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, 1993
Commission file number: 1-3034
NORTHERN STATES POWER COMPANY
(Exact name of Registrant as specified in its charter)
Minnesota 41-0448030
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
414 Nicollet Mall, Minneapolis, Minnesota 55401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 612-330-5500
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of each exchange on which registered
Common Stock, $2.50 Par Value New York Stock Exchange,
Chicago Stock Exchange and
Pacific Stock Exchange
Cumulative Preferred Stock, $100
Par Value each
Preferred Stock $ 3.60 Cumulative New York Stock Exchange
Preferred Stock $ 4.08 Cumulative New York Stock Exchange
Preferred Stock $ 4.10 Cumulative New York Stock Exchange
Preferred Stock $ 4.11 Cumulative New York Stock Exchange
Preferred Stock $ 4.16 Cumulative New York Stock Exchange
Preferred Stock $ 4.56 Cumulative New York Stock Exchange
Preferred Stock $ 6.80 Cumulative New York Stock Exchange
Preferred Stock $ 7.00 Cumulative New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K. ______
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 1, 1994, the aggregate market value of the voting common
stock held by non-affiliates of the Registrant was $2,747,161,556 and there
were outstanding 66,893,377 shares of common stock, $2.50 par value.
Documents Incorporated by Reference
The Registrant's Definitive Proxy Statement for its 1994 meeting of
shareholders to be held on April 27, 1994, is incorporated by reference
into Part III of Form 10-K.
Index
PART I
Item 1 - Business
REGULATION AND REVENUES
General
Revenues
Rate Programs
Rate Matters by Jurisdictions
Ratemaking Principles in Minnesota and Wisconsin
Fuel and Purchased Gas Adjustment Clauses
ELECTRIC OPERATIONS
Capability and Demand
Competition
Energy Sources
Fuel Supply and Costs
Nuclear Power Plants - Licensing, Operation and Waste Disposal
GAS OPERATIONS
Capability and Demand
Competition
Gas Supply and Costs
TELEPHONE OPERATIONS
NRG ENERGY, INC
OTHER SUBSIDIARIES
ENVIRONMENTAL MATTERS
CAPITAL SPENDING AND FINANCING
EMPLOYEES AND EMPLOYEE BENEFITS
OPERATING STATISTICS
EXECUTIVE OFFICERS
Item 2 - Properties
Item 3 - Legal Proceedings
Item 4 - Submission of Matters to a Vote of Security Holders
PART II
Item 5 - Market for Registrant's Common Equity and Related Stockholder
Matters
Item 6 - Selected Financial Data
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations
Item 8 - Financial Statements and Supplementary Data
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
PART III
Item 10 - Directors and Executive Officers of the Registrant
Item 11 - Executive Compensation
Item 12 - Security Ownership of Certain Beneficial Owners and Management
Item 13 - Certain Relationships and Related Transactions
PART IV
Item 14 - Exhibits, Financial Statement Schedules, and Reports on Form
8-K
SIGNATURES
PART I
Item 1 - Business
Northern States Power Company (the Company) was incorporated in 1909
under the laws of Minnesota. Its executive offices are located at 414
Nicollet Mall, Minneapolis, Minnesota 55401. (Phone 612-330-5500). The
Company has one significant subsidiary, Northern States Power Company, a
Wisconsin Corporation (the Wisconsin Company) and several other subsidiaries,
including NRG Energy, Inc. (NRG), and Viking Gas Transmission Company
(Viking), both Delaware corporations. NRG manages several of the Company's
non-regulated energy subsidiaries. Viking is a regulated utility that
operates a 500-mile interstate natural gas pipeline. (See "NRG Energy, Inc."
and "Other Subsidiaries" herein for further discussion of these two
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 a 49,000
square mile service area and the transportation and distribution of natural
gas in approximately 133 communities within this area. The Company formerly
supplied telephone service in the Minot, North Dakota, area. The telephone
operation was sold on Jan. 31, 1991. (See "Telephone Operations" herein.)
For business segment information, see Note 16 of Notes to Financial
Statements under Item 8.
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 is concentrated in the Minneapolis-St. Paul
metropolitan area. In 1993, about 62% of NSP's electric retail revenue was
derived from sales in the Minneapolis-St. Paul metropolitan area and about
57% of retail gas revenue came from sales in the St. Paul area.
NSP's utility businesses are experiencing some of the challenges
currently common to regulated electric and gas utility companies, namely,
increasing competition for customers, increasing costs to operate and
construct facilities, uncertainties in regulatory processes and increasing
costs of compliance with environmental laws and regulations. In particular,
NSP is experiencing problems with the storage of spent nuclear fuel from the
Company's Prairie Island nuclear facility. Without additional storage or
significant modification of normal plant operations, the plant will be
shutdown in early 1996, which could have a significant financial impact on
NSP. (See "Environmental Matters" herein, Management's Discussion and
Analysis of Financial Condition and Results of Operations under Item 7
and Note 15 of Notes to Financial Statements under Item 8 for further
discussion of this matter.)
NSP made three strategically important business acquisitions in 1993
to operate more effectively in an increasingly competitive marketplace. NSP
acquired an interstate gas pipeline, purchased assets of a non-regulated gas
marketing business and expanded its non-regulated steam business. In 1993,
NSP acquired Viking Gas Transmission Company and selected assets of the
Centran Corporation. These Centran Corporation assets were reorganized into
Cenergy, Inc., which provides NSP a vehicle to offer customized gas and
energy services to fit customers' individual needs, both inside and outside
the NSP service territory. The Viking pipeline allows NSP to lower its cost
and to increase supply and storage flexibility. These two acquisitions
together substantially increase our ability to compete in a more competitive
business environment created by FERC Order 636. (See discussion at "Gas
Operations" herein.) In addition, NRG purchased the Minneapolis Energy
Center to position NSP as the major provider of central heating and cooling
in Minnesota's largest city.
NRG has also been active in the international market through
partnership investments. NRG acquired part ownership in the MIBRAG Gmbh coal
and power complex and the 900 megawatt (Mw) Schkopau power plant near
Leipzig, Germany. In addition, NRG also plans to become the operator and
37.5% owner of the 1680 Mw Gladstone Power Station in Queensland, Australia.
(See additional discussions of business acquisitions and partnership investments
in the "NRG Energy, Inc." and "Other Subsidiaries" sections, herein, and in
Note 4 of Notes to Financial Statements under Item 8.)
Business Realignment
In order for the Company to be prepared to successfully meet
challenges in the changing utility industry and to compete effectively in an
increasingly competitive environment, the Company began a functional
restructuring of its organization in 1992. During 1993, the Company
completed several phases of the functional restructuring. The Company is
now organized around three core, customer-focused businesses: electric
power generation, electric transmission and distribution, and gas
distribution. The new organization will use shared services, agreements or
service contracts between all businesses, and centralized support groups
throughout the Company. This restructuring is expected to improve the
Company's competitive position by reducing costs, expediting decision-making
and improving operating efficiencies.
REGULATION AND REVENUES
General
Retail sales rates, services and other aspects of the Company's
operations are subject to the jurisdiction of the Minnesota Public Utilities
Commission (MPUC), the North Dakota Public Service Commission (NDPSC), and
the South Dakota Public Utilities Commission (SDPUC) within their respective
states. The MPUC also possesses regulatory authority over aspects of the
Company's financial activities including security issuances, property
transfers when the asset value is in excess of $100,000, mergers with other
utilities, and transactions between the regulated Company and non-regulated
affiliates. In addition, the MPUC reviews and approves the Company's
electric resource plans for meeting customers' future electric energy needs.
The Wisconsin Company is subject to regulation of similar scope by the Public
Service Commission of Wisconsin (PSCW) and the Michigan Public Service
Commission (MPSC). In addition, each of the state commissions certifies the
need for new generating plants and transmission lines of designated
capacities to be located within the respective states before the facilities
may be sited and built.
Wholesale rates for electric energy sold in interstate commerce,
wheeling rates for energy transmission in interstate commerce, the wholesale
gas transportation rates of Viking, and certain other activities of the
Company, the Wisconsin Company and Viking are subject to the jurisdiction of
the Federal Energy Regulatory Commission (FERC). NSP also is subject to the
jurisdiction of other federal, state and local agencies in many of its
activities. (See "Environmental Matters" under Item 1.)
The Minnesota Environmental Quality Board (MEQB) is empowered to
select and designate sites for new power plants with a capacity of 50 Mw or
more and routes for transmission lines with a capacity of 200 kilovolt (Kv)
or more, and to evaluate such sites and routes for environmental
compatibility. The MEQB may designate sites or routes from those proposed
by power suppliers or those developed by the MEQB. No such power plant or
transmission line may be constructed in Minnesota except on a site or route
designated by the MEQB.
