-A Pollution Control Trustee of a new
series of bonds designated "First Mortgage Bonds, Pollution Control Series N"
(sometimes called "Bonds of Pollution Control Series N"), in a principal amount
equal to the principal amount of the Series 1992-A Pollution Control Revenue
Bonds, and with corresponding terms and maturity, the Bonds of Pollution Control
Series N to be issued as registered bonds without coupons in denominations of a
multiple of $5,000; and
WHEREAS, the City has issued $50,000,000 principal amount of its
Pollution Control Revenue Bonds (Northern States Power Company--Sherburne County
Generating Station Unit 3 Project), Series 1993-A (the "Series 1993-A Pollution
Control Revenue Bonds") pursuant to the provisions of the Indenture of Trust,
dated as of September 1, 1993, as supplemented by Supplemental Indenture No. 1
dated as of April 1, 1997 (as supplemented, the "Series 1993-A Pollution Control
Indenture"), between the City and Norwest Bank Minnesota, National Association,
as Trustee (said Trustee or any successor trustee under the Series 1993-A
Pollution Control Indenture being hereinafter referred to as the "Series 1993-A
Pollution Control Trustee"); and
<PAGE>
WHEREAS, the net proceeds of the Series 1993-A Pollution Control
Revenue Bonds were loaned by the City to the Company pursuant to the provisions
of a Loan Agreement dated as of September 1, 1993, as amended by Amendment No. 1
dated as of April 1, 1997, between the City and the Company (as amended, the
"Series 1993-A Agreement"), to provide a portion of the funds to finance the
acquisition, construction and equipping of certain pollution control facilities
relating to the third electric generating unit located in the City at the
Company's Sherburne County Generating Station, owned jointly by the Company and
Southern Minnesota Municipal Power Agency; and
WHEREAS, payments by the Company under and pursuant to the Series
1993-A Agreement have been assigned by the City to the Series 1993-A Pollution
Control Trustee in order to secure the payment of the Series 1993-A Pollution
Control Revenue Bonds; and
WHEREAS, in order to further secure the payment of the Series 1993-A
Pollution Control Revenue Bonds, the Company desires to provide for the issuance
under the Indenture to the Series 1993-A Pollution Control Trustee of a new
series of bonds designated "First Mortgage Bonds, Pollution Control Series O"
(sometimes called "Bonds of Pollution Control Series O"), in a principal amount
equal to the principal amount of the Series 1993-A Pollution Control Revenue
Bonds, and with corresponding terms and maturity, the Bonds of Pollution Control
Series O to be issued as registered bonds without coupons in denominations of a
multiple of $5,000; and
WHEREAS, the City has issued $50,000,000 principal amount of its
Pollution Control Revenue Bonds (Northern States Power Company--Sherburne County
Generating Station Unit 3 Project), Series 1993-B (the "Series 1993-B Pollution
Control Revenue Bonds") pursuant to the provisions of the Indenture of Trust,
dated as of September 1, 1993, as supplemented by Supplemental Indenture No. 1
dated as of April 1, 1997 (as supplemented, the "Series 1993-B Pollution Control
Indenture"), between the City and Norwest Bank Minnesota, National Association,
as Trustee (said Trustee or any successor trustee under the Series 1993-B
Pollution Control Indenture being hereinafter referred to as the "Series 1993-B
Pollution Control Trustee"); and
WHEREAS, the net proceeds of the Series 1993-B Pollution Control
Revenue Bonds were loaned by the City to the Company pursuant to the provisions
of a Loan Agreement dated as of September 1, 1993, as amended by Amendment No. 1
dated as of April 1, 1997 between the City and the Company (as amended, the
"Series 1993-B Agreement"), to provide a portion of the funds to finance the
acquisition, construction and equipping of certain pollution control facilities
relating to the third electric generating unit located in the City at the
Company's Sherburne County Generating Station, owned jointly by the Company and
Southern Minnesota Municipal Power Agency; and
WHEREAS, payments by the Company under and pursuant to the Series
1993-B Agreement have been assigned by the City to the Series 1993-B Pollution
Control Trustee in order to secure the payment of the Series 1993-B Pollution
Control Revenue Bonds; and
WHEREAS, in order to further secure the payment of the Series 1993-B
Pollution Control Revenue Bonds, the Company desires to provide for the issuance
under the Indenture to the Series 1993-B Pollution Control Trustee of a new
series of bonds designated "First Mortgage Bonds, Pollution Control Series P"
(sometimes called "Bonds of Pollution Control Series P"), in a principal amount
equal to the principal amount of the Series 1993-B Pollution Control Revenue
Bonds, and with corresponding terms and maturity, the Bonds of Pollution Control
Series P to be issued as registered bonds without coupons in denominations of a
multiple of $5,000; and
<PAGE>
WHEREAS, the Bonds of Pollution Control Series M, the Bonds of
Pollution Control Series N, the Bonds of Pollution Control Series O and the
Bonds of Pollution Control Series P are to be substantially in the form and
tenor following, to-wit:
(Form of Bonds of Pollution Control Series M, N, O and P)
This Bond has not been registered under the Securities Act of 1933, as
amended, and may not be offered or sold in contravention of said Act and is not
transferable except to a successor Trustee under the Indenture of Trust dated as
of ____________ from the City of Becker, Minnesota (the "City"), to ___________,
as Trustee.
NORTHERN STATES POWER COMPANY
(Incorporated under the laws of the State of Minnesota)
First Mortgage Bond
Pollution Control Series
No.__________________ $______________
Northern States Power Company, a corporation organized and existing
under and by virtue of the laws of the State of Minnesota (herein called the
"Company"), for value received, hereby promises to pay to ________________,
_____________, Minnesota, as Trustee under the Indenture of Trust dated as of
________________, as supplemented by Supplemental Indenture No. 1 dated as of
April 1, 1997 (as supplemented, the "Pollution Control Indenture") from the City
of Becker, Minnesota, to ______________________, ______________, Minnesota, or
any successor trustee under the Pollution Control Indenture (the "Pollution
Control Trustee") and at the office of Harris Trust and Savings Bank, Chicago,
Illinois (the "Trustee") the sum of _____________________ Million Dollars in
lawful money of the United States of America on the Demand Redemption Date, as
hereinafter defined, and to pay on the Demand Redemption Date to the Pollution
Control Trustee, interest hereon from the Initial Interest Accrual Date, as
hereinafter defined, to the Demand Redemption Date at the same rate or rates per
annum then and thereafter from time to time borne by the Pollution Control
Revenue [Refunding] Bonds (Northern States Power Company -- Sherburne County
Generating Station Unit _________ Project), Series ____________ (the "Pollution
Control Revenue Bonds"), in like money, said interest being payable at the
office of the Trustee in Chicago, Illinois, subject to the provisions
hereinafter set forth in the event of a rescission of a Redemption Demand, as
hereinafter defined.
This bond is one of a duly authorized issue of bonds of the Company,
known as its First Mortgage Bonds, unlimited in aggregate principal amount,
which issue of bonds consists, or may consist of several series of varying
denominations, dates and tenors, all issued and to be issued under and equally
secured (except in so far as a sinking fund, or similar fund, established in
accordance with the provisions of the Indenture may afford additional security
for the bonds of any specific series) by a Trust Indenture dated February 1,
1937 (the "1937 Indenture"), as supplemented by 44 supplemental trust indentures
(the "Supplemental Indentures"), a Supplemental and Restated Trust Indenture
dated May 1, 1988 (the "Restated Indenture") and a new supplemental trust
indenture for the bonds of this series (the "New Supplemental Indenture"),
executed by the Company to the Trustee. The 1937 Indenture, as supplemented by
the Supplemental Indentures, the Restated Indenture and the New Supplemental
Indenture, is referred to as the "Indenture". Reference is hereby made to the
Indenture for a description of the property mortgaged and pledged, the nature
and extent of the security, the rights of the holders of the bonds as to such
security, and the terms and conditions upon which the bonds may be issued under
the Indenture and are secured. The principal hereof may be declared or may
become due on the conditions, in the manner and at the time set forth in the
Indenture, upon the happening of a default as in the Indenture provided.
With the consent of the Company and to the extent permitted by and as
provided in the Indenture, the rights and obligations of the Company and/or the
holders of the bonds, and/or the terms and provisions of the Indenture and/or of
any instruments supplemental thereto may be modified or altered by affirmative
vote of the holders of at least 80% in principal amount of the bonds then
outstanding under the Indenture and any
<PAGE>
instruments supplemental thereto (excluding bonds disqualified from voting by
reason of the Company's interest therein as provided in the Indenture); provided
that without the consent of all holders of all bonds affected no such
modification or alteration shall permit the extension of the maturity of the
principal of any bond or the reduction in the rate of interest thereon or any
other modification in the terms of payment of such principal or interest. The
foregoing 80% requirement will be reduced to 66 2/3% when all bonds of each
series issued under the Indenture prior to May 1, 1985, shall have been retired
or all the holders thereof shall have consented to such reduction.
The Restated Indenture amends and restates the 1937 Indenture and the
Supplemental Indentures. The Restated Indenture will become effective and
operative (the "Effective Date") when all Bonds of each series issued under the
Indenture prior to May 1, 1988 shall have been retired through payment or
redemption (including those bonds "deemed to be paid" within the meaning of that
term as used in Article XVII of the 1937 Indenture) or until, subject to certain
exceptions, the holders of the requisite principal amount of such bonds shall
have consented to the amendments contained in the Restated Indenture. Holders of
the bonds of this series and of each subsequent series of bonds issued under the
Indenture likewise will be bound by the amendments contained in the Restated
Indenture when they become effective and operative. Reference is made to the
Restated Indenture for a complete description of the amendments contained
therein to the 1937 Indenture and to the Supplemental Indentures.
This bond is one of a series of bonds of the Company issued under the
Indenture and designated as First Mortgage Bonds, Pollution Control Series
__________. The bonds of this Series have been issued to the Pollution Control
Trustee under the Pollution Control Indenture to secure payment of the Pollution
Control Revenue Bonds issued by the City under the Pollution Control Indenture,
the proceeds of which have been or are to be loaned to the Company pursuant to
the provisions of the Loan Agreement dated as of ___________, as amended by
Amendment No. 1 dated as of April 1, 1997 (as amended, the "Agreement") between
the Company and the City. The maturity of the obligation represented by the
bonds of this Series is _______________. The date of maturity of the obligation
represented by the bonds of this Series is hereinafter referred to as the Final
Maturity Date. The bonds of this Series shall bear interest from the Initial
Interest Accrual Date, as hereinafter defined, at the same rate or rates per
annum then and thereafter from time to time borne by the Pollution Control
Revenue Bonds.
Except as provided in the next succeeding paragraph, in the event of a
default under Section 8.01 of the Agreement or in the event of a default in the
payment of the principal of, premium, if any, or interest [(and such default in
the payment of interest continues for the full grace period, if any, permitted
by the Pollution Control Indenture and the Pollution Control Revenue Bonds)] on
the Pollution Control Revenue Bonds, whether at maturity, by acceleration, by
sinking fund, redemption or otherwise, as and when the same becomes due, the
bonds of this Series shall be redeemable in whole upon receipt by the Trustee of
a written demand (hereinafter called a "Redemption Demand") from the Pollution
Control Trustee stating that there has been such a default, stating that it is
acting pursuant to the authorization granted by Section [8.03][8-3] of the
Pollution Control Indenture, specifying the last date to which interest on the
Pollution Control Revenue Bonds has been paid (such date being hereinafter
referred to as the "Initial Interest Accrual Date") and demanding redemption of
the bonds of this Series. The Trustee shall, within 10 days after receiving such
Redemption Demand, mail a copy thereof to the Company marked to indicate the
date of its receipt by the Trustee. Promptly upon receipt by the Company of such
copy of a Redemption Demand, the Company shall fix a date on which it will
redeem the bonds of this Series so demanded to be redeemed (hereinafter called
the "Demand Redemption Date"). Notice of the date fixed as and for the Demand
Redemption Date shall be mailed by the Company to the trustee at least 30 days
prior to such Demand Redemption Date. The date to be fixed by the Company as and
for the Demand Redemption Date may be any date up to and including the earlier
of (i) the 120th day after receipt by the Trustee of the Redemption Demand or
(ii) the Final Maturity Date, PROVIDED that if the Trustee shall not have
received such notice fixing the Demand Redemption Date within 90 days after
receipt by it of the Redemption Demand, the Demand Redemption Date shall be
deemed to be the earlier of (i) the 120th day after receipt by the Trustee of
the Redemption Demand or (ii) the Final Maturity Date. The Trustee shall mail
notice of the Demand Redemption Date (such notice being hereafter called the
"Demand Redemption Notice") to the Pollution
<PAGE>
Control Trustee not more than 10 nor less than five days prior to the Demand
Redemption Date. Notwithstanding the foregoing, if a default to which this
paragraph is applicable is existing on the Final Maturity Date, such date shall
be deemed to be the Demand Redemption Date without further action (including
actions specified in this paragraph) by the Pollution Control Trustee, the
Trustee or the Company. The bonds of this Series shall be redeemed by the
Company on the Demand Redemption Date, upon surrender thereof by the Pollution
Control Trustee to the Trustee, at a redemption price equal to the principal
amount thereof, plus accrued interest thereon at the rate per annum set forth in
the first paragraph of this Bond, from the Initial Interest Accrual Date to the
Demand Redemption Date. If a Redemption Demand is rescinded by the Pollution
Control Trustee by written notice to the Trustee prior to the Demand Redemption
Date, no Demand Redemption Notice shall be given, or, if already given, shall be
automatically annulled, and interest on the bonds of this Series shall cease to
accrue, all interest accrued thereon shall be automatically rescinded and
cancelled and the Company shall not be obligated to make any payments of
principal of or interest on the bonds of this Series; but no such rescission
shall extend to or affect any subsequent default or impair any right consequent
thereon.
In the event that all of the bonds outstanding under the Indenture
shall have become immediately due and payable, whether by declaration or
otherwise, and such acceleration shall not have been annulled, the bonds of this
Series shall bear interest at the rate per annum set forth in the first
paragraph of this Bond, from the Initial Interest Accrual Date, as specified in
a written notice to the Trustee from the Pollution Control Trustee, and the
principal of and interest on the bonds of this Series from the Initial Interest
Accrual Date shall be payable in accordance with the provisions of the
Indenture.
Upon payment of the principal of and premium, if any, and interest on
the Pollution Control Revenue Bonds, whether at maturity or prior to maturity by
redemption or otherwise, and the surrender thereof to and cancellation thereof
by the Pollution Control Trustee (other than any Pollution Control Revenue Bond
that was cancelled by the Pollution Control Trustee and for which one or more
other Pollution Control Revenue Bonds were delivered and authenticated pursuant
to the Pollution Control Indenture in lieu of or in exchange or substitution for
such cancelled Pollution Control Revenue Bond), or upon provision for the
payment thereof having been made in accordance with the Pollution Control
Indenture, bonds of this Series in a principal amount equal to the principal
amount of the Pollution Control Revenue Bonds so surrendered and cancelled or
for the provision for which payment has been made shall be deemed fully paid and
the obligations of the Company thereunder shall be terminated, and such bonds of
this Series shall be surrendered by the Pollution Control Trustee to the Trustee
and shall be cancelled by the Trustee.
No recourse shall be had for the payment of, or interest, if any, on
this bond, or any part thereof, or of any claim based hereon or in respect
hereof or of the Indenture, against any incorporator, or any past, present or
future stockholder, officer or director of the Company or of any predecessor or
successor corporation, either directly or through the Company, or through any
such predecessor or successor corporation, or through any receiver or a trustee
in bankruptcy, whether by virtue of any constitution, statute or rule of law or
by the enforcement of any assessment or penalty or otherwise, all such liability
being, by the acceptance hereof and as part of the consideration for the issue
hereof, expressly waived and released, as more fully provided in the Indenture.
The bond shall not be valid or become obligatory for any purpose unless
and until the certificate of authentication hereon shall have been signed by or
on behalf of Harris Trust and Savings Bank, as Trustee under the Indenture, or
its successor thereunder.
IN WITNESS WHEREOF, NORTHERN STATES POWER COMPANY has caused this
instrument to be signed in its name by its President or a Vice President, and
its corporate seal, or a facsimile thereof, to be hereto affixed and attested by
its Secretary or an Assistant Secretary.
Dated:______________ NORTHERN STATES POWER COMPANY
Attest:______________ By______________________________________
_________Secretary __________President
<PAGE>
(Form of Trustee's Certificate)
This bond is one of the bonds of the Series designated thereon,
described in the within-mentioned Indenture.
HARRIS TRUST AND SAVINGS BANK,
As Trustee,
By____________________________
Authorized Officer
and
WHEREAS, the Company is desirous of conveying, assigning, transferring,
mortgaging, pledging, setting over, and confirming to the Trustee and to its
respective successors in trust, additional property acquired by it subsequent to
the date of the preparation of the Supplemental Trust Indenture dated June 1,
1995; and
WHEREAS, the Indenture provides in substance that the Company and the
Trustee may enter into indentures supplemental thereto for the purposes, among
others, of creating and setting forth the particulars of any new series of bonds
and of providing the terms and conditions of the issue of the bonds of any
series not expressly provided for in the Indenture and of conveying, assigning,
transferring, mortgaging, pledging, setting over and confirming to the Trustee
additional property of the Company, and for any other purpose not inconsistent
with the terms of the Indenture; and
WHEREAS, the execution and delivery of this Supplemental Trust
Indenture have been duly authorized by a resolution adopted by the Board of
Directors of the Company;
WHEREAS, the Trustee has duly determined to execute this Supplemental
Trust Indenture and to be bound, insofar as it may lawfully do so, by the
provisions hereof;
NOW, THEREFORE, Northern States Power Company, in consideration of the
premises and of one dollar duly paid to it by the Trustee at or before the
ensealing and delivery of these presents, the receipt of which is hereby
acknowledged, and other good and valuable considerations, does hereby covenant
and agree to and with Harris Trust and Savings Bank, as Trustee, and its
successors in the trust under the Indenture for the benefit of those who hold or
shall hold the bonds, or any of them, issued or to be issued thereunder, as
follows:
ARTICLE I.
SPECIFIC SUBJECTION OF ADDITIONAL PROPERTY TO
THE LIEN OF THE ORIGINAL INDENTURE
SECTION 1.01. The Company in order to better secure the payment, of
both the principal and interest, of all bonds of the Company at any time
outstanding under the Indenture according to their tenor and effect and the
performance of and compliance with the covenants and conditions contained in the
Indenture, has granted, bargained, sold, warranted, released, conveyed,
assigned, transferred, mortgaged, pledged, set over, and confirmed and by these
presents does grant, bargain, sell, warrant, release, convey, assign, transfer,
mortgage, pledge, set over, and confirm to the Trustee and to its respective
successors in said trust forever, subject to the rights reserved by the Company
in and by the provisions of the Indenture, all of the property described and
mentioned or enumerated in a schedule annexed hereto and marked Schedule A,
reference to said schedule being made hereby with the same force and effect as
if the same were incorporated herein at length; together with all and singular
the tenements, hereditaments, and appurtenances belonging and in any way
appertaining to the aforesaid property or any part thereof with the reversion
and reversions, remainder and remainders, tolls, rents and revenues, issues,
income, products, and profits thereof;
<PAGE>
Also, in order to subject the personal property and chattels of the
Company to the lien of the Indenture and to conform with the provisions of the
Uniform Commercial Code, all fossil, nuclear, hydro, and other electric
generating plants, including buildings and other structures, turbines,
generators, exciters, boilers, reactors, nuclear fuel, other boiler plant
equipment, condensing equipment and all other generating equipment; substations;
electric transmission and distribution systems, including structures, poles,
towers, fixtures, conduits, insulators, wires, cables, transformers, services
and meters; steam heating mains and equipment; gas transmission and distribution
systems, including structures, storage facilities, mains, compressor stations,
purifier stations, pressure holders, governors, services, and meters; telephone
plant and related distribution systems; trucks and trailers; office, shop, and
other buildings and structures, furniture and equipment; apparatus and equipment
of all other kinds and descriptions; materials and supplies; all municipal and
other franchises, leaseholds, licenses, permits, privileges, patents and patent
rights; all shares of stock, bonds, evidences of indebtedness, contracts,
claims, accounts receivable, choses in action and other intangibles, all books
of account and other corporate records;
Excluding, however, all merchandise and appliances heretofore or
hereafter acquired for the purpose of sale to customers and others;
All the estate, right, title, interest, and claim, whatsoever, at law
as well as in equity, which the Company now has or hereafter may acquire in and
to the aforesaid property and every part and parcel thereof subject, however, to
the right of the Company, until the happening of a completed default as defined
in Section 1 of Article XIII of the Original Indenture prior to the Effective
Date and upon the occurrence and continuation of a Completed Default as defined
in the Indenture on and after the Effective Date, to retain in its possession
all shares of stock, notes, evidences of indebtedness, other securities and cash
not expressly required by the provisions hereof to be deposited with the
Trustee, to retain in its possession all contracts, bills and accounts
receivable, motor cars, any stock of goods, wares and merchandise, equipment or
supplies acquired for the purpose of consumption in the operation, construction,
or repair of any of the properties of the Company, and to sell, exchange,
pledge, hypothecate, or otherwise dispose of any or all of such property so
retained in its possession free from the lien of the Indenture, without
permission or hindrance on the part of the Trustee, or any of the bondholders.
No person in any dealings with the Company in respect of any such property shall
be charged with any notice or knowledge of any such completed default (prior to
the Effective Date) or Completed Default (after the Effective Date) under the
Indenture while the Company is in possession of such property. Nothing contained
herein or in the Indenture shall be deemed or construed to require the deposit
with, or delivery to, the Trustee of any of such property, except such as is
specifically required to be deposited with the Trustee by some express provision
of the Indenture;
To have and to hold all said property, real, personal, and mixed,
granted, bargained, sold, warranted, released, conveyed, assigned, transferred,
mortgaged, pledged, set over, or confirmed by the Company as aforesaid, or
intended so to be, to the Trustee and its successors and assigns forever,
subject, however, to permitted liens as defined in Section 5 of Article I of the
1937 Indenture prior to the Effective Date and to Permitted Encumbrances on and
after the Effective Date and to the further reservations, covenants, conditions,
uses, and trusts set forth in the Indenture; in trust nevertheless for the same
purposes and upon the same conditions as are set forth in the Indenture.
ARTICLE II.
PROVISIONS OF BONDS OF POLLUTION CONTROL SERIES M, N, O AND P
SECTION 2.01. There is hereby created, for issuance under the
Indenture, a series of bonds designated Pollution Control Series M, each of
which shall bear the descriptive title "First Mortgage Bonds, Pollution Control
Series M" and the form thereof shall contain suitable provisions with respect to
the matters specified in this section. The Bonds of Pollution Control Series M
shall be printed, lithographed or typewritten and shall be substantially of the
tenor and purport previously recited. The Bonds of Pollution Control Series M
shall be
<PAGE>
issued as registered bonds without coupons in denominations of a multiple of
$5,000 and shall be registered in the name of the Series 1989-A Pollution
Control Trustee. The Bonds of Pollution Control Series M shall be dated as of
the date of their authentication.
The Bonds of Pollution Control Series M shall be payable, both as to
principal and interest, at the office of the Trustee in Chicago, Illinois, in
lawful money of the United States of America. The maturity of the obligation
represented by the Bonds of Pollution Control Series M is April 1, 2007. The
date of maturity of the obligation represented by the Bonds of Pollution Control
Series M is hereinafter referred to as the Series M Final Maturity Date. The
Bonds of Pollution Control Series M shall bear interest from the Series M
Initial Interest Accrual Date, as hereinafter defined, at the same rate or rates
then and thereafter from time to time borne by the Series 1989-A Pollution
Control Revenue Bonds.
SECTION 2.02. Except as provided in the next succeeding paragraph of
this Section 2.02, in the event of a default under Section 8.01 of the Series
1989-A Agreement or in the event of a default in the payment of the principal
of, premium, if any, or interest on the Series 1989-A Pollution Control Revenue
Bonds, whether at maturity, by acceleration, by sinking fund, redemption or
otherwise, as and when the same becomes due, the Bonds of Pollution Control
Series M shall be redeemable in whole upon receipt by the Trustee of a written
demand (hereinafter called a "Series M Redemption Demand") from the Series
1989-A Pollution Control Trustee stating that there has been such a default,
stating that it is acting pursuant to the authorization granted by Section 8-3
of the Series 1989-A Pollution Control Indenture, specifying the last date to
which interest on the Series 1989-A Pollution Control Revenue Bonds has been
paid (such date being hereinafter referred to as the "Series M Initial Interest
Accrual Date") and demanding redemption of the Bonds of Pollution Control Series
M. The Trustee shall, within 10 days after receiving such Series M Redemption
Demand, mail a copy thereof to the Company marked to indicate the date of its
receipt by the Trustee. Promptly upon receipt by the Company of such copy of a
Series M Redemption Demand, the Company shall fix a date on which it will redeem
the Bonds of Pollution Control Series M so demanded to be redeemed (hereinafter
called the "Series M Demand Redemption Date"). Notice of the date fixed as the
Series M Demand Redemption Date shall be mailed by the Company to the Trustee at
least 30 days prior to such Series M Demand Redemption Date. The date to be
fixed by the Company as and for the Series M Demand Redemption Date may be any
date up to and including the earlier of (i) the 120th day after receipt by the
Trustee of the Series M Redemption Demand or (ii) the Series M Final Maturity
Date; PROVIDED that if the Trustee shall not have received such notice fixing
the Series M Demand Redemption Date within 90 days after receipt by it of the
Series M Redemption Demand, the Series M Demand Redemption Date shall be deemed
to be the earlier of (i) the 120th day after receipt by the Trustee of the
Series M Redemption Demand or (ii) the Series M Final Maturity Date. The Trustee
shall mail notice of the Series M Demand Redemption Date (such notice being
hereinafter called the "Series M Demand Redemption Notice") to the Series 1989-A
Pollution Control Trustee not more than 10 nor less than five days prior to the
Series M Demand Redemption Date. Notwithstanding the foregoing, if a default to
which this paragraph is applicable is existing on the Series M Final Maturity
Date, such date shall be deemed to be the Series 1989-A Demand Redemption Date
without further action (including actions specified in this paragraph) by the
Series 1989-A Pollution Control Trustee, the Trustee or the Company. The Bonds
of Pollution Control Series M shall be redeemed by the Company on the Series M
Demand Redemption Date, upon surrender thereof by the Series 1989-A Pollution
Control Trustee to the Trustee, at a redemption price equal to the principal
amount thereof, plus accrued interest thereon at the rate per annum set forth in
Section 2.01 hereof, from the Series M Initial Interest Accrual Date to the
Series M Demand Redemption Date. If a Series M Redemption Demand is rescinded by
the Series 1989-A Pollution Control Trustee by written notice to the Trustee
prior to the Series M Demand Redemption Date, no Series M Demand Redemption
Notice shall be given, or, if already given, shall be automatically annulled,
and interest on the Bonds of Pollution Control Series M shall cease to accrue,
all interest accrued thereon shall be automatically rescinded and cancelled and
the Company shall not be obligated to make any payments of principal of or
interest on the Bonds of Pollution Control Series M; but no such rescission
shall extend to or affect any subsequent default or impair any right consequent
thereon.
<PAGE>
In the event that all of the bonds outstanding under the Indenture
shall have become immediately due and payable, whether by declaration or
otherwise, and such acceleration shall not have been annulled, the Bonds of
Pollution Control Series M shall bear interest at the rate per annum set forth
in Section 2.01 hereof, from the Series M Initial Interest Accrual Date, as
specified in a written notice to the Trustee from the Series 1989-A Pollution
Control Trustee, and the principal of and interest on the Bonds of Pollution
Control Series M from the Series M Initial Interest Accrual Date shall be
payable in accordance with the provisions of the Indenture.
Anything herein contained to the contrary notwithstanding, the Trustee
is not authorized to take any action pursuant to a Series M Redemption Demand or
a rescission thereof or a written notice required by this Section 2.02, and such
Series M Redemption Demand, rescission or notice shall be of no force or effect,
unless it is executed in the name of the Series 1989-A Pollution Control Trustee
by one of its Vice Presidents.
SECTION 2.03. Upon payment of the principal of and premium, if any, and
interest on the Series 1989-A Pollution Control Revenue Bonds, whether at
maturity or prior to maturity by redemption or otherwise, and the surrender
thereof to and cancellation thereof by the Series 1989-A Pollution Control
Trustee (other than any Series 1989-A Pollution Control Revenue Bond that was
cancelled by the Series 1989-A Pollution Control Trustee and for which one or
more other Series 1989-A Pollution Control Revenue Bonds were delivered and
authenticated pursuant to the Series 1989-A Pollution Control Indenture), or
upon provision for the payment thereof having been made in accordance with the
Series 1989-A Pollution Control Indenture, Bonds of Pollution Control Series M
in a principal amount equal to the principal amount of the Series 1989-A
Pollution Control Revenue Bonds so surrendered and cancelled or for the
provision for which payment has been made shall be deemed fully paid and the
obligations of the Company thereunder shall be terminated, and such Bonds of
Pollution Control Series M shall be surrendered by the Series 1989-A Pollution
Control Trustee to the Trustee and shall be cancelled and destroyed by the
Trustee, and a certificate of such cancellation and destruction shall be
delivered to the Company.
SECTION 2.04. There is hereby created, for issuance under the
Indenture, a series of bonds designated Pollution Control Series N, each of
which shall bear the descriptive title "First Mortgage Bonds, Pollution Control
Series N" and the form thereof shall contain suitable provisions with respect to
the matters specified in this section. The Bonds of Pollution Control Series N
shall be printed, lithographed or typewritten and shall be substantially of the
tenor and purport previously recited. The Bonds of Pollution Control Series N
shall be issued as registered bonds without coupons in denominations of a
multiple of $5,000 and shall be registered in the name of the Series 1992-A
Pollution Control Trustee. The Bonds of Pollution Control Series N shall be
dated as of the date of their authentication.
The Bonds of Pollution Control Series N shall be payable, both as to
principal and interest, at the office of the Trustee in Chicago, Illinois, in
lawful money of the United States of America. The maturity of the obligation
represented by the Bonds of Pollution Control Series N is March 1, 2019. The
date of maturity of the obligation represented by the Bonds of Pollution Control
Series N is hereinafter referred to as the Series N Final Maturity Date. The
Bonds of Pollution Control Series N shall bear interest from the Series N
Initial Interest Accrual Date, as hereinafter defined, at the same rate or rates
then and thereafter from time to time borne by the Series 1992-A Pollution
Control Revenue Bonds.