NSP is unable to predict the impact on its operating results from the
future regulatory activities of any of the above agencies. To the best of its
ability, NSP works to understand and comply with all rules issued by the
various agencies.
Revenues
NSP's financial results depend on its ability to obtain adequate and
timely rate relief from the various regulatory bodies. NSP's 1993 utility
operating revenues, excluding intersystem non-firm electric sales to other
utilities of $110 million and miscellaneous revenues of $39 million, were
subject to regulatory jurisdiction as follows:
Authorized Return on Percent of Total
Common Equity @ Revenues
December 31, 1993 (Electric & Gas)
(Electric Operations)
Retail:
Minnesota Public Utilities
Commission 11.47% 73.4%
Public Service Commission
of Wisconsin 12.00** 14.7
North Dakota Public Service
Commission 11.50 5.6
South Dakota Public Utilities
Commission * 3.1
Michigan Public Service
Commission 12.25 0.6
Sales for Resale - Wholesale
and Interstate Transmission:
Federal Energy Regulatory
Commission * 2.6
Total 100.0%
* Settlement proceeding, based upon revenue levels granted with no specified
return.
** Return authorized for 1994 is 11.4%.
Rate Programs
Rate increases requested and granted in previous years from various
jurisdictions were as follows (Note that 1992 and 1993 amounts represent
annual increases effective in these years, while previous years represent
annual increases requested in those years even if effective in a subsequent
year.):
Annual Increase
Year Requested Granted
(Millions of dollars)
1987 $122.0 $ 83.9
1988 4.4 3.0
1989 129.0 8.0
1990 19.5 11.2
1991 118.7 68.0
1992 ----- -----
1993 166.6 101.5
The following table summarizes the status of rate increases filed
during 1992 and 1993 for rates effective in 1993.
Annual Increase
Updated
Requested Request Granted Status
(Millions of dollars)
Electric
Minnesota-Retail $119.1 $112.3 $ 72.2 Order Issued 1/14/94
North Dakota-Retail 8.8 7.1 4.8 Order On Reconsideration
Issued 4/7/93
South Dakota-Retail 6.3 4.2 Order Approving
Settlement Agreement
Issued 12/09/92
Wisconsin-Retail 10.8 8.0 Order Issued 1/14/93
Minnesota Wholesale 2.3 .9 (1)
Wisconsin Wholesale .6 .6 (1)
Gas
Minnesota-Retail 14.9 12.4 10.0 Order Issued 12/30/93
Wisconsin-Retail 1.4 1.1 Order Issued 1/14/93
Viking Wholesale 2.4 (.3) (2)
Total 1993 Rate
Program $166.6 $101.5
(1) Order filed with a settlement agreement with rates effective in 1993.
(2) Rate increase request filed 1991. Rates effective under a settlement
agreement in 1993.
The following table summarizes the status of rate increases filed in
1993 for rates effective in 1994.
Annual Increase
Updated
Requested Request Granted Status
(Millions of dollars)
Electric
North Dakota-Retail 1.2 1.2 Order Issued 12/29/93
Gas
Wisconsin-Retail 1.4 1.7 1.4 Order Issued 12/23/93
Total 1994 Rate
Program 2.6 2.6
Rate Matters by Jurisdictions
Minnesota Public Utilities Commission (MPUC)
In November 1992, the Company filed applications for rate increases
totaling $119.1 million and $14.9 million for its Minnesota electric and
natural gas customers, respectively. This represented annual increases of
approximately 9% and 5.8%, respectively. In December 1992, the MPUC issued
orders granting interim rate increases (subject to refund) of $71.2 million
(5.4%) for electric service and $8.4 million (3.3%) for gas service,
effective Jan. 1, 1993. In June 1993, the Company adjusted its proposed
annual electric rate increase to $112.3 million and its gas rate request to
$12.4 million. The Company received initial orders from the MPUC in
September 1993 allowing an annual retail electric rate increase of $54.3
million (4.1%) and an annual retail gas rate increase of $8.3 million (3.3%).
On Nov. 10, 1993, the MPUC reconsidered several issues common to both the
electric and gas rate cases and on Dec. 2, 1993, reconsidered a number of
other issues in the electric rate order. The Company received a final gas
rate order after reconsideration on Dec. 30, 1993, granting an overall gas
rate increase of $10.0 million (3.9%). The Company received a final electric
rate order after reconsideration on Jan. 14, 1994, granting an overall
electric rate increase of $72.2 million (5.4%). The return on equity granted
in both cases was 11.47%. Electric rate refunds of interim rates collected
are required in the amount of approximately $12 million, which were accrued
in 1993 and are expected to be paid in May 1994. No refunds of interim gas
rates collected are required. Final rates for gas customers were implemented
in March 1994. Implementation of final rates for electric customers is
expected in April 1994. The effects of reconsideration were recorded in the
fourth quarter 1993, when reconsideration occurred. However, the Company
restated its third quarter 1993 earnings for the effects of reconsideration.
(See additional discussion in Note 17 of Notes to Financial Statements under
Item 8.)
On Jan. 31, 1994, an appeal of the MPUC's determination on the allowed
return on equity was filed with the Minnesota Court of Appeals by the
Minnesota Department of Public Service, the Office of the Minnesota Attorney
General and the Minnesota Energy Consumers intervenor groups. The appeal
concerns the method of calculating the rate of return on common equity for
both the electric and gas cases. The amount at issue is approximately $7
million in annual revenues for the Company. The ultimate financial impact
of this appeal, if any, is not determinable at this time. A decision by the
court is expected by the end of 1994.
No general rate filings are anticipated in Minnesota in 1994.
North Dakota Public Service Commission (NDPSC)
On May 1, 1992, the Company filed with the NDPSC a general retail
electric rate increase of $8.8 million, or 9.7%. The request was later
reduced to $7.1 million or 7.9%. The NDPSC issued its order on Dec. 15,
1992, granting an increase of $2.7 million or 3%. On Dec. 31, 1992, the
Company filed a petition for reconsideration of several issues contained in
the order. On Jan. 27, 1993, the NDPSC agreed to reconsider the issues
contained in the Company's reconsideration petition. On April 7, 1993, the
NDPSC issued its final order after reconsideration. The final annual rate
increase authorized totaled $4.8 million (5.3%) with rates effective April
21, 1993.
On Dec. 29, 1993, the Company received approval from the NDPSC to
increase base rates $1.2 million, or 1.2%, to recover 1994 cost increases
associated with power purchased from the Manitoba-Hydro Electric Board. The
additional costs consist of demand charges related to 500 Mw of firm capacity
for four months. Eight months of the annual demand costs, which took effect
May 1, 1993, were included in the Company's increase granted in April 1993.
The $1.2 million annual increase was implemented Jan. 5, 1994.
No general rate filings are anticipated in North Dakota in 1994.
South Dakota Public Utilities Commission (SDPUC)
On June 29, 1992, the Company filed with the SDPUC an application for
a general retail electric rate increase of $6.3 million or about 9.8%. A
proposed settlement agreement was reached between Company officials and the
SDPUC staff and filed with the SDPUC on Nov. 10, 1992. The proposed increase
was $4.2 million, or 6.5%. It was effective in two stages: the first stage
on Jan. 1, 1993, equal to $3.8 million, or 5.8%; and the second stage on May
1, 1993, equal to $0.4 million, or 0.7%. In addition, the Company agreed to
a one-year moratorium on rate increases, which means the Company could not
implement further rate increases until Jan. 1, 1995. On Dec. 9, 1992, the
SDPUC issued its order approving the settlement. The settlement agreement did
not address the rate treatment of accrual accounting for postretirement health
care benefits. On Jan. 26, 1993, the SDPUC ordered the Company to continue
to use the pay-as-you-go accounting method, and not the accrual method, for
ratemaking purposes. The Company requested reconsideration of the
Commission's decision on accrued benefits on Feb. 25, 1993. On April 12,
1993, the Commission denied the Company's request for reconsideration. The
Company will seek an accounting order to permit the use of deferred
accounting for such benefits until such treatment is requested in the next
general rate filing. Although the ultimate rate recovery of the accrued
benefits is unresolved, the impact is immaterial to the Company's operating
results ($620,000 on an annual basis).
No general rate filings are anticipated in South Dakota in 1994.