SECTION 2.05. Except as provided in the next succeeding paragraph of
this Section 2.05, in the event of a default under Section 8.01 of the Series
1992-A Agreement or in the event of a default in the payment of the principal
of, premium, if any, or interest (and such default in the payment of interest
continues for the full grace period, if any, permitted by the Series 1992-A
Pollution Control Indenture and the Series 1992-A Pollution Control Revenue
Bonds) on the Series 1992-A Pollution Control Revenue Bonds, whether at
maturity, by acceleration, by sinking fund, redemption or otherwise, as and when
the same becomes due, the Bonds of Pollution Control Series N shall be
redeemable in whole upon receipt by the Trustee of a written demand (hereinafter
called a "Series N Redemption Demand") from the Series 1992-A Pollution Control
Trustee stating that there has been such a default, stating that it is acting
pursuant to the authorization granted by Section 8.03 of the Series 1992-A
Pollution Control Indenture, specifying the last date to which interest on the
Series 1992-A Pollution Control Revenue Bonds has been paid (such date being
hereinafter referred to as the "Series N Initial
<PAGE>
Interest Accrual Date") and demanding redemption of the Bonds of Pollution
Control Series N. The Trustee shall, within 10 days after receiving such Series
N Redemption Demand, mail a copy thereof to the Company marked to indicate the
date of its receipt by the Trustee. Promptly upon receipt by the Company of such
copy of a Series N Redemption Demand, the Company shall fix a date on which it
will redeem the Bonds of Pollution Control Series N so demanded to be redeemed
(hereinafter called the "Series N Demand Redemption Date"). Notice of the date
fixed as the Series N Demand Redemption Date shall be mailed by the Company to
the Trustee at least 30 days prior to such Series N Demand Redemption Date. The
date to be fixed by the Company as and for the Series N Demand Redemption Date
may be any date up to and including the earlier of (i) the 120th day after
receipt by the Trustee of the Series N Redemption Demand or (ii) the Series N
Final Maturity Date; PROVIDED that if the Trustee shall not have received such
notice fixing the Series N Demand Redemption Date within 90 days after receipt
by it of the Series N Redemption Demand, the Series N Demand Redemption Date
shall be deemed to be the earlier of (i) the 120th day after receipt by the
Trustee of the Series N Redemption Demand or (ii) the Series N Final Maturity
Date. The Trustee shall mail notice of the Series N Demand Redemption Date (such
notice being hereinafter called the "Series N Demand Redemption Notice") to the
Series 1992-A Pollution Control Trustee not more than 10 nor less than five days
prior to the Series N Demand Redemption Date. Notwithstanding the foregoing, if
a default to which this paragraph is applicable is existing on the Series N
Final Maturity Date, such date shall be deemed to be the Series 1992-A Demand
Redemption Date without further action (including actions specified in this
paragraph) by the Series 1992-A Pollution Control Trustee, the Trustee or the
Company. The Bonds of Pollution Control Series N shall be redeemed by the
Company on the Series N Demand Redemption Date, upon surrender thereof by the
Series 1992-A Pollution Control Trustee to the Trustee, at a redemption price
equal to the principal amount thereof, plus accrued interest thereon at the rate
per annum set forth in Section 2.04 hereof, from the Series N Initial Interest
Accrual Date to the Series M Demand Redemption Date. If a Series N Redemption
Demand is rescinded by the Series 1992-A Pollution Control Trustee by written
notice to the Trustee prior to the Series N Demand Redemption Date, no Series N
Demand Redemption Notice shall be given, or, if already given, shall be
automatically annulled, and interest on the Bonds of Pollution Control Series N
shall cease to accrue, all interest accrued thereon shall be automatically
rescinded and cancelled and the Company shall not be obligated to make any
payments of principal of or interest on the Bonds of Pollution Control Series N;
but no such rescission shall extend to or affect any subsequent default or
impair any right consequent thereon.
In the event that all of the bonds outstanding under the Indenture
shall have become immediately due and payable, whether by declaration or
otherwise, and such acceleration shall not have been annulled, the Bonds of
Pollution Control Series N shall bear interest at the rate per annum set forth
in Section 2.04 hereof, from the Series N Initial Interest Accrual Date, as
specified in a written notice to the Trustee from the Series 1992-A Pollution
Control Trustee, and the principal of and interest on the Bonds of Pollution
Control Series N from the Series N Initial Interest Accrual Date shall be
payable in accordance with the provisions of the Indenture.
Anything herein contained to the contrary notwithstanding, the Trustee
is not authorized to take any action pursuant to a Series N Redemption Demand or
a rescission thereof or a written notice required by this Section 2.05, and such
Series N Redemption Demand, rescission or notice shall be of no force or effect,
unless it is executed in the name of the Series 1992-A Pollution Control Trustee
by one of its Vice Presidents.
SECTION 2.06. Upon payment of the principal of and premium, if any, and
interest on the Series 1992-A Pollution Control Revenue Bonds, whether at
maturity or prior to maturity by redemption or otherwise, and the surrender
thereof to and cancellation thereof by the Series 1992-A Pollution Control
Trustee (other than any Series 1992-A Pollution Control Revenue Bond that was
cancelled by the Series 1992-A Pollution Control Trustee and for which one or
more other Series 1992-A Pollution Control Revenue Bonds were delivered and
authenticated pursuant to the Series 1992-A Pollution Control Indenture), or
upon provision for the payment thereof having been made in accordance with the
Series 1992-A Pollution Control Indenture, Bonds of Pollution Control Series N
in a principal amount equal to the principal amount of the Series 1992-A
Pollution Control Revenue Bonds so surrendered and cancelled or for the
provision for which payment has been made shall be deemed fully paid and the
obligations of the Company thereunder shall be terminated, and such Bonds of
<PAGE>
Pollution Control Series N shall be surrendered by the Series 1992-A Pollution
Control Trustee to the Trustee and shall be cancelled and destroyed by the
Trustee, and a certificate of such cancellation and destruction shall be
delivered to the Company.
SECTION 2.07. There is hereby created, for issuance under the
Indenture, a series of bonds designated Pollution Control Series O, each of
which shall bear the descriptive title "First Mortgage Bonds, Pollution Control
Series O" and the form thereof shall contain suitable provisions with respect to
the matters specified in this section. The Bonds of Pollution Control Series O
shall be printed, lithographed or typewritten and shall be substantially of the
tenor and purport previously recited. The Bonds of Pollution Control Series O
shall be issued as registered bonds without coupons in denominations of a
multiple of $5,000 and shall be registered in the name of the Series 1993-A
Pollution Control Trustee. The Bonds of Pollution Control Series O shall be
dated as of the date of their authentication.
The Bonds of Pollution Control Series O shall be payable, both as to
principal and interest, at the office of the Trustee in Chicago, Illinois, in
lawful money of the United States of America. The maturity of the obligation
represented by the Bonds of Pollution Control Series O is September 1, 2019. The
date of maturity of the obligation represented by the Bonds of Pollution Control
Series O is hereinafter referred to as the Series O Final Maturity Date. The
Bonds of Pollution Control Series O shall bear interest from the Series O
Initial Interest Accrual Date, as hereinafter defined, at the same rate or rates
then and thereafter from time to time borne by the Series 1993-A Pollution
Control Revenue Bonds.
SECTION 2.08. Except as provided in the next succeeding paragraph of
this Section 2.08, in the event of a default under Section 8.01 of the Series
1993-A Agreement or in the event of a default in the payment of the principal
of, premium, if any, or interest (and such default in the payment of interest
continues for the full grace period, if any, permitted by the Series 1993-A
Pollution Control Indenture and the Series 1993-A Pollution Control Revenue
Bonds) on the Series 1993-A Pollution Control Revenue Bonds, whether at
maturity, by acceleration, by sinking fund, redemption or otherwise, as and when
the same becomes due, the Bonds of Pollution Control Series O shall be
redeemable in whole upon receipt by the Trustee of a written demand (hereinafter
called a "Series O Redemption Demand") from the Series 1993-A Pollution Control
Trustee stating that there has been such a default, stating that it is acting
pursuant to the authorization granted by Section 8.03 of the Series 1993-A
Pollution Control Indenture, specifying the last date to which interest on the
Series 1993-A Pollution Control Revenue Bonds has been paid (such date being
hereinafter referred to as the "Series O Initial Interest Accrual Date") and
demanding redemption of the Bonds of Pollution Control Series O. The Trustee
shall, within 10 days after receiving such Series O Redemption Demand, mail a
copy thereof to the Company marked to indicate the date of its receipt by the
Trustee. Promptly upon receipt by the Company of such copy of a Series O
Redemption Demand, the Company shall fix a date on which it will redeem the
Bonds of Pollution Control Series O so demanded to be redeemed (hereinafter
called the "Series O Demand Redemption Date"). Notice of the date fixed as the
Series O Demand Redemption Date shall be mailed by the Company to the Trustee at
least 30 days prior to such Series O Demand Redemption Date. The date to be
fixed by the Company as and for the Series O Demand Redemption Date may be any
date up to and including the earlier of (i) the 120th day after receipt by the
Trustee of the Series O Redemption Demand or (ii) the Series O Final Maturity
Date; PROVIDED that if the Trustee shall not have received such notice fixing
the Series O Demand Redemption Date within 90 days after receipt by it of the
Series O Redemption Demand, the Series O Demand Redemption Date shall be deemed
to be the earlier of (i) the 120th day after receipt by the Trustee of the
Series O Redemption Demand or (ii) the Series O Final Maturity Date. The Trustee
shall mail notice of the Series O Demand Redemption Date (such notice being
hereinafter called the "Series O Demand Redemption Notice") to the Series 1993-A
Pollution Control Trustee not more than 10 nor less than five days prior to the
Series O Demand Redemption Date. Notwithstanding the foregoing, if a default to
which this paragraph is applicable is existing on the Series O Final Maturity
Date, such date shall be deemed to be the Series 1993-A Demand Redemption Date
without further action (including actions specified in this paragraph) by the
Series 1993-A Pollution Control Trustee, the Trustee or the Company. The Bonds
of Pollution Control Series O shall be redeemed by the Company on the Series O
Demand Redemption Date, upon surrender thereof by the Series 1993-A Pollution
Control Trustee to the Trustee, at a redemption price equal to the principal
amount
<PAGE>
thereof, plus accrued interest thereon at the rate per annum set forth in
Section 2.07 hereof, from the Series O Initial Interest Accrual Date to the
Series O Demand Redemption Date. If a Series O Redemption Demand is rescinded by
the Series 1993-A Pollution Control Trustee by written notice to the Trustee
prior to the Series O Demand Redemption Date, no Series O Demand Redemption
Notice shall be given, or, if already given, shall be automatically annulled,
and interest on the Bonds of Pollution Control Series O shall cease to accrue,
all interest accrued thereon shall be automatically rescinded and cancelled and
the Company shall not be obligated to make any payments of principal of or
interest on the Bonds of Pollution Control Series O; but no such rescission
shall extend to or affect any subsequent default or impair any right consequent
thereon.
In the event that all of the bonds outstanding under the Indenture
shall have become immediately due and payable, whether by declaration or
otherwise, and such acceleration shall not have been annulled, the Bonds of
Pollution Control Series O shall bear interest at the rate per annum set forth
in Section 2.07 hereof, from the Series O Initial Interest Accrual Date, as
specified in a written notice to the Trustee from the Series 1993-A Pollution
Control Trustee, and the principal of and interest on the Bonds of Pollution
Control Series O from the Series O Initial Interest Accrual Date shall be
payable in accordance with the provisions of the Indenture.
Anything herein contained to the contrary notwithstanding, the Trustee
is not authorized to take any action pursuant to a Series O Redemption Demand or
a rescission thereof or a written notice required by this Section 2.08, and such
Series O Redemption Demand, rescission or notice shall be of no force or effect,
unless it is executed in the name of the Series 1993-A Pollution Control Trustee
by one of its Vice Presidents.
SECTION 2.09. Upon payment of the principal of and premium, if any, and
interest on the Series 1993-A Pollution Control Revenue Bonds, whether at
maturity or prior to maturity by redemption or otherwise, and the surrender
thereof to and cancellation thereof by the Series 1993-A Pollution Control
Trustee (other than any Series 1993-A Pollution Control Revenue Bond that was
cancelled by the Series 1993-A Pollution Control Trustee and for which one or
more other Series 1993-A Pollution Control Revenue Bonds were delivered and
authenticated pursuant to the Series 1993-A Pollution Control Indenture), or
upon provision for the payment thereof having been made in accordance with the
Series 1993-A Pollution Control Indenture, Bonds of Pollution Control Series O
in a principal amount equal to the principal amount of the Series 1993-A
Pollution Control Revenue Bonds so surrendered and cancelled or for the
provision for which payment has been made shall be deemed fully paid and the
obligations of the Company thereunder shall be terminated, and such Bonds of
Pollution Control Series O shall be surrendered by the Series 1993-A Pollution
Control Trustee to the Trustee and shall be cancelled and destroyed by the
Trustee, and a certificate of such cancellation and destruction shall be
delivered to the Company.
SECTION 2.10. There is hereby created, for issuance under the
Indenture, a series of bonds designated Pollution Control Series P, each of
which shall bear the descriptive title "First Mortgage Bonds, Pollution Control
Series P" and the form thereof shall contain suitable provisions with respect to
the matters specified in this section. The Bonds of Pollution Control Series P
shall be printed, lithographed or typewritten and shall be substantially of the
tenor and purport previously recited. The Bonds of Pollution Control Series P
shall be issued as registered bonds without coupons in denominations of a
multiple of $5,000 and shall be registered in the name of the Series 1993-B
Pollution Control Trustee. The Bonds of Pollution Control Series P shall be
dated as of the date of their authentication.
The Bonds of Pollution Control Series P shall be payable, both as to
principal and interest, at the office of the Trustee in Chicago, Illinois, in
lawful money of the United States of America. The maturity of the obligation
represented by the Bonds of Pollution Control Series P is September 1, 2019. The
date of maturity of the obligation represented by the Bonds of Pollution Control
Series P is hereinafter referred to as the Series P Final Maturity Date. The
Bonds of Pollution Control Series P shall bear interest from the Series P
Initial Interest Accrual Date, as hereinafter defined, at the same rate or rates
then and thereafter from time to time borne by the Series 1993-B Pollution
Control Revenue Bonds.
SECTION 2.11. Except as provided in the next succeeding paragraph of
this Section 2.11, in the event of a default under Section 8.01 of the Series
1993-B Agreement or in the event of a default in the payment of the principal
of, premium, if any, or interest (and such default in the payment of interest
continues for the full grace
<PAGE>
period, if any, permitted by the Series 1993-B Pollution Control Indenture and
the Series 1993-B Pollution Control Revenue Bonds) on the Series 1993-B
Pollution Control Revenue Bonds, whether at maturity, by acceleration, by
sinking fund, redemption or otherwise, as and when the same becomes due, the
Bonds of Pollution Control Series P shall be redeemable in whole upon receipt by
the Trustee of a written demand (hereinafter called a "Series P Redemption
Demand") from the Series 1993-B Pollution Control Trustee stating that there has
been such a default, stating that it is acting pursuant to the authorization
granted by Section 8.03 of the Series 1993-B Pollution Control Indenture,
specifying the last date to which interest on the Series 1993-B Pollution
Control Revenue Bonds has been paid (such date being hereinafter referred to as
the "Series P Initial Interest Accrual Date") and demanding redemption of the
Bonds of Pollution Control Series P. The Trustee shall, within 10 days after
receiving such Series P Redemption Demand, mail a copy thereof to the Company
marked to indicate the date of its receipt by the Trustee. Promptly upon receipt
by the Company of such copy of a Series P Redemption Demand, the Company shall
fix a date on which it will redeem the Bonds of Pollution Control Series P so
demanded to be redeemed (hereinafter called the "Series P Demand Redemption
Date"). Notice of the date fixed as the Series P Demand Redemption Date shall be
mailed by the Company to the Trustee at least 30 days prior to such Series P
Demand Redemption Date. The date to be fixed by the Company as and for the
Series P Demand Redemption Date may be any date up to and including the earlier
of (i) the 120th day after receipt by the Trustee of the Series P Redemption
Demand or (ii) the Series P Final Maturity Date; PROVIDED that if the Trustee
shall not have received such notice fixing the Series P Demand Redemption Date
within 90 days after receipt by it of the Series P Redemption Demand, the Series
P Demand Redemption Date shall be deemed to be the earlier of (i) the 120th day
after receipt by the Trustee of the Series P Redemption Demand or (ii) the
Series P Final Maturity Date. The Trustee shall mail notice of the Series P
Demand Redemption Date (such notice being hereinafter called the "Series P
Demand Redemption Notice") to the Series 1993-B Pollution Control Trustee not
more than 10 nor less than five days prior to the Series P Demand Redemption
Date. Notwithstanding the foregoing, if a default to which this paragraph is
applicable is existing on the Series P Final Maturity Date, such date shall be
deemed to be the Series 1993-B Demand Redemption Date without further action
(including actions specified in this paragraph) by the Series 1993-B Pollution
Control Trustee, the Trustee or the Company. The Bonds of Pollution Control
Series P shall be redeemed by the Company on the Series P Demand Redemption
Date, upon surrender thereof by the Series 1993-B Pollution Control Trustee to
the Trustee, at a redemption price equal to the principal amount thereof, plus
accrued interest thereon at the rate per annum set forth in Section 2.10 hereof,
from the Series P Initial Interest Accrual Date to the Series P Demand
Redemption Date. If a Series P Redemption Demand is rescinded by the Series
1993-B Pollution Control Trustee by written notice to the Trustee prior to the
Series P Demand Redemption Date, no Series P Demand Redemption Notice shall be
given, or, if already given, shall be automatically annulled, and interest on
the Bonds of Pollution Control Series P shall cease to accrue, all interest
accrued thereon shall be automatically rescinded and cancelled and the Company
shall not be obligated to make any payments of principal of or interest on the
Bonds of Pollution Control Series P; but no such rescission shall extend to or
affect any subsequent default or impair any right consequent thereon.
In the event that all of the bonds outstanding under the Indenture
shall have become immediately due and payable, whether by declaration or
otherwise, and such acceleration shall not have been annulled, the Bonds of
Pollution Control Series P shall bear interest at the rate per annum set forth
in Section 2.10 hereof, from the Series P Initial Interest Accrual Date, as
specified in a written notice to the Trustee from the Series 1993-B Pollution
Control Trustee, and the principal of and interest on the Bonds of Pollution
Control Series P from the Series P Initial Interest Accrual Date shall be
payable in accordance with the provisions of the Indenture.
Anything herein contained to the contrary notwithstanding, the Trustee
is not authorized to take any action pursuant to a Series P Redemption Demand or
a rescission thereof or a written notice required by this Section 2.11, and such
Series P Redemption Demand, rescission or notice shall be of no force or effect,
unless it is executed in the name of the Series 1993-B Pollution Control Trustee
by one of its Vice Presidents.
SECTION 2.12 Upon payment of the principal of and premium, if any, and
interest on the Series 1993-B Pollution Control Revenue Bonds, whether at
maturity or prior to maturity by redemption or otherwise, and the surrender
thereof to and cancellation thereof by the Series 1993-B Pollution Control
Trustee (other than any
<PAGE>
Series 1993-B Pollution Control Revenue Bond that was cancelled by the Series
1993-B Pollution Control Trustee and for which one or more other Series 1993-B
Pollution Control Revenue Bonds were delivered and authenticated pursuant to the
Series 1993-B Pollution Control Indenture), or upon provision for the payment
thereof having been made in accordance with the Series 1993-B Pollution Control
Indenture, Bonds of Pollution Control Series P in a principal amount equal to
the principal amount of the Series 1993-B Pollution Control Revenue Bonds so
surrendered and cancelled or for the provision for which payment has been made
shall be deemed fully paid and the obligations of the Company thereunder shall
be terminated, and such Bonds of Pollution Control Series P shall be surrendered
by the Series 1993-B Pollution Control Trustee to the Trustee and shall be
cancelled and destroyed by the Trustee, and a certificate of such cancellation
and destruction shall be delivered to the Company.
SECTION 2.13 The Series 1989-A Pollution Control Trustee, the Series
1992-A Pollution Control Trustee, the Series 1993-A Pollution Control Trustee
and the Series 1993-B Pollution Control Trustee as the registered holder of the
Bonds of Pollution Control Series M, Bonds of Pollution Control Series N, Bonds
of Pollution Control Series O and Bonds of Pollution Control Series P,
respectively, at its option may surrender the same at the office of the Trustee,
in Chicago, Illinois, or elsewhere, if authorized by the Company, for
cancellation, in exchange for other bonds of the same series of the same
aggregate principal amount. Thereupon, and upon receipt of any payment required
under the provisions of Section 2.14 hereof, the Company shall execute and
deliver to the Trustee and the Trustee shall authenticate and deliver such other
registered bonds to such registered holder at its office or at any other place
specified as aforesaid.
SECTION 2.14 No charge shall be made by the Company for any exchange or
transfer of Bonds of Pollution Control Series M, Bonds of Pollution Control
Series N, Bonds of Pollution Control Series O or Bonds of Pollution Control
Series P other than for taxes or other governmental charges, if any, that may be
imposed in relation thereto.
<PAGE>
ARTICLE III.
FINANCING STATEMENT TO COMPLY WITH THE UNIFORM COMMERCIAL CODE
SECTION 3.01 The name and address of the debtor and secured party are
set forth below:
Debtor: Northern States Power Company
414 Nicollet Mall
Minneapolis, Minnesota 55401
Secured Party: Harris Trust and Savings Bank, Trustee
111 West Monroe Street
Chicago, Illinois 60603
NOTE: Northern States Power Company, the debtor above named, is "a
transmitting utility" under the Uniform Commercial Code as adopted in Minnesota,
North Dakota and South Dakota.
SECTION 3.02 Reference to Article I hereof is made for a description of
the property of the debtor covered by this Financing Statement with the same
force and effect as if incorporated in this Section at length.
SECTION 3.03 The maturity dates and respective principal amounts of
obligations of the debtor secured and presently to be secured by the Indenture,
reference to all of which for the terms and conditions thereof is hereby made
with the same force and effect as if incorporated herein at length, are as
follows:
FIRST MORTGAGE BONDS PRINCIPAL AMOUNT
- -------------------- ----------------
Series due October 1, 1997.............................. $100,000,000
Series due February 1, 1999............................. $200,000,000
Series due October 1, 2001.............................. $150,000,000
Series due December 1, 2000............................. $100,000,000
Series due March 1, 2002................................ $50,000,000
Series due February 1, 2003............................. $50,000,000
Series due April 1, 2003................................ $80,000,000
Series due December 1, 2005............................. $70,000,000
Resource Recovery Series I.............................. $19,800,000
Pollution Control Series J.............................. $5,450,000
Pollution Control Series K.............................. $3,400,000
Pollution Control Series L.............................. $4,850,000
Series due July 1, 2025................................. $250,000,000
Pollution Control Series M.............................. $60,000,000
Pollution Control Series N.............................. $27,900,000
Pollution Control Series O.............................. $50,000,000
Pollution Control Series P.............................. $50,000,000
SECTION 3.04 This Financing Statement is hereby adopted for all of the
First Mortgage Bonds of the series mentioned above secured by said Indenture.
SECTION 3.05 The 1937 Indenture and the prior Supplemental Trust
Indentures, as set forth below, have been filed or recorded in each and every
office in the States of Minnesota, North Dakota, and South Dakota designated by
law for the filing or recording thereof in respect of all property of the
Company subject thereto:
Original Indenture Supplemental Indenture
Dated February 1, 1937 Dated June 1, 1952
Supplemental Indenture Supplemental Indenture
Dated June 1, 1942 Dated October 1, 1954
Supplemental Indenture Supplemental Indenture
Dated February 1, 1944 Dated September 1, 1956
<PAGE>
Supplemental Indenture Supplemental Indenture
Dated August 1, 1957 Dated September 1, 1984
Supplemental Indenture Supplemental Indenture
Dated July 1, 1958 Dated December 1, 1984
Supplemental Indenture Supplemental Indenture
Dated December 1, 1960 Dated May 1, 1985
Supplemental Indenture Supplemental Indenture
Dated August 1, 1961 Dated September 1, 1985
Supplemental Indenture Supplemental Indenture
Dated June 1, 1962 Dated May 1, 1988
Supplemental Indenture Supplemental Indenture
Dated September 1, 1963 Dated July 1, 1989
Supplemental Indenture Supplemental Indenture
Dated August 1, 1966 Dated October 1, 1969
Supplemental Indenture Supplemental Indenture
Dated June 1, 1967 Dated February 1, 1971
Supplemental Indenture Supplemental Indenture
Dated October 1, 1967 Dated May 1, 1971
Supplemental Indenture Supplemental Indenture
Dated May 1, 1968 Dated February 1, 1972
Supplemental Indenture Supplemental Indenture
Dated October 1, 1945 Dated January 1, 1973
Supplemental Indenture Supplemental Indenture
Dated July 1, 1948 Dated January 1, 1974
Supplemental Indenture Supplemental Indenture
Dated August 1, 1949 Dated September 1, 1974
Supplemental Indenture Supplemental Indenture
Dated April 1, 1975 Dated June 1, 1990
Supplemental Indenture Supplemental Indenture
Dated May 1, 1975 Dated October 1, 1992
Supplemental Indenture Supplemental Indenture
Dated March 1, 1976 Dated April 1, 1993
Supplemental Indenture Supplemental Indenture
Dated June 1, 1981 Dated December 1, 1993
Supplemental Indenture Supplemental Indenture
Dated December 1, 1981 Dated February 1, 1994
Supplemental Indenture Supplemental Indenture
Dated May 1, 1983 Dated October 1, 1994
Supplemental Indenture Supplemental Indenture
Dated December 1, 1983 Dated June 1, 1995
SECTION 3.06 The property covered by this Financing Statement also
shall secure additional series of First Mortgage Bonds of the debtor which may
be issued from time to time in the future in accordance with the provisions of
the Indenture.
<PAGE>
ARTICLE IV.
AMENDMENTS TO INDENTURE
SECTION 4.01 Each holder or registered owner of a bond of any series
originally authenticated by the Trustee and originally issued by the Company
subsequent to May 1, 1985 and of any coupon pertaining to any such bond, by the
acquisition, holding or ownership of such bond and coupon, thereby consents and
agrees to, and shall be bound by, the provisions of Article VI of the
Supplemental Trust Indenture dated May 1, 1985. Each holder or registered owner
of a bond of any series (including Bonds of Pollution Control Series M, Bonds of
Pollution Control Series N, Bonds of Pollution Control Series O and Bonds of
Pollution Control Series P) originally authenticated by the Trustee and
originally issued by the Company subsequent to May 1, 1988 and of any coupon
pertaining to such bond, by the acquisition, holding or ownership of such bond
and coupon, thereby consents and agrees to, and shall be bound by, the
provisions of the Supplemental and Restated Trust Indenture dated May 1, 1988
upon the Effective Date.
ARTICLE V.
MISCELLANEOUS
SECTION 5.01 The recitals of fact herein, except the recital that the
Trustee has duly determined to execute this Supplemental Trust Indenture and be
bound, insofar as it may lawfully so do, by the provisions hereof and in the
bonds shall be taken as statements of the Company and shall not be construed as
made by the Trustee. The Trustee makes no representations as to the value of any
of the property subject to the lien of the Indenture, or any part thereof, or as
to the title of the Company thereto, or as to the security afforded thereby and
hereby, or as to the validity of this Supplemental Trust Indenture or of the
bonds issued under the Indenture by virtue hereof (except the Trustee's
certificate) and the Trustee shall incur no responsibility in respect of such
matters.
SECTION 5.02 This Supplemental Trust Indenture shall be construed in
connection with and as a part of the 1937 Indenture, as supplemented by the
Supplemental Trust Indentures dated June 1, 1942, February 1, 1944, October 1,
1945, July 1, 1948, August 1, 1949, June 1, 1952, October 1, 1954, September 1,
1956, August 1, 1957, July 1, 1958, December 1, 1960, August 1, 1961, June 1,
1962, September 1, 1963, August 1, 1966, June 1, 1967, October 1, 1967, May 1,
1968, October 1, 1969, February 1, 1971, May 1, 1971, February 1, 1972, January
1, 1973, January 1, 1974, September 1, 1974, April 1, 1975, May 1, 1975, March
1, 1976, June 1, 1981, December 1, 1981, May 1, 1983, December 1, 1983,
September 1, 1984, December 1, 1984, May 1, 1985, September 1, 1985, the
Supplemental and Restated Trust Indenture dated May 1, 1988 and the Supplemental
Trust Indentures dated July 1, 1989, June 1, 1990, October 1, 1992, April 1,
1993, December 1, 1993, February 1, 1994, October 1, 1994, June 1, 1995 and
April 1, 1997.
SECTION 5.03 (a) If any provision of this Supplemental Trust Indenture
limits, qualifies or conflicts with another provision of the Indenture required
to be included in indentures qualified under the Trust Indenture Act of 1939, as
amended (as enacted prior to the date of this Supplemental Trust Indenture) by
any of the provisions of Sections 310 to 317, inclusive, of the said Act, such
required provision shall control.
(b) In case any one or more of the provisions contained in this
Supplemental Indenture or in the bonds issued hereunder shall be invalid,
illegal, or unenforceable in any respect, the validity, legality and
enforceability of the remaining provisions contained herein and therein shall
not in any way be affected, impaired, prejudiced or disturbed thereby.
SECTION 5.04 Wherever in this Supplemental Trust Indenture the word
"Indenture" is used without either prefix, "1937", "Original" or "Supplemental",
such word was used intentionally to include in its meaning both the 1937
Indenture and all indentures supplemental thereto.
SECTION 5.05 Wherever in this Supplemental Trust Indenture either of
the parties hereto is named or referred to, this shall be deemed to include the
successors or assigns of such party, and all the covenants and
<PAGE>
agreements in this Supplemental Trust Indenture contained by or on behalf of the
Company or by or on behalf of the Trustee shall bind and inure to the benefit of
the respective successors and assigns of such parties, whether so expressed or
not.
SECTION 5.06 (a) This Supplemental Trust Indenture may be
simultaneously executed in several counterparts, and all said counterparts
executed and delivered, each as an original, shall constitute but one and the
same instrument.
(b) The Table of Contents and the descriptive headings of the several
Articles of this Supplemental Trust Indenture were formulated, used and inserted
in this Supplemental Trust Indenture for convenience only and shall not be
deemed to affect the meaning or construction of any of the provisions hereof.
-------
The amount of obligations to be issued forthwith under the Indenture is
$187,900,000.
-------
<PAGE>
IN WITNESS WHEREOF, on this 10th day of April, A.D. 1997, NORTHERN
STATES POWER COMPANY, a Minnesota corporation, party of the first part, has
caused its corporate name and seal to be hereunto affixed and this Supplemental
Trust Indenture dated April 1, 1997, to be signed by its President or a Vice
President, and attested by its Secretary or an Assistant Secretary, for and in
its behalf, and HARRIS TRUST AND SAVINGS BANK, an Illinois corporation, as
Trustee, party of the second part, to evidence its acceptance of the trust
hereby created, has caused its corporate name and seal to be hereunto affixed,
and this Supplemental Trust Indenture dated April 1, 1997, to be signed by its
President, a Vice President, or an Assistant Vice President, and attested by its
Secretary or an Assistant Secretary, for and in its behalf.
NORTHERN STATES POWER COMPANY
/s/ EDWARD J. MCINTYRE
BY: EDWARD J. MCINTYRE, VICE PRESIDENT
Attest:
(CORPORATE SEAL)
/s/ GARY R. JOHNSON
GARY R. JOHNSON, SECRETARY
Executed by Northern States
Power Company in the presence of:
/s/ MARY SCHELL
MARY SCHELL, WITNESS
/s/ DEAN SCHAFER
DEAN SCHAFER, WITNESS
HARRIS TRUST AND SAVINGS BANK,
as Trustee
/s/ J. BARTOLINI
BY: J. BARTOLINI, VICE PRESIDENT
Attest:
(CORPORATE SEAL)
/s/ D.G. DONOVAN
D.G. DONOVAN, ASSISTANT SECRETARY
Executed by Harris Trust and Savings
Bank in the presence of:
/s/ K. RICHARDSON
K. RICHARDSON, WITNESS
/s/ R. JOHNSON
R. JOHNSON, WITNESS
<PAGE>
STATE OF MINNESOTA ss.:
COUNTY OF HENNEPIN
On this 10th day of April A.D. 1997, before me, FAYE WAHLSTRAND, a
Notary Public in and for said County in the State aforesaid, personally appeared
Edward J. McIntyre, and Gary R. Johnson, to me personally known, and to me known
to be the Vice President and Secretary, respectively, of Northern States Power
Company, one of the corporations described in and which executed the within and
foregoing instrument, and who, being by me severally duly sworn, each for
himself, did say that he, the said Edward J. McIntyre is a Vice President, and
he, the said Gary R. Johnson is the Secretary, of said Northern States Power
Company, a corporation; that the seal affixed to the within and foregoing
instrument is the corporate seal of said corporation, and that said instrument
was executed on behalf of said corporation by authority of its stockholders and
board of directors; and said Edward J. McIntyre and Gary R. Johnson each
acknowledged said instrument to be the free act and deed of said corporation and
that such corporation executed the same.
WITNESS my hand and notarial seal, this 10th day of April, A.D. 1997.
/s/ FAYE WAHLSTRAND
FAYE WAHLSTRAND
NOTARY PUBLIC IN HENNEPIN COUNTY, MINNESOTA.
MY COMMISSION EXPIRES JANUARY 31, 2000
FAYE WAHLSTRAND
NOTARY PUBLIC - MINNESOTA
HENNEPIN COUNTY
MY COMMISSION EXPIRES 1-31-2000
(NOTARY SEAL)
STATE OF MINNESOTA ss.:
COUNTY OF HENNEPIN
Edward J. McIntyre and Gary R. Johnson, being severally duly sworn,
each deposes and says that he, the said Edward J. McIntyre is Vice President,
and he, the said Gary R. Johnson is Secretary, of Northern States Power Company,
the corporation described in and which executed the within and foregoing
Supplemental Trust Indenture, as mortgagor; and each for himself further says
that said Supplemental Trust Indenture was executed in good faith, and not for
the purpose of hindering, delaying, or defrauding any creditor of the said
mortgagor.