Public Service Commission of Wisconsin (PSCW)
On June 1, 1992, the Wisconsin Company filed with the PSCW for an
overall annual electric rate increase of $10.8 million, or 4.2%, and an
overall annual gas rate increase of $1.4 million, or 2.1%. The PSCW issued
an order dated Jan. 14, 1993, effective on Jan. 16, 1993 granting an increase
in annual electric rates of $8.0 million and an increase in annual gas rates
of $1.1 million. These orders represented a 3.1% increase in electric
operating revenues and a 1.8% increase in gas operating revenues. The
authorized return on common equity in these orders was 12.0%.
On June 3, 1993, as a part of its biennial filing requirement, the
Wisconsin Company filed with the PSCW for an overall annual gas rate increase
of $1.37 million, or 1.9%, and no annual electric rate increase. On Aug. 18,
1993, the Wisconsin Company increased its gas rate request to $1.7 million,
or 2.4%, to recover its allocated share of the acquisition cost of Viking.
The PSCW issued an order dated Dec. 23, 1993, effective Jan. 1, 1994,
granting an increase in annual gas rates of $1.41 million, or 2.0%. The
authorized return on common equity in this order was 11.4%.
Retail Rate Recovery of Viking Acquisition Costs
During 1993, the Company and the Wisconsin Company requested from
regulators in Minnesota, North Dakota, and Wisconsin recovery in retail rates
of a portion of the acquisition cost paid for Viking in recognition of
reduced retail delivered gas costs related to the acquisition of Viking. The
PSCW approved in the Wisconsin Company's rates the pass-through from Viking
and recovery of $1.8 million, related to NSP's acquisition cost of Viking,
over the five-year period 1994-1998. On March 23, 1994, the NDPSC authorized,
without any change in rates, the amortization in jurisdictional expenses of
approximatley $2 million of Viking acquisition costs over a 15 year period
starting June 11, 1993. Recovery of such amortization in base rates would not
commence until approval in the next general rate filing for North Dakota gas
operations. A request for similar recovery is still pending before the MPUC.
If this request is not approved, Viking would continue to expense until 2008
approximately $2 million in acquisition cost amortization each year with
partial rate recovery.
Transmission Access Tariff and Settlement (FERC)
On Oct. 9, 1990, NSP filed an "open access" electric transmission
services tariff with the FERC. The filing was contested by several parties,
including the FERC staff. In April 1992, the FERC Administrative Law Judge
issued an initial decision generally favorable to NSP's positions. On Sept.
21, 1993, the FERC issued an order that affirmed in part, modified in part
and reversed in part the April 1992 initial decision of the Administrative
Law Judge. On Oct. 21, 1993, NSP requested rehearing of the FERC's order.
On Nov. 18, 1993, the FERC granted a tolling order delaying the decision on
NSP's request. The case is currently pending rehearing with the FERC. If
the order is not reversed by the FERC, refunds to customers would be
required. Although the financial impact of this case is immaterial, it is
noteworthy because it is one of the first FERC rulings concerning rates and
terms of contracts for open access of transmission systems.
Minnesota Wholesale Rate Proceedings (FERC)
On Feb. 19, 1993, the Company filed with the FERC a request for
increase in Minnesota wholesale electric rates of $2.3 million, or about 8.7%
(Docket No. ER93-385-000). The Company requested that the new rates become
effective on April 19, 1993, subject to refund with interest pending the FERC
approval of the overall request. On April 20, 1993, the FERC issued an order
accepting the filing and suspending the rate increase for five months. On
August 26, 1993 the Company filed a settlement agreement with the FERC. The
agreement specifies an increase of $0.9 million or about 3.6% effective
Sept. 21, 1993. On Nov. 19, 1993, the FERC issued a final order accepting
the settlement agreement and allowing the rates to become effective. The
nine customers affected by this rate increase have all provided the Company
with notices of termination of their resale power contracts effective in July
1995 (seven customers) and 1996 (two customers) as discussed below. The
settlement calls for no further increases for the duration of service under
the current contracts.
In 1990, 16 of the Company's 19 municipal wholesale customers began
reviewing their long-term power supply options. Nine customers created a
joint action group, Minnesota Municipal Power Agency (MMPA), to serve their
future power supply needs and in 1992 notified the Company of their intent
to terminate their power supply agreements with the Company effective July
1995 or July 1996. These nine customers represent approximately $24 million
in annual revenues and a maximum demand load of approximately 150 Mw.
On Oct. 21, 1993, the MMPA filed a complaint with the FERC under new
Section 211 of the Federal Power Act alleging that the Company had not
bargained in good faith toward a transmission service agreement which would
allow MMPA to deliver power supply to its members starting July 1, 1995,
when the municipalities' supply agreements with the Company expire. On Jan.
26, 1994, the FERC ruled that the Company had bargained in good faith, as
required by Section 211, but ordered the Company and MMPA to negotiate for
sixty days to attempt to resolve remaining issues. If the parties are unable
to reach agreement, the dispute will be submitted to the FERC for a hearing.
The outcome of the case is not expected to have a material financial impact
on the Company's operating results or financial condition.
In 1992 and 1993, the Company signed long-term power supply agreements
with the remaining 10 of its current 19 municipal customers. The agreements
commit the customers to purchase power from the Company for up to 13 years
(through 2005) at fixed rates to increase by up to 3% per year. The 10
customers represent a maximum demand load of approximately 55 Mw and provide
approximately $8 million in annual revenue. The FERC approved formula rates
effective Jan. 1, 1994, by order dated Feb. 23, 1994.
Other Wholesale Rate Proceedings (FERC)
In January 1993, the Wisconsin Company proposed a settlement offer to
increase rates for its 10 municipal wholesale customers. On Feb. 26, 1993,
the Wisconsin Company filed with the FERC a settlement agreement with its 10
wholesale customers calling for a general wholesale rate increase. The
agreements called for a $600,000, or 3.7% overall increase in wholesale
electric rates. FERC accepted the settlement, and the new wholesale electric
rate became effective Sept. 1, 1993.
On May 6, 1993, Viking filed a settlement agreement with the FERC that
called for a $.3 million, or 1.0% overall decrease in wholesale gas
transportation rates. FERC accepted the settlement, and the new wholesale
gas transportation rates became effective July 1, 1993.
Ratemaking Principles in Minnesota and Wisconsin
Since the MPUC assumed jurisdiction of Minnesota electric and gas
rates in 1975, several significant regulatory precedents have evolved. The
MPUC accepts the use of a forecast test year that corresponds to the period
when rates are put into effect and allows collection of interim rates subject
to refund. The use of a forecast test year and interim rates minimizes
regulatory lag.
The MPUC must order interim rates within 60 days of a rate case
filing. Minnesota statutes allow interim rates to be set using (1) updated
expense and rate base items similar to those previously allowed, and (2) a
return on equity equal to that granted in the last MPUC order for the
utility. The MPUC must make a determination on the application within 10
months after filing. If the final determination does not permit the full
amount of the interim rates, the utility must refund the excess revenue
collected, with interest. Generally, the Company may not increase its rates
more frequently than every 12 months.
Minnesota law allows Construction Work in Progress (CWIP) in a
utility's rate base instead of recording Allowance for Funds Used During
Construction (AFC) in revenue requirements for rate proceedings. The MPUC
has exercised this option to a limited extent so that cash earnings are
allowed on small and short-term projects that do not qualify for AFC. (For
the Company's policy regarding the recording of AFC, see Note 1 of Notes to
Financial Statements under Item 8.)
The PSCW has a biennial filing requirement for processing rate cases
and monitoring utilities' rates. By June 1 of each odd-numbered year, the
Wisconsin Company must submit filings for calendar test years beginning the
following January 1. The filing procedure and subsequent review generally
allow the PSCW sufficient time to issue an order effective with the start of
the test year.
The PSCW reviews each utility's cash position to determine if a
current return on CWIP will be allowed. The PSCW will allow either a return
on CWIP or capitalization of AFC at the adjusted overall cost of capital.
The Wisconsin Company currently capitalizes AFC on production and
transmission CWIP at the FERC formula rate and on all other CWIP at the
adjusted overall cost of capital.
Fuel and Purchased Gas Adjustment Clauses
The Company's wholesale and retail electric 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 Wisconsin Company
calculates the wholesale electric fuel adjustment factor for the current
month based on estimated fuel costs for that month. The estimated fuel cost
is adjusted to actual the following month.
The Wisconsin Company's automatic retail electric fuel adjustment
clause for Wisconsin customers was eliminated effective in 1986. The clause
was replaced by a limited-issue filing procedure. Under the procedure, an
annual deviation in fuel costs of 2% and a monthly deviation of 8% will allow
filing for a change in rates limited to the fuel issue. The adjustment
approved is calculated on an annual basis, but applied prospectively. The
PSCW will be holding a technical conference and possibly hearings in 1994 to
determine the appropriate process to handle fuel costs under the new biennial
rate filing process.