/s/ EDWARD J. MCINTYRE
EDWARD J. MCINTYRE
/s/ GARY R. JOHNSON
GARY R. JOHNSON
Subscribed and sworn to before me this 10th day of April, A.D. 1997.
/s/ FAYE WAHLSTRAND
FAYE WAHLSTRAND
NOTARY PUBLIC, HENNEPIN COUNTY, MINN.
MY COMMISSION EXPIRES JANUARY 31, 2000
FAYE WAHLSTRAND
NOTARY PUBLIC - MINNESOTA
HENNEPIN COUNTY
MY COMMISSION EXPIRES 1-31-2000
(NOTARY SEAL)
<PAGE>
STATE OF ILLINOIS ss.:
COUNTY OF COOK)
On this 10th day of April, A.D. 1997, before me, T. MUZQUIZ, a Notary
Public in and for said County in the State aforesaid, personally appeared J.
BARTOLINI and D.G. DONOVAN to me personally known, and to me known to be the
Vice President and Assistant Secretary, respectively, of Harris Trust and
Savings Bank, one of the corporations described in and which executed the within
and foregoing instrument, and who, being by me severally duly sworn, each, did
say that she, the said J. BARTOLINI is a Vice President, and he, the said D.G.
DONOVAN, is the Assistant Secretary, of said Harris Trust and Savings Bank, a
corporation; that the seal affixed to the within and foregoing instrument is the
corporate seal of said corporation, and that said instrument was executed on
behalf of said corporation by authority of its board of directors; and said J.
BARTOLINI and D.G. DONOVAN each acknowledged said instrument to be the free act
and deed of said corporation and that such corporation executed the same.
WITNESS my hand and notarial seal, this 10th day of April, A.D. 1997.
/s/ T. MUZQUIZ
T. MUZQUIZ
NOTARY PUBLIC, COOK COUNTRY, ILLINOIS.
MY COMMISSION EXPIRES JULY 12, 1997.
(NOTARY SEAL)
STATE OF ILLINOIS ss.:
COUNTY OF COOK
J. BARTOLINI and D.G. DONOVAN, being severally duly sworn, each for
himself deposes and says that she, the said J. BARTOLINI, is Vice President, and
he, the said D.G. DONOVAN, is Assistant Secretary, of Harris Trust and Savings
Bank, the corporation described in and which executed the within and foregoing
Supplemental Trust Indenture, as mortgagee; and each for himself further says
that said Supplemental Trust Indenture was executed in good faith, and not for
the purpose of hindering, delaying, or defrauding any creditor of the mortgagor.
J. BARTOLINI /s/ J. BARTOLINI
D.G. DONOVAN /s/ D.G. DONOVAN
Subscribed and sworn to before me this 10th day of April, A.D. 1997.
/s/ T. MUZQUIZ
T. MUZQUIZ
NOTARY PUBLIC, COOK COUNTY, ILLINOIS.
MY COMMISSION EXPIRES JULY 12, 1997
(NOTARY SEAL)
<PAGE>
SCHEDULE A
The property referred to in Article I of the foregoing Supplemental
Trust Indenture from Northern States Power Company to Harris Trust and Savings
Bank, Trustee, made as of April 1, 1997, includes the following property
hereafter more specifically described. Such description, however, is not
intended to limit or impair the scope of intention of the general description
contained in the granting clauses or elsewhere in the Original Indenture.
I. PROPERTIES IN THE STATE OF MINNESOTA
The following described real property, situate, lying and being in the
County of Dakota, to-wit:
(1) That part of the NE1/4 of the SE1/4 of Section 30, Township
115 North, Range 17 West described as follows: Commencing at
the Northeast corner of said quarter-quarter; thence South
along the East line thereof 153.90 feet to the South
right-of-way line of Trunk Highway No. 55 and the point of
beginning of the land to be described; thence continuing South
along said East line 603.00 feet; thence deflecting 90 degrees
00 minutes 00 seconds right 495.00 feet; thence deflecting 90
degrees 00 minutes 00 seconds right to said South highway
right-of-way line; thence East along said highway right-of-way
line to the point of beginning. Excepting and reserving unto
Seller, their heirs and assigns, the perpetual right,
privilege and easement to construct improve, use, maintain and
dedicate to the public a roadway upon the North 125 feet and
the East 40 feet of the above-described parcel of land
provided that said roadways do not interfere with NSP's
electrical facilities, landscaping or right of access to the
land granted herein.
The following described real property; situate, lying and being in the
County of Hennepin, to-wit:
(1) Lot 1, Block 1, Schany 2nd Addition.
The following described real property; situate, lying and being in the
County of Murray, to-wit:
(1) The North 220 feet of the East 200 feet of the West 235 feet
of the NE1/4 of Section 24, Township 106 North, Range 43 West.
The following described real property; situate, lying and being in the
County of Rice, to-wit:
(1) Lot 1, Block 1, Cannon Road Substation.
The following described real property; situate, lying and being in the
County of Sherburne, to-wit:
(1) The SW1/4 of Section 6, Township 33 North, Range 28 West,
excepting therefrom the West 500 feet of the SW1/4 of the
SW1/4 of said Section 6.
And
The NE1/4 of the NW1/4 of Section 7, Township 33 North, Range
28 West, excepting therefrom the East 153 feet of the North
163 feet.
(2) Beginning at the Northwest corner of the NE1/4 of Section 35,
Township 34 North, Range 29 West; thence North 89 degrees 07
minutes 33 seconds East along the North line of said NE1/4 of
Section 35 (assumed bearing) a distance of 495.01 feet; thence
South 00 degrees 10 minutes 53 seconds West a distance of
440.07 feet to the South line of the North 440 feet of the
NW1/4 of the NE1/4; thence South 89 degrees 07 minutes 33
seconds West a distance of 495.02 feet to the West line of the
NE1/4 of Section 35; thence North 00 degrees 10 minutes 53
seconds East along said West line to the point of beginning,
and there terminating.
And
Commencing at the Northwest corner of the NE1/4 of Section 35,
Township 34 North, Range 29 West; thence North 89 degrees 07
minutes 33 seconds East along the North line of said NE1/4 of
Section 35 (assumed bearing) a distance of 819.97 feet to the
point of beginning of the land to be described;
<PAGE>
thence continuing North 89 degrees 07 minutes 33 seconds East
a distance of 497.96 feet to the East line of the NW1/4 of the
NE1/4 of said Section 35; thence South 00 degrees 11 minutes
30 seconds West along the East line of said NW1/4 of the NE1/4
a distance of 440.07 feet to the South line of the North 440
feet thereof; thence South 89 degrees 07 minutes 33 seconds
West a distance of 495.00 feet; thence North 00 degrees 11
minutes 31 seconds East a distance of 440.07 feet to the point
of beginning and there terminating.
The following described real property; situate, lying and being in the
County of Washington, to-wit:
(1) Lots Nine (9) and Ten (10), Block Eight (8), of OAK PARK.
(2) All that part of the Northwest Quarter of the Northwest
Quarter (NW1/4 of the NW1/4) of Section Three (3), in Township
Twenty-nine (29) North, of Range Twenty (20) West of the
Fourth Meridian, described as follows, to-wit:
Beginning at an iron monument set at the intersection
of the Southerly right-of-way line of Minnesota State
Highway 212 with a line drawn parallel to and Three
Hundred Seventy-nine and Two-tenths (379.2) feet East
of the West line of said tract, and running thence
South along said parallel line One Hundred (100) feet
to an iron monument; thence Easterly on a straight
line to an iron monument; said monument being set on
a line drawn parallel to and Five Hundred
Ninety-seven (597) feet East of said West line of
said tract, at a point One Hundred (100) feet South
of the intersection of said parallel line with said
Southerly right-of-way line of said highway; thence
North along said parallel line just described One
Hundred (100) feet to an iron monument set on said
Southerly right-of-way line of said highway; thence
Westerly along said right of way line to the point of
beginning, containing Five-tenths (0.5) acres, more
or less, according to the United States Government
Survey thereof.
The following described real property; situate, lying and being in the
County of Waseca, to-wit:
(1) Lot Five (5), Block One (1), South Addition to the City of
Waseca, and the West (10) feet of the South Fifty (50) feet of
Lot Four (4), in Block One (1), South Addition to the City of
Waseca.
<PAGE>
-------
MORTGAGOR'S RECEIPT FOR COPY
The undersigned Northern States Power Company, the Mortgagor described
in the foregoing Mortgage, hereby acknowledges that at the time of the execution
of the Mortgage, Harris Trust and Savings Bank, Trustee, the Mortgagee described
therein, surrendered to it a full, true, complete, and correct copy of said
instrument, with signatures, witnesses, and acknowledgments thereon shown.
NORTHERN STATES POWER COMPANY
/s/ EDWARD J. MCINTYRE
BY EDWARD J. MCINTYRE, VICE PRESIDENT
Attest:
/s/ GARY R. JOHNSON
GARY R. JOHNSON, SECRETARY
-------
This instrument was drafted by Northern States Power Company, 414
Nicollet Mall, Minneapolis, Minnesota 55401.
Tax statements for the real property described in this instrument
should be sent to Northern States Power Company, 414 Nicollet Mall, Minneapolis,
Minnesota 55401.
Exhibit 10.15
STOCK EQUIVALENT PLAN
FOR NON-EMPLOYEE DIRECTORS OF
NORTHERN STATES POWER COMPANY
(As Amended and Restated Effective October 1, 1997)
ARTICLE I
PURPOSE, DEFINITIONS AND GENERAL PROVISIONS
1.1. PURPOSE. The purposes of this Plan are: (a) to cause a portion of the
compensation of each non-employee director of Northern States Power Company
("NSP") to be paid in equivalents of common stock of the Company; and (b) to
permit each director to defer receipt of all or a portion of his/her retainer,
board or committee meeting fees.
1.2. DEFINITIONS.
(a) "AWARD" shall mean the amount, expressed either in dollars of
Compensation or in Stock Equivalents, that will be credited to
a Participant on an Award Date. The term "Award" includes
Conversion Awards, Deferral Awards and Discretionary Awards.
(b) "AWARD DATE" shall mean the date an Award is to be credited to
a Participant.
(c) "BOARD" shall mean the Board of Directors of the Company.
(d) "BENEFICIARY" shall mean the person or persons (including,
without limitation, the trustees of any testamentary or inter
vivos trust,) designated from time to time in writing by a
Participant to receive payments under the Plan after the death
of such Participant, or, in the absence of any such
designation or in the event that such designated persons or
person shall predecease such Participant, or shall not be in
existence or shall otherwise be unable to receive such
payments, the person or persons designated under such
Director's last will and testament or, in the absence of such
designation, to the Participant's estate.
(e) "COMMITTEE" shall mean those management members of the
Company, namely the Chairman of the Board, President, Chief
Financial Officer and Corporate Secretary, who administer the
Plan, provided all such persons
<PAGE>
are not eligible to participate in the Plan. All decisions by
the Committee shall be by simple majority and the decisions
will be final.
(f) "COMPANY" shall mean Northern States Power Company, a
Minnesota corporation, and any successor thereof.
(g) "COMPENSATION" shall mean payments which the Director receives
from the Company for services as a member of its Board of
Directors. Such payments may include directors' retainers,
board meeting fees and committee meeting fees, but shall
exclude direct reimbursement of expenses.
(h) "CONVERSION AWARD" shall mean a one-time Award made to a
Director in lieu of benefits earned by that Director under the
Northern States Power Company Retirement Plan for Non-Employee
Directors, pursuant to an election described in Section 1.5
hereof.
(i) "DEFERRAL AWARD" shall mean an Award made pursuant to a
deferral election described in Section 1.4 hereof.
(j) "DIRECTOR" shall mean any member of the Board of Directors of
the Company who is not an employee of the Company.
(k) "DISCRETIONARY AWARD" shall mean an Award made at the sole
discretion of the Board pursuant to Section 1.3 of this Plan.
(l) "NSP STOCK" shall mean the common stock of the Company, par
value $2.50 per share.
(m) "PARTICIPANT" shall mean any Director who receives an Award.
(n) "PLAN" shall mean the Stock Equivalent Plan for Non-Employee
Directors of the Company, as from time to time amended and in
effect.
(o) "STOCK ACCOUNT" shall mean the account to which Awards are
credited in the name of a Participant as described in Section
2.2 of this Plan.
(p) "STOCK EQUIVALENTS" shall mean the units, representing a like
number of shares of NSP Stock, that are credited to a
Director's Stock Account under Sections 2.1 and 2.2 of this
Plan.
(q) "TERMINATION OF SERVICE" shall mean the termination (by death,
retirement or otherwise) of a Participant's service as a
Director of the Company.
<PAGE>
1.3. DISCRETIONARY AWARDS. The amount and number of Discretionary Awards that
may be granted under this Plan is subject to the sole discretion of the Board
and shall be determined in the sole discretion of the Board. Each Award shall
contain such terms, restrictions and conditions as the Board may determine that
are not inconsistent with this Plan. Discretionary Awards shall be made in Stock
Equivalents or as a dollar amount, as determined in the sole discretion of the
Board.
1.4. DEFERRAL AWARDS. In accordance with this Section, a Director may elect to
receive Deferral Awards in lieu of all or a portion of his/her Compensation by
filing with the Secretary of the Company an election in writing on a form
approved by the Committee. Deferral Awards shall be made as of the date such
Compensation would have been paid, in a dollar amount equal to the amount of
Compensation the Director has elected to defer. A deferral election with respect
to Compensation for a calendar year must be made prior to the beginning of that
calendar year. No election may be made for the calendar year in which a Director
is first elected to the Board. A deferral election shall continue in effect
until the Director's Termination of Service or, if the Director provides the
Secretary of the Company with earlier written notice to discontinue the deferral
election, at the end of the calendar year in which such written notice is
received by the Secretary.
1.5. CONVERSION AWARDS. In lieu of all benefits otherwise payable under the
Northern States Power Company Retirement Plan for Non-Employee Directors
("Retirement Plan"), any Director elected to the Board prior to October 1, 1997
and serving on the Board during the last quarter of 1997 may make a one-time
election to receive a Conversion Award under this Plan in a dollar amount equal
to the sum of the quarterly retainer payments the Director would have been
entitled to receive under the Retirement Plan if the Director's service on the
Board ended December 31, 1997. Any such election must be made in writing on a
form approved by the Committee for that purpose, and shall be irrevocable. Any
such election will not be effective unless it is received by the Corporate
Secretary on or before December 31, 1997, and prior to termination of the
Director's service on the Board. The Award Date for a Conversion Award under
this Plan in satisfaction of a Director's conversion election shall be January
1, 1998.
ARTICLE II
TREATMENT OF AWARDS
2.1. STOCK ACCOUNTS. The Company shall establish on its books a Stock Account in
the name of each Participant accurately to reflect the Company's liability to
each Participant who has received an Award. To this Stock Account shall be
credited Awards plus other items as described hereafter. Payments to a
Participant or Beneficiary following Termination of Service shall be debited to
the Stock Account. In addition, debits and credits to the Stock Account shall be
made in the manner provided hereafter. Despite the maintenance of such Stock
Account for each Participant, the Company's obligation to make distributions
under the Plan shall be made
<PAGE>
from the Company's general assets and property. The Company may, in its sole
discretion, establish a separate fund or account to make payment to a
Participant or Beneficiary hereunder. Whether the Company, in its sole
discretion, does establish such a fund or account, no Participant or Beneficiary
or any person shall have, under any circumstances, any interest whatever in any
particular property or assets of the Company by virtue of this Plan.
2.2. CREDITING OF AWARDS. Awards in the form of Stock Equivalents shall be
credited to a Participant's Stock Account. Awards in dollars shall also be
credited to a Participant's Stock Account by converting the dollar amount of the
Award into Stock Equivalents equal to the number of shares of NSP Stock, to
three decimal places, that could be purchased on the Award Date with the dollar
amount of such Award, at a price per share equal to the arithmetical mean of the
highest and lowest quoted selling prices on the New York Stock Exchange
Composite Tape for such day. If there are no sales on that day, such mean on the
next preceding day on which there are such sales shall be used.