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.
The Wisconsin Company's gas and retail electric rate schedules for
Michigan customers include Gas Cost Recovery Factors and Power Supply Cost
Recovery Factors, which are based on 12 month projections. After each 12
month period, a reconciliation is submitted whereby over-collections are
refunded and any under-collections are collected from the customers.
Viking is a transportation-only interstate pipeline and provides no
sales services. As a result, Viking terminated its PGA clause effective Nov.
1, 1993. Natural gas fuel for compressor operations is provided in-kind by
transportation suppliers.
ELECTRIC OPERATIONS
Capability and Demand
Assuming normal weather, NSP expects its 1994 summer peak demand to
be 7,218 Mw. NSP's 1994 summer capability is estimated to be 8,866 Mw,
including 1,340 Mw (including reserves) of contracted purchases from the
Manitoba Hydro-Electric Board, a Canadian Crown Corporation (Manitoba Hydro)
and 677 Mw of other contracted purchases. The estimate assumes 7,241 Mw of
thermal generating capability and 1,625 Mw of hydro generating capability.
Of the total summer capability, NSP has committed 109 Mw for sales to other
utilities. Of the estimated net capability, including the interconnection
with Manitoba Hydro, 30% has been installed during the last 10 years.
NSP's 1993 maximum demand of 6,990 Mw occurred on August 25, 1993.
Resources available at that time included 6,816 Mw of Company-owned
capability and 1,787 Mw of purchased capability net of contracted sales. The
reserve margin for 1993 was 23%. The minimum reserve margin requirement as
determined by the members of the Mid-Continent Area Power Pool (MAPP), of
which NSP is a member, is 15%. (See Note 15 of Notes to Financial Statements
under Item 8 for more discussion of power agreement commitments.)
The Company filed an electric resource plan with the MPUC in 1993.
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
such needs. The plan contains: conservation programs to reduce the Company's
peak energy demand and conserve overall electricity use; economic purchases
of power; and programs for maintaining reliability of existing plants. It
also includes an approximate schedule of timing of such needs. The plan
does not anticipate the need for additional base-load generating plants
during the balance of this century and assumes that the Company's Prairie
Island nuclear generating facility will continue operating through its
license period.
The following resource needs were included in the resource plan. The
plan does not specify the precise technology to meet these needs, but does
suggest energy source options.
Cumulative MW Resource Needs By Type vs. Base of 1993
1996 2000 2004 2008
Peak 0-500 0-500 300-1,100 600-1,800
Intermediate 0-0 0-700 300-1,000 900-1,000
Base 0 0 0-300 200-1,400
DSM 500 1,200 1,700 2,000
Total 300-1,000 1,200-2,400 2,300-4,100 3,700-6,200
The resource plan proposes to satisfy the above resource needs through
a combination of the following options:
Sources of Energy to Meet Needs
- Continued operation of existing generation.
- Demand reduction of 2000 Mw by 2008 through conservation and load
management.
- 100 Mw of wind generation.
- Increased reliance on hydro power under contracts from Manitoba
Hydro.
- Standby generation and cogeneration at customer sites when mutually
beneficial to both NSP and the customer.
- Installation of 210 Mw of natural gas-fired combustion turbines
with an in-service date expected in September 1994.
- Purchase of 232 Mw of natural gas-fired combined cycle generation.
- Competitive bidding to fill additional needs for new generation.
In October 1993, the Company signed a 25-year agreement for the
purchase of 25 Mw of wind-generated electric capacity and associated energy
to be produced in Minnesota. The wind generating plant is expected to be
fully operational by May 1994. This contract is the first phase of the
Company's plan to obtain 100 megawatts of wind-generated electricity by 1997.
The Company can recover the cost of energy purchases through cost-of-energy
adjustment clauses in electric rates.
With respect to conservation, NSP is actively involved in numerous
demand-side management programs. NSP's operating goals, which go beyond the
resource plan guidelines above, are to offset peak electric demand by 1,100
Mw by 1995 and 1,700 Mw by 2000.
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 cogenerators. Electric service also increasingly
competes with other forms of energy. The degree of competition may vary from
time to time, depending on relative costs and supplies of other forms of
energy. Although NSP cannot predict the extent to which its future business
may be affected by supply, relative cost or promotion of other electricity
or energy suppliers, NSP believes that it will be in a position to compete
favorably.
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 proposal
contemplates that NSP's regulated business will not construct new regulated
generation facilities within its service area. However, the Company has
proposed that its subsidiary, NRG, be allowed to bid in response to Company
solicitations for proposals. The Company's competitive bidding proposal is
being reviewed by the MPUC along with the 1993 resource plan. The Company
anticipates an MPUC decision during the second quarter of 1994.
The Company intends to make similar competitive bidding proposal
filings in North Dakota and South Dakota during 1994. Management intends to
obtain regulatory approval in all retail jurisdictions to use a single bid
process to meet resource needs for the entire system. The Wisconsin
Commission has approved the use of competitive bidding for new resources
for all Wisconsin utilities.
On Oct. 24, 1992, President Clinton signed into law the Energy Policy
Act of 1992 (Energy Act). The Energy Act amends the Public Utility Holding
Company Act of 1935 (1935 Act) and the Federal Power Act. Among many other
provisions, the Energy Act is designed to promote competition in the
development of wholesale power generation in the electric utility industry.
It exempts a new class of independent power producers from regulation under
the 1935 Act. The Energy Act also allows the FERC to order wholesale
"wheeling" by public utilities to provide utility and non-utility generators
access to public utility transmission facilities. The provision allows the
FERC to set prices for wheeling, which will allow utilities to recover
certain costs. The costs would be recovered from the companies receiving the
services, rather than the utilities' retail customers. The market-based
power agreement filings with FERC (See discussion in "Regulation and
Revenues", herein.) reflect the trend toward increasing transmission access
under the Energy Act. The Energy Act's ultimate impact on NSP cannot be
predicted.
Many states are currently considering retail wheeling. While the
topic of retail wheeling has been discussed in NSP jurisdictions, no
legislation or regulatory initiatives have been formally introduced. Retail
wheeling represents yet another development of a competitive electric industry.
Management plans to continue its ongoing efforts to be a low-cost supplier
of electricity and an active participant in the more competitive market for
electricity expected as a result of the Energy Act.
Through the functional restructuring discussed on page 1, the Company
has moved responsibility for customer service, product reliability and
profitability to the jurisdictional level within each business sector. This
restructuring and business realignment will continue within each business
sector through 1994. The Customer Operations Delivery system is being
streamlined by consolidating similar functions. The Company is continuing
an extensive reliability project that includes preventive maintenance on
transmission and distribution power lines, improvements to existing
equipment, and testing and implementing new technology. Reliability efforts
are focusing on reducing the number of outages caused by lightning, human
errors, animals and trees.
NSP created the Delivery Operations Department in 1993 to consolidate
operation of its transmission and distribution systems. This department
monitors the flow of electricity on the transmission network in NSP's five-
state service area. It directs all switching of the Company's transmission
equipment in Minnesota. In the Twin Cities metropolitan area, it monitors
the flow of electricity on the distribution network, directs field switching,
and directs field personnel to respond to trouble events.
Energy Sources
For the year ended Dec. 31, 1993, 48 percent of NSP's Kwh requirements
was obtained from coal generation and 28 percent was obtained from nuclear
generation. Purchased and interchange energy provided 20 percent, including
13 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 (60 percent), nuclear (35 percent), renewable and other fuels (5
percent).
The following is a summary of NSP's electric power output in millions
of kilowatt-hours for the past three years:
1993 1992 1991
Thermal plants 33 130 30 467 31 335
Hydro plants 1 001 1 024 1 153
Purchased and interchange 8 541 8 187 7 019
Total 42 672 39 678 39 507
Many of NSP's power purchases from other utilities are coordinated
through the regional power organization MAPP. NSP is one of 29 participants
in MAPP consisting of 10 investor-owned systems, eight generation and
transmission cooperatives, three public power districts, seven municipal
systems and the Department of Energy's Western Area Power Administration.
MAPP membership also includes 15 Liaisons/Associate Participants consisting
of two Canadian Crown Corporations, 12 municipal systems, and one investor-
owned system, which are members of MAPP, pursuant to an agreement dated March
31, 1972. This agreement provides for the members to coordinate the
installation and operation of generating plants and transmission line
facilities. The terms and conditions of the MAPP agreement and transactions
between MAPP members are subject to the jurisdiction of the FERC. The 1972
MAPP agreement was accepted for filing by the FERC, effective Dec. 1, 1972.
As discussed in Note 15 of Notes to Financial Statements in Item 8,
significant increases in purchased power may be required beginning in 1995
if the Prairie Island generating facility can not continue operating.
Fuel Supply and Costs
Coal and nuclear fuel will continue to dominate NSP's fuel
requirements for generating electricity. It is expected that approximately
98 percent of NSP's fuel requirements, on a Btu basis, will be provided by
these two fuels over the next several years, leaving two 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 1993 and the estimated fuel mix
for 1994 and 1995 are as follows:
Fuel Use on Btu Basis
(Est) (Est)
1993 1994 1995
Coal 62.3% 62.9% 61.2%
Nuclear 36.2% 35.4% 37.1%
Other 1.5% 1.7% 1.7%
The Company normally maintains approximately 30 days of coal inventory
(between 20 and 45 days, depending on plant site). The Company has long-term
contracts providing for the delivery of up to 99 percent of its 1994 coal
requirements. Coal delivery may be subject to short-term interruptions or
reductions due to transportation problems, weather and availability of
equipment.
The Company expects that more than 96 percent of the coal it burns in
1994 will have a sulfur content of less than 1 percent. The Company has
contracts with two Montana coal suppliers, Westmoreland Resources and Western
Energy, and three Wyoming suppliers, Rochelle Coal Company, Antelope Coal
Company and Black Thunder Coal Company, for a maximum total of 85 million
tons of low-sulfur coal for the next 10 years. These arrangements are
sufficient to meet the requirements of existing coal-fired plants. They also
permit the Company to purchase additional coal when such purchase would
improve fuel economics and operations. The Company has options from
suppliers for over 100 million tons of coal with a sulfur content of less
than 1 percent that could be available for future plants. 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 Wisconsin Company's electric
generating plants are primarily hydro plants.
The estimated coal requirements of the Company at its major existing
coal-fired generating plants for the periods indicated and the coal supply
for such requirements are as follows:
State
Sulfur Dioxide
Maximum Amount Contract Approximate Emission Limit
Annual Covered by Expiration Sulfur Pounds Per
Plant Demand Contract Date Content(%)(2) MBTU*Input
(Tons) (Tons)
Black Dog 1 000 000 1 000 000 (1) 0.5 3.0(3)
High Bridge 800 000 800 000 (1) 0.5 3.0
Allen S. King 2 000 000 2 000 000 (1) 0.9 1.6(4)
Riverside 1 200 000 1 200 000 (1) 0.7 2.5(5)
Sherco 8 000 000 8 000 000 (1) 0.5 0.9(6)
13 000 000 13 000 000(7)
*MBTU = Million British Thermal Units
Notes:
(1) Contract expiration dates vary between 1995 and 2005 for western coal,
which can provide more than 95% of the required fuel supply for the
designated generating unit. Spot purchases of western and midwestern
coal, and other fuels will provide the remaining fuel requirements.
The Company is also test burning petroleum coke as a potential fuel.
(2) This figure represents the average blended sulfur content of the
combination of fuels typically burned at each plant.
(3) The Black Dog Fluidized Bed (Unit 2) SO2 limit is 1.2 lb/MBTU.
(4) The King Plant SO2 limitation of 1.9 lb/MBTU expired in January 1991,
but the Minnesota Pollution Control Agency (MPCA) approved a short-
term extension during permit negotiations. This interim limit was
lowered to 1.8 lb/MBTU in May 1993. A final decision from the MPCA
was reached in February 1994 setting a limit of 1.6 lb/MBTU.
(5) 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.
(6) Compliance with air pollution control permit and applicable air
quality regulations requires use of limestone scrubbers to achieve 70%
SO2 removal and to limit SO2 emission to 0.96 lb/MBTU during any 90-
day period for Units 1 and 2. For Unit 3, the SO2 emission limit is
0.61 lb/MBTU.
(7) Required annual deliveries are no less than 6.0 million tons per year.
Annual requirements are expected to range from 11.0 to 12.5 million.
NSP's current fuel oil inventory is adequate to meet anticipated 1994
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 agreements for complete nuclear fuel cycles, which include uranium
concentrate (yellowcake), uranium conversion, uranium enrichment services and
fuel fabrication.
The Company's current nuclear fuel contractual commitments are
summarized below:
Nuclear Fuel
Services Contract Duration
Monticello Prairie Island No. 1 Prairie Island No. 2
Yellowcake 1998 (1) 1998 (1) 1998 (1)
Conversion 1999 (2) 1999 (2) 1999 (2)
Enrichment 2005 (3) 2005 (3) 2005 (3)
Fabrication 1998 (4) 2004 2004
(1) The yellowcake requirements are approximately 60% under contract for
1994-1997 and 15% for 1998.
(2) The uranium concentrate conversion services are approximately 60%
under contract for 1994-1997 and 35% for 1998-1999.
(3) 100% of enrichment requirements are under contract for 1994-1995. The
enrichment requirements are approximately 45% covered under a
combination of firm contracts plus options for 1996-2005.
(4) The Company has options to supply its needs through 2001.
The Company expects sufficient uranium to be available for the total
fuel requirements of its existing plants. The nuclear fuel contract strategy
involves a portfolio of long- and medium-term contracts, as well as spot
purchases. There are no assurances regarding the ultimate costs of any of
the components of the fuel cycle or what impact any governmental legislation
may have. However, 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 an electrical generation facility.
The cost of nuclear fuel, including disposal, is recovered in the customer
price of the electricity sold by the Company.
NSP's fuel costs for the past three years are shown below:
Fuel Costs *
Per Million Btu
Year Ended December 31
1991 1992 1993
Coal** $ 1.24 $ 1.22 $1.17
Nuclear*** .47 .43 .41
All Fuels .95 .93 .90
* Fuel adjustment clauses in its electric rate schedules or statutory
provisions enable NSP to adjust for fuel cost changes. (See "Regulation
and Revenues - Fuel and Purchased Gas Adjustment Clauses" under Item 1.)
** Includes refuse-derived fuel and wood.
*** See Note 1 of Notes to Financial Statements under Item 8 for an
explanation of the Company's nuclear fuel amortization policies.
Nuclear Power Plants - Licensing, Operation and Waste Disposal
The Company operates two nuclear generating plants: the single unit,
539 Mw Monticello Nuclear Generating Plant and the Prairie Island Nuclear
Generating Plant with two units totaling 1,025 Mw. The Monticello Plant
received its 40-year operating license from the Nuclear Regulatory Commission
(NRC) on Sept. 8, 1970, and commenced operation on June 30, 1971. Prairie
Island Units 1 and 2 received their 40-year operating licenses on Aug. 9,
1973, and Oct. 29, 1974, respectively, and commenced operation on Dec. 16,
1973, and Dec. 21, 1974, respectively.
The Prairie Island and Monticello nuclear plants currently hold the
Institute of Nuclear Power Operations' (INPO) top rating for plant operations
and training. The Company is the only utility in the nation to achieve
INPO's top rating simultaneously at all of its nuclear plants.
The Company previously operated the Pathfinder Plant near Sioux Falls,
SD as a nuclear plant from 1964 until 1967, after which it was converted to
an oil and gas-fired peaking plant. The nuclear portions were placed in a
safe storage condition in 1971, and the Company began decommissioning them
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 millicurie of residual contamination remain in the operating
plant.
Operating nuclear power plants produce gaseous, liquid and solid
radioactive wastes. The discharge and handling of such wastes are controlled
by federal regulation. For commercial nuclear power plants, high-level
radioactive wastes include only spent 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.
The primary purpose of in-plant storage of low-level radioactive waste
is to accumulate an inventory of material for economical shipment. Low-level
waste disposal sites have been licensed in New York, Kentucky, Illinois,
South Carolina, Nevada and Washington. At present, only South Carolina has
an operating site that accepts commercial wastes from Minnesota.
A 1980 federal law places responsibility on each state for disposal
of its low-level radioactive waste. The law encourages states to form
regional agreements or compacts to dispose of regionally generated waste.
Minnesota is a member of the Midwest Interstate Low-Level Radioactive Waste
Compact Commission. Following the expulsion of Michigan from the Midwest
Compact in 1991 for failing to make progress, Ohio was designated the host
state. The 1980 law, as amended in 1985, requires disposal sites to be
operational after 1992. The South Carolina site has extended its closure
date to out-of-region waste until June 30, 1994. Ohio is projecting
completion of the low-level radioactive waste disposal facility in 2001. The
Company, along with all other low-level radioactive waste generators in the
Midwest Compact, will need to store low-level radioactive waste onsite in the
interim.