2.3 CREDITING OF DIVIDENDS/STOCK SPLITS.
(a) On each date on which a dividend in cash or property is distributed
by the Company on shares of issued and outstanding NSP Stock, the Stock Account
of a Participant shall be credited with Stock Equivalents as follows: (i) the
dollar amount of the fair market value of the cash or property so distributed
per share of issued and outstanding NSP Stock shall be multiplied by the number
of Stock Equivalents (including fractions) in the Participant's Stock Account on
the record date for such distribution; (ii) this dollar amount shall then be
converted into Stock Equivalents equal to the number of shares of NSP Stock, to
three decimal places, that could be purchased on the payment date for such
distribution by dividing such dollar amount by a price per share equal to the
arithmetical mean of the highest and lowest quoted selling prices on the New
York Stock Exchange Composite Tape for such date, or, if there are no sales on
that date, such mean on the next preceding day on which there are such sales
shall be used.
(b) On each date on which a stock dividend or stock split is
distributed with respect to shares of NSP Stock, a Participant's Stock Account
shall be credited with the number of Stock Equivalents equal to the product of
(x) the number of shares which would have been distributed per share of issued
and outstanding NSP Stock and (y) the number of Stock Equivalents (including
fractions) in the Participant's Stock Account on the record date for such
distribution.
2.4 CONVERSION OF STOCK EQUIVALENTS. If the Company shall be a party to any
consolidation or merger or share exchange and, in connection with such
transaction, all or part of the outstanding shares of NSP Stock shall be changed
into or exchanged for stock or other securities of any other entity or the
Company or cash or any other property, on the day immediately preceding the
effective date of such transaction, the Stock Equivalents in a Participant's
Stock Account shall be converted into the appropriate number of stock
equivalents of such other entity.
2.5. TIME OF PAYMENT OF AWARDS.
<PAGE>
(a) Except as provided in Section 2.7, Awards shall not be payable to a
Participant prior to the Participant's Termination of Service.
(b) Upon Termination of Service, the portion of a Participant's
aggregate account balance in his/her Stock Account that is attributable to any
Conversion Award and to any other Award credited to the Stock Account prior to
December 31, 1997 shall be paid in a single distribution of NSP Stock to the
Participant (or, in the event of the Participant's death, his/her beneficiary)
within 90 days after the date of Termination of Service.
(c) Except as provided in subsections (d) and (e) below, the remainder
of a Participant's Stock Account shall be paid in the manner selected by the
Participant from the distribution alternatives established by the Committee. A
Participant may only make one distribution election. For a Participant elected
to the Board prior to October 1, 1997, the distribution election shall be made
prior to January 1, 1998. For a Participant elected to the Board after October
1, 1997, the distribution election shall be made within 60 days of his/her
election to the Board. The distribution election must be made in writing on a
form approved by the Committee. Once made, the distribution election shall be
irrevocable. A Participant's distribution election shall apply only to the
portion of the Participant's Stock Account that is attributable to Discretionary
Awards credited to the Participant's Stock Account after the date on which the
distribution election is made and to Deferral Awards attributable entirely to
Compensation earned after the date of the election.
(d) Any portion of a Participant's Stock Account for which no
distribution election has been made shall be paid in a single distribution of
NSP Stock to the Participant (or, in the event of the Participant's death,
his/her beneficiary) within 90 days after the date of Termination of Service.
(e) Notwithstanding any distribution election made by a Participant, in
the event of a Participant's death prior to distribution in full of a
Participant's Stock Account, the entire remaining balance in the Participant's
Stock Account shall be paid in a single distribution to the Participant's
beneficiary.
2.6. FORM OF PAYMENT. Awards shall be payable to a Participant only as a
distribution of whole shares of NSP Stock equal to the number of whole Stock
Equivalents credited to the Participant's Stock Account, and cash for any
partial Stock Equivalents. The shares of NSP Stock to be used for distribution
under this plan shall be shares purchased on the open market. In converting a
Participant's partial Stock Equivalents in his/her Stock Account into cash for
payment purposes, such conversion shall be based on the then current market
value of the partial shares of NSP Stock reflected in his/her Stock Account. For
purposes of the preceding sentence, market value shall be the arithmetical mean
between the highest and lowest quoted selling prices for NSP Stock on the New
York Stock Exchange Composite Tape on the date immediately preceding the payment
date. If there are no sales on that day, then such mean on the next preceding
day on which there are such sales shall be used. Upon request, the Company will
reimburse a Participant for any expenses actually incurred by the Participant
for the sale of shares
<PAGE>
distributed to the Participant under this Plan, provided such request and sale
occur within one year after the Participant receives the distribution.
2.7. ACCELERATION OF PAYMENTS. In the event of a Participant's disability, the
Committee, within its sole discretion, is empowered to accelerate the payment of
such Participant's Stock Account balance to such Participant prior to
Termination of Service.
ARTICLE III
OTHER PROVISIONS
3.1. AMENDMENT OR TERMINATION. The Board of Directors may amend or terminate
this Plan at any time; provided, however, that no amendment or termination shall
adversely affect any prior Awards or rights under this Plan, and provided
further that no amendment may be made to the last sentence of Section 3.5
hereof.
3.2. EXPENSES. The expenses of administering the Plan shall be borne by the
Company, and shall not be charged against any Participant's Awards.
3.3. APPLICABLE LAW. The provisions of the Plan shall be construed, administered
and enforced according to the laws of the State of Minnesota.
3.4. NO TRUST. No action by the Company, the Board or the Committee under this
Plan shall be construed as creating a trust, escrow or other secured or
segregated fund or other fiduciary relationship of any kind in favor of any
Participant, Beneficiary, or any other persons otherwise entitled to Awards. The
status of the Participant and Beneficiary with respect to any liabilities
assumed by the Company hereunder shall be solely those of unsecured creditors of
the Company. Any asset acquired or held by the Company in connection with
liabilities assumed by it hereunder, shall not be deemed to be held under any
trust, escrow or other secured or segregated fund or other fiduciary
relationship of any kind for the benefit of the Participant or Beneficiary or to
be security for the performance of the obligations of the Company, but shall be,
and remain, a general, unpledged, unrestricted asset of the Company at all times
subject to the claims of general creditors of the Company.
3.5. NO ASSIGNABILITY AND SUCCESSORS. Neither the Participant nor any other
person shall acquire any right to or interest in any amount awarded to the
Participant, otherwise than by actual payment in accordance with the provisions
of this Plan, or have any power, voluntarily or involuntarily, to transfer,
assign, anticipate, pledge, mortgage or otherwise encumber, alienate or transfer
any rights hereunder in advance of any of the payments to be made pursuant to
this Plan or any portion thereof. The obligations of the Company hereunder shall
be binding upon any and all successors and assigns of the Company.
<PAGE>
3.6. WITHHOLDING. The Company shall comply with all federal and state laws and
regulations with respect to the withholding, deposit and payment of any income
taxes relating to the payment of Awards under this Plan.
3.7. NO IMPACT ON DIRECTORSHIP. This Plan shall not be construed to confer any
right on the part of a Participant to be or remain a Director or to receive any,
or any particular rate of, Compensation.
3.8. INTERPRETATIONS. The Committee shall administer this Plan and shall have
discretionary authority to construe and interpret the terms of this Plan, and to
establish such rules and procedures for implementing the Plan as it deems
necessary or advisable. Interpretations of, and determinations related to, this
Plan made by the Committee in good faith, including any determinations or
calculations of Awards or Stock Account balances, shall be conclusive and
binding upon all parties; and the Company and the members of the Committee shall
not incur any liability to a Participant for any such interpretation or
determination so made or for any other action taken by it in connection with
this Plan.
3.9. SHAREHOLDER RIGHTS. Directors shall not be deemed for any purpose to be or
have rights as shareholders of the Company with respect to any Stock Equivalents
credited to a Stock Account, until and unless a certificate for NSP Stock is
issued upon distribution hereunder.
3.10. SECURITIES LAWS. NSP Stock shall not be distributed to a Participant upon
distribution of his/her Stock Account unless the issuance complies with all
relevant provisions of law, including without limitation, (i) securities laws of
Minnesota or any other appropriate state, (ii) restrictions, if any, imposed by
the Securities Act of 1933 and the Securities Exchange Act of 1934 and rules and
regulations promulgated thereunder by the Securities & Exchange Commission
("SEC"), (iii) rules of any stock exchange on which shares of NSP Stock are
listed, and (iv) until the sale of such NSP Stock has been registered with the
SEC.
3.11. EFFECTIVE DATE. This Plan was first established and effective on April 23,
1996. This amended and restated Plan is effective as of October 1, 1997. Except
as otherwise specifically provided, payments to a Director whose service as a
Director ends prior to October 1, 1997, shall be determined under the terms of
the Plan as in effect when his/her service as a Director terminated (and not
under the terms of this amended and restated Plan).
NORTHERN STATES POWER COMPANY
BY: /s/
------------------------------
James J. Howard,
Chairman of the Board
Exhibit 12.01
NORTHERN STATES POWER COMPANY AND SUBSIDIARY COMPANIES
STATEMENT OF COMPUTATION OF
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
Earnings 1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Income from continuing (Thousands of dollars)
operations before accounting
change $ 237,320 $ 274,539 $ 275,795 $ 243,475 $ 211,740
Add
Taxes based on income (1)
Federal income taxes 105,733 153,515 142,492 112,611 99,952
State income taxes 23,008 40,635 34,988 35,746 28,076
Deferred income taxes-net (5,902) (30,561) (11,076) (6,100) 12,256
Tax credits - net (26,365) (17,395) (14,409) (13,049) (9,544)
Foreign income taxes 236 616 233 219
Fixed charges 169,377 141,961 133,328 115,083 113,562
Deduct
Undistributed equity in earnings of
unconsolidated affiliates (2) 5,364 25,976 41,870 23,588 1,142
--------- --------- --------- --------- ---------
Earnings $ 498,043 $ 537,334 $ 519,481 $ 464,397 $ 454,900
========= ========= ========= ========= =========
Fixed charges:
Interest charges, excluding AFC - debt,
per statement of income 154,940 141,961 133,328 115,083 113,562
Distributions on redeemable preferred
securities of subsidiary trust 14,437 -- -- -- --
--------- --------- --------- --------- ---------
Total fixed charges $ 169,377 $ 141,961 $ 133,328 $ 115,083 $ 113,562
========= ========= ========= ========= =========
Ratio of earnings to fixed
charges 2.9 3.8 3.9 4.0 4.0
========= ========= ========= ========= =========
</TABLE>
(1) Includes income taxes included in Other Income (Expense).
(2) Includes losses of unconsolidated affiliates accounted for under the equity
method.
Exhibit 21.01
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
Subsidiaries of Registrant*
<TABLE>
<CAPTION>
Name State of Incorporation Purpose
---- ---------------------- -------
<S> <C> <C>
Northern States Power
Company (Wisconsin) Wisconsin Electric and gas utility
Viking Gas Transmission Company Delaware Natural gas transmission
NRG Energy, Inc. Delaware Owns and manages nonregulated energy
subsidiaries of the Company
Energy Masters International, Inc. Minnesota Natural gas marketing and energy
services
Eloigne Company Minnesota Owns and operates affordable housing
units
Seren Innovations, Inc. Minnesota Communications and data services
Ultra Power Technologies, Inc. Minnesota Markets power-cable testing technology
</TABLE>
* Excludes certain immaterial subsidiaries
Exhibit 23.01
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statement No. 333-00415 on Form S-3 (relating to the Northern States Power
Company Dividend Reinvestment and Stock Purchase Plan), Registration Statement
No. 2-61264 on Form S-8 (relating to the Northern States Power Company Employee
Stock Ownership Plan), Registration Statement No. 33-38700 on Form S-8 (relating
to the Northern States Power Company Executive Long-Term Incentive Award Stock
Plan), and Registration Statement No. 33-63243 on Form S-3 (relating to the
Northern States Power Company $300,000,000 Principal Amount of First Mortgage
Bonds) of our report dated Feb. 2, 1998 appearing in this Form 10-K.
/s/
PRICE WATERHOUSE LLP
Minneapolis, Minnesota
March 25, 1998
EXHIBIT 99.01
Northern States Power Company Cautionary Factors
The Private Securities Litigation Reform Act of 1995 (the Act) provides
a new "safe harbor" for forward-looking statements to encourage such disclosures
without the threat of litigation providing those statements are identified as
forward-looking and are accompanied by meaningful, cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Forward-looking statements
have been and will be made in written documents and oral presentations of
Northern States Power Company (the Company). Such statements are based on
management's beliefs as well as assumptions made by and information currently
available to management. When used in the Company's documents or oral
presentations, the words "anticipate", "estimate", "expect", "objective",
"possible", "potential" and similar expressions are intended to identify
forward-looking statements. In addition to any assumptions and other factors
referred to specifically in connection with such forward-looking statements,
factors that could cause the Company's actual results to differ materially from
those contemplated in any forward-looking statements include, among others, the
following:
- - Economic conditions including inflation rates and monetary fluctuations;
- - Trade, monetary, fiscal, taxation, and environmental policies of
governments, agencies and similar organizations in geographic areas where
the Company has a financial interest;
- - Customer business conditions including demand for their products or
services and supply of labor and materials used in creating their products
and services;
- - Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board, the Securities and Exchange
Commission, the Federal Energy Regulatory Commission and similar entities
with regulatory oversight;
- - Availability or cost of capital such as changes in: interest rates; market
perceptions of the utility industry, the Company or any of its
subsidiaries; or security ratings;
- - Factors affecting utility and nonutility operations such as unusual weather
conditions; catastrophic weather-related damage; unscheduled generation
outages, maintenance or repairs; unanticipated changes to fossil fuel,
nuclear fuel or gas supply costs or availability due to higher demand,
shortages, transportation problems or other developments; nuclear or
environmental incidents; or electric transmission or gas pipeline system
constraints;
- - Employee workforce factors including loss or retirement of key executives,
collective bargaining agreements with union employees, or work stoppages;
- - Increased competition in the utility industry, including: industry
restructuring initiatives; transmission system operation and/or
administration initiatives; recovery of investments made under traditional
regulation; nature of competitors entering the industry; retail wheeling; a
new pricing structure; and former customers entering the generation market;
- - Rate-setting policies or procedures of regulatory entities, including
environmental externalities, which are values established by regulators
assigning environmental costs to each method of electricity generation when
evaluating generation resource options;
- - Nuclear regulatory policies and procedures including operating regulations
and spent nuclear fuel storage;
- - Social attitudes regarding the utility and power industries;
- - Cost and other effects of legal and administrative proceedings,
settlements, investigations and claims;
- - Technological developments that result in competitive disadvantages and
create the potential for impairment of existing assets;
- - Factors associated with nonregulated investments including conditions of
final legal closing, foreign government actions, foreign economic and
currency risks, political instability in foreign countries, partnership
actions, competition, operating risks, dependence on certain suppliers and
customers, domestic and foreign environmental and energy regulations;
- - Most of the current project investments made by the Company's subsidiary,
NRG Energy, Inc. (NRG) consist of minority interests, and a substantial
portion of future investments may take the form of minority interests,
which limits NRG's ability to control the development or operation of the
project;
<PAGE>
- - Other business or investment considerations that may be disclosed from time
to time in the Company's Securities and Exchange Commission filings or in
other publicly disseminated written documents.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise. The foregoing review of factors pursuant to the Act should
not be construed as exhaustive or as any admission regarding the adequacy of
disclosures made by the Company prior to the effective date of the Act.
EXHIBIT 99.02
DESCRIPTION OF COMMON STOCK
The information under this caption is a succinct summary of certain
provisions and is subject to the detailed provisions of Northern States Power
Company's (the "Company") Restated Articles of Incorporation, as amended, and of
its By-Laws, which have been filed (or incorporated by reference) as exhibits to
the Company's Annual Report on Form 10-K for the year ended December 31, 1997,
and which are incorporated herein by this reference.
GENERAL
The capital stock of the Company consists of two classes: Common Stock,
par value $2.50 per share and Preferred Stock, par value $100 per share (the
"Cumulative Preferred Stock"). As of March 2, 1998, there were 160,000,000
shares of Common Stock authorized, of which 74,861,502 shares were outstanding
as of such date. On January 28, 1998, the Board of Directors of the Company
adopted, subject to shareholder approval at the Annual Meeting scheduled for
April 22, 1998, an amendment to the company's Restated Articles of
Incorporation, as amended, which provides for an increase in the number of
authorized shares of Common stock from 160,000,000 shares to 350,000,000 shares.