The federal government has the responsibility to dispose of 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 repositories for domestically produced spent
nuclear fuel from civilian nuclear power reactors and other high-level
radioactive wastes.
The Company has contracted with the DOE for the disposal of spent
nuclear fuel. The DOE charges a quarterly disposal fee based on nuclear
electric generation sold. This fee ranges from approximately $10 million to
$12 million per year, which NSP recovers from its customers in cost-of-energy
rate adjustments. Revisions to the DOE's basis of charging customers will
result in fee reductions of $8.3 million, including reductions of $3.7
million already realized in 1992 and $3.6 million in 1993. In 1985, NSP paid
the DOE a one-time fee of $95 million for fuel used prior to April 7, 1983.
In 1979, the Company began expanding the spent nuclear fuel storage
facilities at its Monticello Plant by replacement of the racks in the storage
pool. Also, in 1987, the Company completed the shipment of 1,058 spent fuel
assemblies from the Monticello Plant to a General Electric storage facility
in Morris, Illinois. As a result, the plant now has sufficient pool storage
capacity to operate until 2008. For discussion of spent nuclear fuel storage
facilities at the Company's Prairie Island Plant, see "Environmental Matters"
herein, Management's Discussion and Analysis of Financial Condition and
Results of Operations under Item 7 and Note 15 of Notes to Financial
Statements under Item 8.
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 $523 million since 1971, and expects to expend an additional $9 million
for currently required NRC analyses, modification and additional equipment.
The NRC is engaged in various ongoing studies and rulemaking activities that
may impose additional requirements upon commercial nuclear power plants.
Management is unable to predict any new requirements or their impact on the
Company's facilities and operations.
See Note 15 of Notes to 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.
GAS OPERATIONS
Capability and Demand
NSP catagorizes 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 642,684 MMBtu for 1993 occurred on Dec. 27, 1993. This
was also NSP's all time maximum daily sendout through Dec. 31, 1993.
As discussed below, NSP's primary gas supply sources are purchases of
third-party gas which are delivered under gas transportation service
agreements with interstate pipelines. These agreements provide for firm
deliverable pipeline capacity of approximately 511,000 MMBtu/day. In
addition, NSP has contracted with four providers of underground natural gas
storage services to meet the heating season and peak day requirements of NSP
gas customers. Using storage reduces the need for firm gas supplies. These
storage agreements provide NSP storage for approximately 15% of annual and
28% of peak daily firm requirements at an annual fixed cost of $5.1 million.
NSP also owns and operates three liquefied natural gas (LNG) plants with a
storage capacity of 2.53 Bcf equivalent and four propane-air plants with a
storage capacity of 1.42 Bcf equivalent to help meet the peak requirements of
its firm residential, commercial and industrial customers. These peak shaving
facilities have production capacity equivalent to 237,900 Mcf of natural gas
per day, or approximately 42% of peak day firm requirements. The Company
expanded this daily deliverability by approximately 16,000 Mcf/day in 1993
through minor capital additions to a propane-air peaking plant. Recovery of
the capital cost of this addition was included in the Company's Minnesota
retail gas rates approved by the MPUC on Dec. 30, 1993. These LNG and
propane-air plants provide a cost-effective alternative to annual pipeline
transportation charges to meet the "needle peaks" caused by firm space heating
demand on extremely cold winter days.
The cost of gas supply, transportation service and storage service is
recovered through the purchased gas adjustment. The average cost of gas and
propane held in inventory for the latest test year is allowed in rate base
by the MPUC and the PSCW.
A number of NSP's interruptible industrial customers purchase their
natural gas requirements directly from producers or brokers for transportation
and delivery through NSP's distribution system. The transportation rates have
been designed to make NSP economically indifferent as to whether NSP sells
and transports gas or only transports gas. However, to the extent
contractual terms allow, rates would increase based on changes in
transportation and other costs.
Competition
During 1992 and 1993, the FERC issued a series of orders (together
called Order 636) that addressed interstate natural gas pipeline
restructuring. This restructuring required all interstate pipelines,
including those serving NSP, to "unbundle" each of the services they provide:
gathering, transportation, storage, sales and pipeline delivery management.
To comply with Order 636, NSP executed new pipeline transportation service and
gas supply agreements effective Nov. 1, 1993, as discussed below. While these
new agreements create a new form of contractual obligation, NSP believes the
new agreements provide flexibility to respond to future changes in the
retail natural gas market. NSP expects its financial risk under the new
agreements to be no greater than the risk faced under the previous long-term
full requirements gas supply contracts.
As a result of the changes in the natural gas industry in the last
decade, culminating in Order 636, NSP's natural gas supply network has been
transformed into an integrated gas supply grid where NSP purchases natural
gas from numerous suppliers, directly contracts for transportation service
on directly connected and upstream pipelines, and is able to flexibly deliver
the supplies to any NSP retail gas service territory. In addition, NSP
directly contracted for underground storage and owns and operates several
liquified natural gas and propane-air peak shaving facilities. NSP's
diversified supply and transportation contracts, as well as underground
storage and peak shaving facilities, provide NSP with the ability to meet
customer needs with reliable and economic natural gas supply.
Order 636 ended the traditional pipeline sales service function
effective Nov. 1, 1993. This is a significant change for the natural gas
industry. Traditionally, the pipeline sales function met two important needs
for local distribution companies (LDCs) such as NSP, which serve primarily
weather-sensitive space heating markets: 1) reliability of supply and 2)
flexibility to meet varying load conditions in response to day-to-day weather
variations. NSP believes some uncertainty remains as to whether the new
unbundled services under Order 636 will prove to be as reliable and flexible
as the traditional sales service.
The implementation of Order 636 will apply additional competitive
pressure on all LDCs 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 as to whether it sells or transports gas. However,
some transportation customers may have greater opportunities or incentives to
physically bypass the LDC's 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 expects Order 636
will enhance its ability to remain competitive and allow it to maximize its
margins by providing an increased selection of services to its customers.
Order 636 allows interstate pipelines to negotiate with customers to
recover up to 100 percent of prudently incurred "transition costs"
attributable to Order 636 restructuring. Recoverable transition costs can
include "buy down" and "buy out" costs for remaining gas supply and upstream
pipeline transportation agreements, unrecovered deferred gas purchase costs,
and the cost to dispose of regulated assets no longer needed because of the
termination of the merchant function (e.g., financial losses on the sale of
regulated storage facilities).
NSP's primary gas supplier, Northern Natural Gas Company (Northern),
is currently in the process of determining the amount of transition costs to
be passed on to customers, as a result of Order 636 restructuring. Northern's
restructuring has provided for the assignment of a significant portion of
Northern's gas supply and upstream contract obligations. This solution was
beneficial because Northern's customers contracted directly for obligations,
rather than paying to buy out of those obligations and then contracting with
the same gas suppliers and pipelines to replace the merchant function. The
total transition costs recoverable for the remaining unassigned agreements is
limited to $78 million. In addition, Northern may seek transition cost
recovery for certain other costs, subject to prudency review. Northern's
total Order 636 transition costs, to be passed on to all of its customers,
are estimated to be approximately $100 million. Northern will recover the
prudent transition costs by amortizing the amount over a period of several
years, and including the amortized costs as a component of customer demand
charges. NSP estimates that it will be billed for approximately 10 percent
of Northern's transition costs, spread over a period of approximately five
years. NSP's regulatory commissions have previously approved recovery of
similar restructuring charges in retail gas rates.
NSP has no Order 636 transition cost responsibilities to its other
pipeline suppliers. FERC has ruled that NSP has no transition cost obligation
to Williston Basin Interstate Pipeline Company (Williston) since it was never
a gas sales customer of that pipeline. Viking incurred no Order 636 transition
costs.
The gas services available to NSP's customers were expanded in 1993
through the acquisitions of Viking in June 1993 and the assets of a gas
marketing business by a new NSP subsidiary, Cenergy, Inc, in October 1993.
The acquisition of Viking allows NSP increased access to natural gas
transportation. Cenergy's acquisition of a gas marketing business will
allow NSP to provide more customized value-added energy services to retail
gas customers without increasing costs within the regulated retail gas
distribution business. (See Note 4 of Notes to Financial Statements in
Item 8 and the Other Subsidiaries section herein for further discussion of
Viking and Cenergy.)