As of March 2, 1998, there were 7,000,000 shares of Cumulative Preferred Stock
authorized, of which the following series were outstanding as of such date:
$3.60 Series -- 275,000 shares; $4.08 Series -- 150,000 shares; $4.10 Series --
175,000 shares; $4.11 Series -- 200,000 shares; $4.16 Series -- 100,000 shares;
$4.56 Series -- 150,000 shares; Variable Rate Series A -- 300,000 shares; and
Variable Rate Series B -- 650,000 shares). All of the outstanding shares of the
Variable Rate Series A and Variable Rate Series B will be redeemed on March 31,
1998.
The Board of Directors of the Company is authorized to provide for the issue
from time to time of Cumulative Preferred Stock in series and, as to each
series, to fix the designation, dividend rates and times of payment, redemption
price, and liquidation price or preference as to assets in voluntary
liquidation. Cumulative dividends, redemption provisions and sinking fund
requirements, to the extent that some or all of these features are or may be
present when Cumulative Preferred Stock is issued, could have an adverse effect
on the availability of earnings for distribution to the holders of the Common
Stock or for other corporate purposes.
DIVIDEND RIGHTS
Before any dividends may be paid on the Common Stock, the holders of
each series of the Company's Cumulative Preferred Stock are entitled to receive
their dividends at the respective rates provided for the shares of the
respective series. In addition, the Company may not, except in certain limited
circumstances, declare or pay any dividends on its Common Stock if the Company
has deferred payment of interest on its Junior Subordinated Debentures that were
<PAGE>
issued in connection with the Trust Originated Preferred Securities (TOPrS)
issued and sold by its subsidiary trust, NSP Financing I.
LIMITATIONS ON PAYMENT OF DIVIDENDS ON AND ACQUISITIONS OF COMMON STOCK
So long as any shares of Cumulative Preferred Stock are outstanding,
dividends (other than dividends payable in Common Stock) or distributions on, or
acquisitions for value of, Common Stock (i) may not exceed 50% of net income of
the Company for a preceding twelve-month period, after deducting dividends
accruing on any Cumulative Preferred Stock during the period, if the sum of the
capital represented by the Common Stock, premiums on capital stock (restricted
to premiums on Common Stock only by Commission Orders), and surplus accounts is
less than 20% of the sum of the total capital, premiums on capital stock,
surplus accounts and debt maturing more than one year after date of issue, (ii)
may not exceed 75% of net income for such preceding twelve-month period, as
adjusted, if such capitalization ratio is 20% or more but less than 25%, and
(iii) if such capitalization ratio exceeds 25%, such dividends, distributions or
acquisitions may not reduce such ratio to less than 25% except to the extent
permitted by clauses (i) and (ii) above.
In the Company's Trust Indenture dated February 1, 1937, as
supplemented (the "Trust Indenture"), securing its First Mortgage Bonds, the
Company has covenanted that the sum of (i) all dividends and distributions on
the Common Stock of the Company after September 30, 1954 (other than in Common
Stock), and (ii) the cost of all shares of its Common Stock acquired by it after
that date shall not exceed the sum of (a) the earned surplus of the Company and
certain of its former subsidiary companies, consolidated, at September 30, 1954,
and (b) an amount equal to the net income of the Company and certain of its
former subsidiary companies, consolidated, earned after September 30, 1954,
after making provisions for all dividends accruing after that date on preferred
stock of the Company and after taking into consideration all proper charges and
credits to earned surplus made after that date. In computing net income for the
purpose of this covenant, there will be deducted an amount, if any, by which 15%
of the consolidated gross operating revenues of such companies, as defined in
the Trust Indenture, after certain deductions, exceeds the aggregate of the
amounts expended for maintenance and provided for depreciation. None of the
foregoing provisions are expected to impair the Company's ability to pay
dividends in the foreseeable future.
The Company's Supplemental and Restated Trust Indenture dated May 1,
1988 (the "Restated Indenture") amends and restates the Trust Indenture. The
Restated Indenture will not become effective and operative until all First
Mortgage Bonds of each series issued under the Trust Indenture prior to July
1989 shall have been retired through payment or redemption or, subject to
certain limitations, until the holders of the requisite principal amount of such
First Mortgage Bonds shall have consented to the amendments contained in the
Restated Indenture (the "Effective Date"). The Restated Indenture will replace
the dividend restriction described in the preceding paragraph with the
requirement that (a) the sum of: (i) all dividends and distributions on the
Company's Common Stock after the Effective Date (other than in Common Stock) and
(ii) the amount, if any, by which the considerations given by the Company for
the purchase or other
<PAGE>
acquisition of its Common Stock after the Effective Date exceeds the
considerations received by it after the Effective Date from the sale of Common
Stock, shall not exceed (b) the sum of: (i) the retained earnings of the Company
at the Effective Date, and (ii) an amount equal to the net income of the Company
earned after the Effective Date, after deducting all dividends accruing after
the Effective Date on all classes and series of preferred stock of the Company.
In computing net income for the purpose of this amended covenant, there will be
deducted the amount, if any, by which, after the date commencing 365 days prior
to the Effective Date, the actual expenditures or charges for ordinary repairs
and maintenance and the charges for reserves, renewals, replacements,
retirements, depreciation and depletion are less than 2.50% of the Company's
completed depreciable property, as defined in the Restated Indenture.
VOTING RIGHTS
The holders of shares of Cumulative Preferred Stock of the $3.60 Series
are entitled to three votes for each share held, and the holders of shares of
Common Stock and shares of Cumulative Preferred Stock of all other series are
entitled to one vote for each share held on all matters submitted to a vote of
the Company's stockholders; provided that when dividends payable on the
Cumulative Preferred Stock of any series outstanding are in default in an amount
equivalent to the amount payable thereon during the immediately preceding
twelve-month period, and until such default shall have been remedied, the
holders of shares of Cumulative Preferred Stock, voting as a class and without
regard to series, are entitled to elect the smallest number of directors
necessary to constitute a majority of the Board of Directors and the holders of
shares of Common Stock, voting as a class, are entitled to elect the remaining
directors of the Company.
The affirmative vote or consent of the holders of various specified
percentages of Cumulative Preferred Stock is required to effect certain changes
in the capital structure of the Company and certain other transactions that
might affect their rights. Except to the extent required by law, holders of
Common Stock do not vote as a class in case of any modification of their rights.
CHANGE OF CONTROL
The Company's By-laws and the Minnesota Business Corporation Act, as
amended (the "Minnesota BCA"), contain provisions that could discourage or make
more difficult a change of control of the Company. Such provisions are designed
to protect the Company's shareholders against coercive, unfair or inadequate
tender offers and other abusive takeover tactics and to encourage any person
contemplating a business combination with the Company to negotiate with its
Board of Directors for the fair and equitable treatment of all of the Company's
shareholders.
ELECTION OF DIRECTORS. In electing directors, shareholders may cumulate
their votes in the manner provided in the Minnesota BCA. The Board of Directors
is divided into three classes as nearly equal in number as possible with
staggered terms of office so that only approximately one-third of the directors
are elected at each annual meeting of shareholders. The existence of a
classified Board along with cumulative voting rights may make it more difficult
for a group owning a significant amount of the Company's voting securities to
effect a change in the majority of the Board than would be the case if
cumulative voting did not exist.
<PAGE>
BY-LAW PROVISIONS. The Company's By-laws require advance notice of the
introduction by shareholders of business at annual or special meetings of
shareholders of the Company. For any such proposal to be properly brought before
an annual or special meeting, a shareholder must comply with the shareholder
proposal requirements under the federal proxy rules or deliver a written notice
to the Secretary of the Company not less than 20 days nor more than 90 days
prior to the scheduled annual or special meeting, as the case may be; provided
that if the date of such meeting is not disclosed at least 30 days in advance, a
shareholder notice will be timely delivered if received by the close of business
on the tenth day following the earlier of the day on which notice of the date of
the scheduled meeting was mailed or the day on which public disclosure of the
meeting date occurred. The required notice from a shareholder must contain (i) a
description of the proposed business and the reasons for conducting such
business, (ii) the name and address of each shareholder supporting the proposal
as it appears on the Company's books, (iii) the class and number of shares
beneficially owned by each such shareholder, and (iv) a description of any
financial or other interest of each such shareholder in the proposal.
MINNESOTA BCA. Section 302A.671 of the Minnesota BCA applies to
potential acquirers of 20% or more of the Company's voting shares. Section
302A.671 provides in substance that shares acquired by such acquirer will not
have any voting rights unless (a) the acquisition is approved by (i) a majority
of the voting power of all shares of the Company entitled to vote and (ii) a
majority of the voting power of all shares of the Company entitled to vote
excluding all shares owned by the acquirer or by any officer of the Company, or
(b) the acquisition (i) is pursuant to an all-cash tender offer for all of the
voting shares of the Company, (ii) results in the acquirer becoming the owner of
at least a majority of the outstanding voting shares of the Company, and (iii)
has been approved by a committee of disinterested directors.
Section 302A.673 of the Minnesota BCA generally prohibits public
Minnesota corporations, including the Company, from engaging in any business
combination with a person or entity owning 10% or more of the Company's voting
shares for a period of four years after the date of the transaction in which
such person or entity became a 10% shareholder unless the business combination
or the acquisition resulting in 10% ownership was approved by a committee of
disinterested directors prior to the date such person or entity became a 10%
shareholder.
Section 302A.675 of the Minnesota BCA provides in substance that a
person or entity making a takeover offer (an "offeror") for the Company is
prohibited from acquiring any additional Company shares within two years
following the last purchase of shares pursuant to a takeover offer with respect
to that class unless (i) the acquisition is approved by a committee of
disinterested directors before the purchase of any shares by the offeror
pursuant to a takeover offer or (ii) shareholders of the Company are afforded,
at the time of the acquisition, a reasonable opportunity to dispose of their
shares to the offeror upon substantially equivalent terms as those provided in
the earlier takeover offer.
LIQUIDATION RIGHTS
<PAGE>
In the event of liquidation, after the holders of all series of
Cumulative Preferred Stock have received $100 per share in the case of
involuntary liquidation, and the then applicable redemption prices in the case
of voluntary liquidation, plus in either case an amount equal to all accumulated
and unpaid dividends, the holders of the Common Stock are entitled to the
remaining assets.
PREEMPTIVE AND SUBSCRIPTION RIGHTS
No holder of stock of the Company has the preemptive right to purchase
or subscribe for any additional capital stock of the Company.
The Company's Common Stock is listed on the New York Stock Exchange,
the Chicago Stock Exchange and the Pacific Exchange. The Transfer Agent for the
Common Stock is the Company and the Registrar is Norwest Bank Minnesota, N.A.
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.01
<LEGEND>
This schedule contains summary financial information extracted from the
Statements of Income, Balance Sheets, Statements of Capitalization, Statements
of Changes in Common Stockholders' Equity and Statements of Cash Flows and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,361,320
<OTHER-PROPERTY-AND-INVEST> 1,397,750
<TOTAL-CURRENT-ASSETS> 801,791
<TOTAL-DEFERRED-CHARGES> 340,122
<OTHER-ASSETS> 243,083
<TOTAL-ASSETS> 7,144,066
<COMMON> 186,546
<CAPITAL-SURPLUS-PAID-IN> 893,727
<RETAINED-EARNINGS> 1,364,875
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,371,728<F1>
200,000
200,340
<LONG-TERM-DEBT-NET> 1,878,875
<SHORT-TERM-NOTES> 122,352
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 138,000
<LONG-TERM-DEBT-CURRENT-PORT> 164,420
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,994,931<F1>
<TOT-CAPITALIZATION-AND-LIAB> 7,144,066
<GROSS-OPERATING-REVENUE> 2,733,746
<INCOME-TAX-EXPENSE> 96,710<F2>
<OTHER-OPERATING-EXPENSES> 2,227,135
<TOTAL-OPERATING-EXPENSES> 2,371,990
<OPERATING-INCOME-LOSS> 361,756
<OTHER-INCOME-NET> (27,849)<F3>
<INCOME-BEFORE-INTEREST-EXPEN> 396,489
<TOTAL-INTEREST-EXPENSE> 144,732
<NET-INCOME> 237,320
11,071
<EARNINGS-AVAILABLE-FOR-COMM> 226,249
<COMMON-STOCK-DIVIDENDS> 202,173
<TOTAL-INTEREST-ON-BONDS> 131,456
<CASH-FLOW-OPERATIONS> 689,785
<EPS-PRIMARY> 3.22
<EPS-DILUTED> 3.21
<FN>
<F1>Note 1 - ($73,420) thousand of Common Stockholders' Equity is classified
as Other Items-Capitalization and Liabilities. This represents
the net of leveraged common stock held by the Employee Stock
Ownership Plan and the currency translation adjustments.
<F2>Note 2 - ($48,145) thousand of nonregulated and nonoperating income tax
benefit is classified as Income Tax Expense. The financial
statement presentation includes them as a component of Other
Income (Expense).
<F3>Note 3 - Includes Income from Nonregulated Businesses - Before Interest and
Taxes, Allowance for Funds Used During Construction-Equity,
Merger Costs, Other Utility Income (Deductions)-Net and
Distributions on redeemable preferred securities of subsidiary
trust.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.02
<LEGEND>
This schedule contains summary financial information extracted from the
Statements of Income, Balance Sheets, Statements of Capitalization, Statements
of Changes in Common Stockholders' Equity and Statements of Cash Flows and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,337,880
<OTHER-PROPERTY-AND-INVEST> 904,769
<TOTAL-CURRENT-ASSETS> 797,223
<TOTAL-DEFERRED-CHARGES> 354,128
<OTHER-ASSETS> 242,900
<TOTAL-ASSETS> 6,636,900
<COMMON> 172,659
<CAPITAL-SURPLUS-PAID-IN> 638,719
<RETAINED-EARNINGS> 1,340,799
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,135,880<F1>
0
240,469
<LONG-TERM-DEBT-NET> 1,592,568
<SHORT-TERM-NOTES> 6,867
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 361,500
<LONG-TERM-DEBT-CURRENT-PORT> 261,218
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,022,101<F1>
<TOT-CAPITALIZATION-AND-LIAB> 6,636,900
<GROSS-OPERATING-REVENUE> 2,654,206
<INCOME-TAX-EXPENSE> 146,810<F2>
<OTHER-OPERATING-EXPENSES> 2,126,752
<TOTAL-OPERATING-EXPENSES> 2,288,162
<OPERATING-INCOME-LOSS> 366,044
<OTHER-INCOME-NET> 24,594<F2>
<INCOME-BEFORE-INTEREST-EXPEN> 405,238
<TOTAL-INTEREST-EXPENSE> 130,699
<NET-INCOME> 274,539
12,245
<EARNINGS-AVAILABLE-FOR-COMM> 262,294
<COMMON-STOCK-DIVIDENDS> 187,521
<TOTAL-INTEREST-ON-BONDS> 119,018
<CASH-FLOW-OPERATIONS> 544,464
<EPS-PRIMARY> 3.83<F3>
<EPS-DILUTED> 3.82<F3>
<FN>
<F1>Note 1 - ($16,297) thousand of Common Stockholders' Equity is classified
as Other Items-Capitalization and Liabilities. This represents
the net of leveraged common stock held by the Employee Stock
Ownership Plan and the currency translation adjustments.
<F2>Note 2 - ($14,600) thousand of non-operating income taxes are classified
as Income Tax Expense. The financial statement presentation
includes them as a component of Other Income (Expense).
<F3>Note 3 - In compliance with SFAS No. 128, Earnings Per Share, EPS-Primary
was restated as Earnings Per Average Common Share-Basic and
EPS-Diluted was restated as Earnings Per Average Common Share-
Assuming Dilution.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.03
<LEGEND>
This schedule contains summary financial information extracted from the
Statements of Income, Balance Sheets, Statements of Capitalization, Statements
of Changes in Common Stockholders' Equity and Statements of Cash Flows and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,310,341
<OTHER-PROPERTY-AND-INVEST> 670,718
<TOTAL-CURRENT-ASSETS> 704,463
<TOTAL-DEFERRED-CHARGES> 374,212
<OTHER-ASSETS> 168,851
<TOTAL-ASSETS> 6,228,585
<COMMON> 170,440
<CAPITAL-SURPLUS-PAID-IN> 599,094
<RETAINED-EARNINGS> 1,266,026
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,027,391<F1>
0
240,469
<LONG-TERM-DEBT-NET> 1,542,286
<SHORT-TERM-NOTES> 594
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 215,600
<LONG-TERM-DEBT-CURRENT-PORT> 167,360
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,026,716<F1>
<TOT-CAPITALIZATION-AND-LIAB> 6,228,585
<GROSS-OPERATING-REVENUE> 2,568,584
<INCOME-TAX-EXPENSE> 152,228<F2>
<OTHER-OPERATING-EXPENSES> 2,075,557
<TOTAL-OPERATING-EXPENSES> 2,222,705
<OPERATING-INCOME-LOSS> 345,879
<OTHER-INCOME-NET> 57,886<F2>
<INCOME-BEFORE-INTEREST-EXPEN> 398,685
<TOTAL-INTEREST-EXPENSE> 122,890
<NET-INCOME> 275,795
12,449
<EARNINGS-AVAILABLE-FOR-COMM> 263,346
<COMMON-STOCK-DIVIDENDS> 180,510
<TOTAL-INTEREST-ON-BONDS> 111,994
<CASH-FLOW-OPERATIONS> 573,787
<EPS-PRIMARY> 3.91<F3>
<EPS-DILUTED> 3.91<F3>
<FN>
<F1>
NOTE 1 - ($8,169) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of
leveraged common stock held by the Employee Stock Ownership Plan
and the currency translation adjustments.
<F2>
NOTE 2 - $5,080 thousand of non-operating income taxes are classified as
Income Tax Expense. The financial statement presentation includes
them as a component of Other Income (Expense).
<F3>
NOTE 3 - In compliance with SFAS No. 128, Earnings Per Share, EPS-Primary
was restated as Earnings Per Average Common Share-Basic and
EPS-Diluted was restated as Earnings Per Average Common Share-
Assuming Dilution.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.04
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated
Statements of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,342,841
<OTHER-PROPERTY-AND-INVEST> 1,308,976
<TOTAL-CURRENT-ASSETS> 785,468
<TOTAL-DEFERRED-CHARGES> 351,345
<OTHER-ASSETS> 269,974
<TOTAL-ASSETS> 7,058,604
<COMMON> 185,465
<CAPITAL-SURPLUS-PAID-IN> 876,215
<RETAINED-EARNINGS> 1,355,641
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,372,621<F1>
200,000
200,340
<LONG-TERM-DEBT-NET> 1,856,479
<SHORT-TERM-NOTES> 41,680
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 65,000
<LONG-TERM-DEBT-CURRENT-PORT> 258,535
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,019,249<F1>
<TOT-CAPITALIZATION-AND-LIAB> 7,058,604
<GROSS-OPERATING-REVENUE> 2,034,263
<INCOME-TAX-EXPENSE> 83,267<F2>
<OTHER-OPERATING-EXPENSES> 1,645,939
<TOTAL-OPERATING-EXPENSES> 1,761,681
<OPERATING-INCOME-LOSS> 272,582
<OTHER-INCOME-NET> (27,719)<F3>
<INCOME-BEFORE-INTEREST-EXPEN> 277,338
<TOTAL-INTEREST-EXPENSE> 105,400
<NET-INCOME> 171,938
8,699
<EARNINGS-AVAILABLE-FOR-COMM> 163,239
<COMMON-STOCK-DIVIDENDS> 148,397
<TOTAL-INTEREST-ON-BONDS> 96,802
<CASH-FLOW-OPERATIONS> 508,864
<EPS-PRIMARY> 2.37<F4>
<EPS-DILUTED> 2.36<F4>
<FN>
<F1>$(44,700) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of leveraged
common stock held by the Employee Stock Ownership Plan and the currency
translation adjustments.
<F2>$(32,475) thousand of non-operating income tax benefit is classified as
Income Tax Expense. The financial statement presentation includes this as a
component of Other Income (Expense).
<F3>Includes Income from Nonregulated Businesses Before Interest and Taxes,
Allowance for Funds Used During Construction-Equity, Merger Costs, Other
Utility Income (Deductions)-Net and Distributions on redeemable preferred
securities of subsidiary trust.
<F4> NOTE 4 - In compliance with SFAS No. 128, Earnings Per Share, EPS-Primary
was restated as Earnings Per Average Common Share-Basic and
EPS-Diluted was restated as Earnings Per Average Common Share-
Assuming Dilution.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.05
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated
Statements of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,332,760
<OTHER-PROPERTY-AND-INVEST> 1,259,024
<TOTAL-CURRENT-ASSETS> 689,625
<TOTAL-DEFERRED-CHARGES> 342,891
<OTHER-ASSETS> 254,669
<TOTAL-ASSETS> 6,868,969
<COMMON> 172,569
<CAPITAL-SURPLUS-PAID-IN> 638,906
<RETAINED-EARNINGS> 1,322,265
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,104,282<F1>
200,000
200,340
<LONG-TERM-DEBT-NET> 1,839,698
<SHORT-TERM-NOTES> 3,224
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 299,500
<LONG-TERM-DEBT-CURRENT-PORT> 260,262
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,932,205<F1>
<TOT-CAPITALIZATION-AND-LIAB> 6,868,969
<GROSS-OPERATING-REVENUE> 1,336,820
<INCOME-TAX-EXPENSE> 36,389<F2>
<OTHER-OPERATING-EXPENSES> 1,123,188
<TOTAL-OPERATING-EXPENSES> 1,182,778
<OPERATING-INCOME-LOSS> 154,042
<OTHER-INCOME-NET> (25,004)<F3>
<INCOME-BEFORE-INTEREST-EXPEN> 152,239
<TOTAL-INTEREST-EXPENSE> 68,213
<NET-INCOME> 84,026
6,328
<EARNINGS-AVAILABLE-FOR-COMM> 77,698
<COMMON-STOCK-DIVIDENDS> 96,232
<TOTAL-INTEREST-ON-BONDS> 60,611
<CASH-FLOW-OPERATIONS> 288,401
<EPS-PRIMARY> $1.13<F4>
<EPS-DILUTED> $1.13<F4>
<FN>
<F1>$(29,458) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of leveraged
common stock held by the Employee Stock Ownership Plan and the currency
translation adjustments.
<F2>$(23,201) thousand of non-operating income tax benefit is classified as
Income Tax Expense. The financial statement presentation includes this as a
component of Other Income (Expense).
<F3>Includes Equity in Earnings of Unconsolidated Affiliate Operations,
Allowance for Funds Used During Construction-Equity, Merger Costs, Other Income
(Deductions)-Net and Distributions on redeemable preferred securities of
subsidiary trust.
<F4> NOTE 4 - In compliance with SFAS No. 128, Earnings Per Share, EPS-Primary
was restated as Earnings Per Average Common Share-Basic and
EPS-Diluted was restated as Earnings Per Average Common Share-
Assuming Dilution.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.06
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated
Statements of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> MAR-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,318,737
<OTHER-PROPERTY-AND-INVEST> 942,594
<TOTAL-CURRENT-ASSETS> 724,643
<TOTAL-DEFERRED-CHARGES> 342,504
<OTHER-ASSETS> 270,959
<TOTAL-ASSETS> 6,599,437
<COMMON> 172,528
<CAPITAL-SURPLUS-PAID-IN> 638,390
<RETAINED-EARNINGS> 1,354,894
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,147,834<F1>
200,000
200,340
<LONG-TERM-DEBT-NET> 1,588,870
<SHORT-TERM-NOTES> 5,280
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 148,500
<LONG-TERM-DEBT-CURRENT-PORT> 261,291
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,029,344<F1>
<TOT-CAPITALIZATION-AND-LIAB> 6,599,437
<GROSS-OPERATING-REVENUE> 742,496
<INCOME-TAX-EXPENSE> 30,625<F2>
<OTHER-OPERATING-EXPENSES> 617,024
<TOTAL-OPERATING-EXPENSES> 654,040
<OPERATING-INCOME-LOSS> 88,456
<OTHER-INCOME-NET> 3,200<F3>
<INCOME-BEFORE-INTEREST-EXPEN> 100,672
<TOTAL-INTEREST-EXPENSE> 32,274
<NET-INCOME> 65,773
3,957
<EARNINGS-AVAILABLE-FOR-COMM> 61,816
<COMMON-STOCK-DIVIDENDS> 47,721
<TOTAL-INTEREST-ON-BONDS> 30,259
<CASH-FLOW-OPERATIONS> 218,345
<EPS-PRIMARY> $.90<F4>
<EPS-DILUTED> $.90<F4>
<FN>
<F1>$(17,978) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of leveraged
common stock held by the Employee Stock Ownership Plan and the currency
translation adjustments.
<F2>$(6,391) thousand of non-operating income tax benefit is classified as
Income Tax Expense. The financial statement presentation includes this as a
component of Other Income (Expense).
<F3>Includes Equity in Earnings of Unconsolidated Affiliate Operations,
Allowance for Funds Used During Construction-Equity, Other Income (Deductions)-
Net and Distributions on redeemable preferred securities of subsidiary trust.
<F4> NOTE 4 - In compliance with SFAS No. 128, Earnings Per Share, EPS-Primary
was restated as Earnings Per Average Common Share-Basic and
EPS-Diluted was restated as Earnings Per Average Common Share-
Assuming Dilution.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.07
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated
Statements of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,344,491
<OTHER-PROPERTY-AND-INVEST> 756,307
<TOTAL-CURRENT-ASSETS> 716,887
<TOTAL-DEFERRED-CHARGES> 371,628
<OTHER-ASSETS> 205,623
<TOTAL-ASSETS> 6,394,936
<COMMON> 172,659
<CAPITAL-SURPLUS-PAID-IN> 638,839
<RETAINED-EARNINGS> 1,311,263
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,105,448<F1>
0
240,469
<LONG-TERM-DEBT-NET> 1,673,145
<SHORT-TERM-NOTES> 6,601
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 216,000
<LONG-TERM-DEBT-CURRENT-PORT> 159,840
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,976,120<F1>
<TOT-CAPITALIZATION-AND-LIAB> 6,394,936
<GROSS-OPERATING-REVENUE> 1,944,226
<INCOME-TAX-EXPENSE> 108,239<F2>
<OTHER-OPERATING-EXPENSES> 1,559,196
<TOTAL-OPERATING-EXPENSES> 1,678,691
<OPERATING-INCOME-LOSS> 265,535
<OTHER-INCOME-NET> 15,280<F2>
<INCOME-BEFORE-INTEREST-EXPEN> 292,071
<TOTAL-INTEREST-EXPENSE> 97,240
<NET-INCOME> 194,831
9,184
<EARNINGS-AVAILABLE-FOR-COMM> 185,647
<COMMON-STOCK-DIVIDENDS> 140,410
<TOTAL-INTEREST-ON-BONDS> 89,005
<CASH-FLOW-OPERATIONS> 436,929
<EPS-PRIMARY> $2.71<F3>
<EPS-DILUTED> $2.70<F3>
<FN>
<F1>$(17,313) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of leveraged
common stock held by the Employee Stock Ownership Plan and the currency
translation adjustments.
<F2>$(11,256) thousand of non-operating income tax benefit is classified as
Income Tax Expense. The financial statement presentation includes this as a
component of Other Income (Expense).
<F3>NOTE 3 - In compliance with SFAS No. 128, Earnings Per Share, EPS-Primary
was restated as Earnings Per Average Common Share-Basic and
EPS-Diluted was restated as Earnings Per Average Common Share-
Assuming Dilution.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.08
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated
Statements of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> JUN-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,323,860
<OTHER-PROPERTY-AND-INVEST> 750,981
<TOTAL-CURRENT-ASSETS> 801,321
<TOTAL-DEFERRED-CHARGES> 363,486
<OTHER-ASSETS> 161,612
<TOTAL-ASSETS> 6,401,260
<COMMON> 172,029
<CAPITAL-SURPLUS-PAID-IN> 628,359
<RETAINED-EARNINGS> 1,277,203
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,073,534<F1>
0
240,469
<LONG-TERM-DEBT-NET> 1,666,459
<SHORT-TERM-NOTES> 5,252
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 372,500
<LONG-TERM-DEBT-CURRENT-PORT> 154,706
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,884,283<F1>
<TOT-CAPITALIZATION-AND-LIAB> 6,401,260
<GROSS-OPERATING-REVENUE> 1,310,968
<INCOME-TAX-EXPENSE> 61,256<F2>
<OTHER-OPERATING-EXPENSES> 1,082,395
<TOTAL-OPERATING-EXPENSES> 1,150,889
<OPERATING-INCOME-LOSS> 160,079
<OTHER-INCOME-NET> 7,858<F2>
<INCOME-BEFORE-INTEREST-EXPEN> 175,175
<TOTAL-INTEREST-EXPENSE> 64,583
<NET-INCOME> 110,592
6,123
<EARNINGS-AVAILABLE-FOR-COMM> 104,469
<COMMON-STOCK-DIVIDENDS> 93,292
<TOTAL-INTEREST-ON-BONDS> 58,847
<CASH-FLOW-OPERATIONS> 155,220
<EPS-PRIMARY> $1.53<F3>
<EPS-DILUTED> $1.53<F3>
<FN>
<F1>$(4,057) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of leveraged
common stock held by the Employee Stock Ownership Plan and the currency
translation adjustments.
<F2>$(7,238) thousand of non-operating income tax benefit is classified as
Income Tax Expense. The financial statement presentation includes this as
a component of Other Income (Expense).
<F3>NOTE 3 - In compliance with SFAS No. 128, Earnings Per Share, EPS-Primary
was restated as Earnings Per Average Common Share-Basic and
EPS-Diluted was restated as Earnings Per Average Common Share-
Assuming Dilution.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
EXHIBIT 27.09
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated
Statements of Cash Flows and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> MAR-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,321,430
<OTHER-PROPERTY-AND-INVEST> 691,013
<TOTAL-CURRENT-ASSETS> 837,678
<TOTAL-DEFERRED-CHARGES> 365,265
<OTHER-ASSETS> 165,828
<TOTAL-ASSETS> 6,381,214
<COMMON> 171,250
<CAPITAL-SURPLUS-PAID-IN> 614,817
<RETAINED-EARNINGS> 1,284,516
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,066,267<F1>
0
240,469
<LONG-TERM-DEBT-NET> 1,667,951
<SHORT-TERM-NOTES> 577
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 168,500
<LONG-TERM-DEBT-CURRENT-PORT> 156,689
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,076,445<F1>
<TOT-CAPITALIZATION-AND-LIAB> 6,381,214
<GROSS-OPERATING-REVENUE> 718,709
<INCOME-TAX-EXPENSE> 36,637<F2>
<OTHER-OPERATING-EXPENSES> 588,766
<TOTAL-OPERATING-EXPENSES> 629,432
<OPERATING-INCOME-LOSS> 89,277
<OTHER-INCOME-NET> 5,143<F2>
<INCOME-BEFORE-INTEREST-EXPEN> 98,449
<TOTAL-INTEREST-EXPENSE> 31,239
<NET-INCOME> 67,210
3,061
<EARNINGS-AVAILABLE-FOR-COMM> 64,149
<COMMON-STOCK-DIVIDENDS> 45,660
<TOTAL-INTEREST-ON-BONDS> 27,271
<CASH-FLOW-OPERATIONS> 219,146
<EPS-PRIMARY> $0.94<F3>
<EPS-DILUTED> $0.94<F3>
<FN>
<F1>$(4,316) thousand of Common Stockholders' Equity is classified as Other
Items-Capitalization and Liabilities. This represents the net of leveraged
common stock held by the Employee Stock Ownership Plan and the currency
translation adjustments.
<F2>$4,029 thousand of non-operating income tax benefit is classified as
Income Tax Expense. The financial statement presentation includes this as
a component of Other Income (Expense).
<F3> NOTE 3 - In compliance with SFAS No. 128, Earnings Per Share, EPS-Primary
was restated as Earnings Per Average Common Share-Basic and
EPS-Diluted was restated as Earnings Per Average Common Share-
Assuming Dilution.
</FN>
</TABLE>