The NSP gas operations area has taken significant steps to position
itself to take on the additional responsibilities and take advantage of the
new market opportunities resulting from the restructuring of the natural gas
industry. In addition to construction of new pipeline interconnections,
modernization of its propane-air peaking facilities, and fundamental changes
to its supply portfolio including underground storage, NSP is installing a
state-of-the-art delivery management system.
Gas Supply and Costs
NSP provides retail gas service in portions of eastern North Dakota
and northwestern Minnesota, the eastern portions of the Twin Cities metro
area, and other regional centers in Minnesota (Mankato, St. Cloud and Winona)
and Wisconsin (Eau Claire, La Crosse and Ashland). NSP is directly connected
to four interstate natural gas pipelines serving these regions: Northern,
Viking, Williston and Great Lakes Transmission Pipeline. Approximately 90
percent of NSP's retail gas customers are served from the Northern pipeline
system. As recently as 1987, NSP was able to purchase only "full
requirements" pipeline sales supply, where NSP purchased the full
requirements of its retail customers in a particular NSP gas service
territory from the directly interconnected pipeline, and resold this gas to
retail customers.
As a result of Order 636 restructuring, NSP's natural gas supply
commitments have been unbundled from its gas transportation and storage
commitments. NSP's gas utility actively seeks gas supply, transportation and
storage alternatives to yield a diversified portfolio that provides increased
flexibility, decreased risk and economical rates. This diversification
involves numerous domestic and Canadian supply sources, varied contract
lengths, and transportation contracts with seven natural gas pipelines.
The Company's supply options were enhanced in 1992 with the successful
completion of a direct interconnection to the Williston system near Fargo,
North Dakota. The addition of this direct connection allows the Company more
direct access to additional productive gas supply basins in western North
Dakota and Wyoming, and provides the Company an alternative to its two
traditional pipeline suppliers (Northern and Viking).
Among other things, Order 636 provides for the use of the "straight
fixed/variable" rate design that allows pipelines to recover all their fixed
costs through demand charges. NSP has firm gas transportation contracts with
the following seven pipelines. The contracts expire in various years from
1994 through 2012.
Northern Natural Gas Great Lakes Transmission
Williston Basin Interstate Northern Border Pipeline
Viking Gas Transmission ANR Pipeline
TransCanada Gas Pipeline
The agreements with Great Lakes, Northern Border, ANR and TransCanada
provide for firm transportation service upstream of Northern Natural and
Viking, allowing competition among suppliers at supply pooling points,
minimizing commodity gas costs.
In addition to these fixed transportation charge obligations, NSP has
entered into firm gas supply agreements that provide for the payment of
monthly or annual reservation charges irrespective of the volume of gas
purchased. The total annual obligation is approximately $11.7 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, 1993, NSP was committed
to approximately $607 million in such obligations under these contracts,
over the remaining contract terms, which range from the years 1994-2013.
These obligations include some of the effects of contract revisions made
to comply with Order 636.
NSP purchases firm gas supply from a total of approximately 20
domestic and Canadian suppliers under contracts with durations of one year
to 10 years. NSP purchases no more than 20% of its total daily supply from
any single supplier. This diversity of suppliers and contract lengths allows
NSP to maintain competition from suppliers and minimize supply costs. NSP's
objective is to be able to terminate its retail merchant sales function, if
either demanded by the marketplace or mandated by regulatory agencies, with
no financial cost to NSP.
The state utility commissions in Minnesota, North Dakota, Wisconsin
and Michigan allowed NSP to fully recover the costs of these restructured
services through purchased gas adjustments to customer rates. The MPUC
and the PSCW also have allowed NSP to reflect in rate base the average cost
of gas inventory held in underground storage.
Purchases of gas supply or services by NSP from its Viking pipeline
affiliate and Cenergy gas marketing affiliate are subject to approval by the
MPUC. A request for approval of the NSP/Viking transportation agreements is
pending approval. NSP currently does not purchase system gas supply or
services from Cenergy, but anticipates requesting such authority in 1994.
The MPUC has previously approved similar affiliate gas supply transactions
between Minnegasco, which is another Minnesota LDC, and Arkla, Inc., an
affiliated interstate pipeline and gas marketing company.
The following table details selected operating information for NSP's
gas distribution business which excludes Viking and Cenergy:
Average Total Customers
Cost Deliveries * at
Per MMBtu Bcf Year-End
Minnesota
1990 $2.76 66.1 303,189
1991 $2.50 72.6 311,354
1992 $2.71 68.1 319,673
1993 $3.11 79.8 328,306
Wisconsin
1990 $2.65 14.1 54,966
1991 $2.73 14.4 58,446
1992 $2.80 14.9 62,065
1993 $3.02 17.0 65,155
* Includes sales and transportation services.
TELEPHONE OPERATIONS
On Jan. 31, 1991, the Company sold its telephone properties and
operations located in North Dakota to Rochester Telephone Corporation of
Rochester New York for $48 million in cash. The net of tax gain on the sale
of $16.8 million (27 cents per average common share) was recorded in the
first quarter of 1991. The telephone operations historically accounted for
less than 2% of NSP's earnings.
NRG ENERGY, INC.
NRG Energy, Inc. (NRG) is the Company's subsidiary that develops,
builds, acquires, owns and operates several of the Company's 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. The businesses that NRG currently owns or operates
generated 1993 revenues of $66 million and had assets of $275 million at Dec.
31, 1993. These assets include $37 million of investments in and capitalized
development costs for projects NRG is currently pursuing, as discussed in the
"New Business Development" section.
The subsidiaries of NRG Energy, Inc., which currently conduct business
are: NRG International, Inc.; Graystone Corporation; Scoria Incorporated;
San Joaquin Valley Energy I, Inc.; San Joaquin Valley Energy IV, Inc.; NRG
Energy Jackson Valley I, Inc.; NRG Energy Jackson Valley II, Inc., and NRG
Energy Center, Inc.
Operating Businesses
NRG operates two refuse-derived fuel (RDF) processing plants and an
ash disposal site. The ownership of one plant was transferred by the Company
to NRG at the end of 1993, while legal transfer of ownership of the Company's
85% share of the other RDF plant and the ash disposal site is pending
contract approval by the serviced counties. In 1993, workers at the RDF
plants processed more than 820,000 tons of municipal solid waste into
approximately 660,000 tons of refuse-derived fuel that was burned at two NSP
power plants and at a power plant owned by United Power Association.
NRG also owns and operates three steam lines in Minnesota that provide
steam from the Company's power plants to the Waldorf Corporation, the
Andersen Corporation and the Minnesota Correctional Facility in Stillwater.
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, is expected to
produce 300,000 tons of clean coal annually which, when burned, produces
emissions in compliance with the Clean Air Act. The fuel may be an
alternative to scrubbers for some energy companies. Testing of the plant
ended in August 1993 and commercial operations began at that time.
San Joaquin Valley Energy I, Inc.; San Joaquin Valley Energy IV, Inc.,
and NRG Energy Jackson Valley II, Inc. own 45% of the San Joaquin Valley
Energy partnership, which owns four power plants located near Fresno,
California with a total capacity of 45 Mw. The facilities are operating
fluidized-bed biomass, waste-fueled cogeneration plants. All four plants
have long-term power sales agreements with Pacific Gas & Electric through
2017.
NRG Energy Jackson Valley I, Inc., and NRG Energy Jackson Valley II,
Inc. own 50% of the Jackson Valley Energy partnership, which owns and
operates a 15-Mw cogeneration power plant near Sacramento, California. The
plant has a long-term power sales agreement with Pacific Gas & Electric
through 2014.
On Aug. 20, 1993, NRG Energy Center, Inc. purchased the assets of the
Minneapolis Energy Center (MEC), a downtown Minneapolis district heating and
cooling system. The system utilizes steam and chilled water generating
facilities to heat and cool buildings for approximately 85 heating and 25
cooling customers in downtown Minneapolis. The primary assets include the
main plant, three satellite plants, two standby plants, six miles of steam
lines and two miles of chilled water distribution lines. The MEC was
purchased from Energy Center Partners. Existing long-term contracts with MEC
customers will remain in effect under NRG's ownership. The purchase price
was $110 million, financed mainly with $84 million of project debt. The
purchase price primarily included facilities, long-term service agreements
and goodwill. (See Note 4 of Notes to Financial Statements under Item 8 for
further discussion).
New Business Development
NRG is pursuing several energy-related investment opportunities, as
discussed below. Many of these opportunities are joint venture projects,
which would be financed primarily through debt at the project level. The
remaining project costs are expected to be funded through equity investments
from NRG and other investors. Depending on NRG's ultimate involvement in
such opportunities, these projects could require equity investments of
approximately $390 million by NRG for the five year period 1994-1998.
Graystone Corporation, with several other companies, continues with
permitting plans to build the first privately owned uranium enrichment plant
in the United States. Construction of the Louisiana plant, which would
provide fuel for the nuclear power industry, could begin in 1995.
On June 10, 1993, NRG, together with the International Finance
Corporation (an affiliate of the World Bank), CMS Energy Corporation (the
parent company of Consumers Power Company) and later Corporation Andina de
Fomento (CAF) formed the Scudder Latin American Trust for Independent Power,
an investment fund which is intended to invest in the development of new
power plants and privatization of existing power plants in Latin America and
the Caribbean. The fund has retained Scudder Stevens & Clark as its
investment manager. The fund commenced its investment development efforts
in September 1993. Each of the investors has committed $25 million which the
fund is seeking to invest over the next five years. The fund has commenced
private placement activities to obtain additional investors in the fund,
particularly other utility affiliates and institutional investors.
On Dec. 10, 1993, NRG International, Inc., through a wholly owned
foreign subsidiary, acquired a 50% interest in a German corporation, Saale
Energie GmbH (Saale). Saale owns a 400 Mw share in the 900 Mw power plant
currently under construction in Schkopau, Germany, which is near Leipzig.
PowerGen plc of the United Kingdom acquired the remaining 50% interest in
Saale. Saale was formed to acquire a 41.1% interest in the power plant.
VEBA Kraftwerke Ruhr AG of Gelsen-Kirchen, Germany (VEBA), is the builder of
the Schkopau plant. VEBA, which will own the remaining 59.9% interest in the
power plant and the remaining 500 Mw share in the plant, will operate the
plant. The plant will be fired by brown coal (lignite) mined by MIBRAG GmbH
(MIBRAG) under a long-term contract. Saale has a long-term power sales
agreement for its 400 Mw share with VEAG of Berlin, Germany, the company that
controls the high-voltage transmission of electricity in the former East
Germany. The first unit of the plant is due to be completed by the end of
1995 and the second unit is due to be completed in mid-1996.
On Dec. 19, 1993, NRG International, Inc., through another wholly
owned foreign subsidiary, agreed to acquire a 33% interest in the coal
mining, power generation and associated operations of MIBRAG, located south
of Leipzig, Germany. MIBRAG is a German corporation newly 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, three small industrial power plants and a
circulating fluidized bed power plant presently under construction and
scheduled for completion in 1994, a district heating system and coal
briquetting and dust production facilities. Under the acquisition agreement,
Morrison Knudsen Corporation and PowerGen plc each agreed to also acquire a
33% interest in MIBRAG, while the German government retains a one-percent
interest in MIBRAG. The acquisition is expected to close in 1994.
NRG's equity commitment to the two German projects through 1996 is
expected to be no more than $100 million.
On March 4, 1993, NRG International, Inc. signed a letter of intent
pursuant to which it agrees, on behalf of it or a wholly owned subsidiary,
to join an unincorporated joint venture with Comalco Limited of Australia
(Comalco) and other parties. The joint venture is currently in negotiations
for the acquisition, from the Queensland Electricity Commission, of the
Gladstone Power Station, a 1680-Mw coal-fired plant in Gladstone, Queensland,
Australia. A large portion of the electricity would be sold to Comalco for
use in its aluminum smelter, pursuant to long-term power purchase agreements.
NRG International, Inc. expects to acquire a 37.5% interest in the Gladstone
plant. A wholly owned subsidiary of NRG International, Inc. will operate the
Gladstone plant. Closing of the transaction is expected in 1994. NRG's
total equity investment in the Gladstone project is expected to range from
approximately $60 million to $70 million.
In 1992, NRG had investment writedowns and losses from unsuccessful
non-regulated energy projects of $6.8 million before income taxes. This
included an investment in Cypress Energy Partners, a limited partnership
formed between NRG and Black and Veatch Power Development Corporation.
Cypress Energy Partners was denied permission by the Florida Public Service
Commission to build two, 400 Mw electric generating plants for Florida Power
and Light. An appeal with the Florida Supreme Court against the Commission
was filed and subsequently withdrawn.
OTHER SUBSIDIARIES
Viking Gas Transmission Company
On June 10, 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, for $45 million, $32 million of which was financed
with project debt. 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 400
million cubic feet per day. The Viking pipeline currently serves 12% of
NSP's gas distribution system needs. Approximately 75% of NSP's gas
customers are located within 40 miles of the Viking pipeline. 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. (See Note 4 of Notes to
Financial Statements under Item 8 for further discussion.)
Cenergy, Inc.
On Oct. 1, 1993, Cenergy, Inc., a non-regulated subsidiary of the
Company, acquired from bankruptcy certain assets of Centran Corporation, a
natural gas marketing company, for approximately $4 million. The acquisition
was completed to offer a variety of energy options, to increase natural gas
supply flexibility for existing NSP customers and to expand NSP's energy
services nationwide. The energy services marketing company will offer a
broad range of energy services, while focusing on commercial and industrial
end-users of natural gas. Cenergy serves approximately 300 customers. (See
Note 4 of the Notes to Financial Statements under Item 8 for further
discussion.)
Eloigne Company
In 1993, the Company established a new subsidiary, Eloigne Company
(Eloigne), to identify and develop affordable housing investment
opportunities. Eloigne's principal business is the acquisition of a broadly
diversified portfolio of rental housing projects which qualify for low income
housing tax credits under federal tax law. Elogine's capital investments and
operating results for 1993 were not material.
NEO Corporation
During 1993, the Company formed NEO Corporation, a wholly owned
subsidiary, which owns a 50% interest in Minnesota Methane LLC. Minnesota
Methane LLC is developing small scale waste to energy opportunities utilizing
landfill gas. NEO Corporation's capital investments and equity in the 1993
operating results of Minnesota Methane were not material.
ENVIRONMENTAL MATTERS
NSP's policy is to proactively prevent adverse environmental impacts,
regularly monitor operations to ensure the environment is not adversely
affected, and take timely corrective actions where past practices have had
a negative impact on the environment. Significant resources are dedicated
to environmental training, monitoring and compliance matters. NSP believes
that it is in compliance, in all material respects, with applicable
environmental laws.
The Company has spent approximately $685 million on environmental
improvements to new and existing facilities since 1968. Historically, the
Company has spent an average of approximately $26 million annually in
connection with environmental improvements for existing and new facilities.
The Company expects to incur approximately $9 million in capital expenditures
for compliance with environmental regulations in 1994. In general, the
Company has been experiencing a trend toward more environmental monitoring
and compliance costs, which has caused and may continue to cause slightly
higher operating expenses and capital expenditures. The precise timing and
amount of environmental costs are currently unknown. (For further discussion
of costs, see Note 15 of Notes to Financial Statements under Item 8.)
Permits
NSP is required to seek renewals of environmental operating permits
for its facilities at least every five years. NSP believes that it is in
compliance, in all material respects, with environmental permitting
requirements.
Waste Disposal
The Company has proposed construction of an onsite dry cask
(container) storage facility for spent nuclear fuel at its Prairie Island
Nuclear Generating Plant (Prairie Island) near Red Wing, Minnesota that will
provide additional onsite storage. At current operating levels, the current
Prairie Island onsite storage pool will be filled in 1994. Without
additional onsite storage, operations at Prairie Island, which supply about
20% of the Company's output, will begin to be curtailed in mid-1995 and the
plant will cease operating by early 1996. The design and operation of the
proposed facility will be regulated by the Nuclear Regulatory Commission
(NRC) and must meet applicable health and safety standards. Application for
a Part 72 license was submitted to the NRC in August 1990. The NRC published
a favorable Environmental Assessment for the project in June 1992. In
October 1993, the NRC issued the Company a 20-year license to store fuel in
up to 48 casks at the Prairie Island facility. In addition to the NRC
license, the Company is required to obtain state approval for the proposed
facility. In May 1991, the Minnesota Environmental Quality Board voted to
declare the environmental impact statement prepared for the project, which
found no significant environmental impacts, adequate. A Certificate of Need
Application (CON) for 48 containers for temporary storage of spent nuclear
fuel was filed with the MPUC and hearings were held during the latter part
of 1991. A decision to grant the CON was announced by the MPUC in 1992.
Seventeen containers for temporary storage of spent nuclear fuel were
approved, which would provide adequate storage at least through the year
2001. In November 1992, the Minnesota Court of Appeals received a joint
petition from several parties seeking a reversal of the MPUC's decision. In
June 1993, the Minnesota Court of Appeals ruled that the Prairie Island spent
fuel storage facility falls under the requirements of the Minnesota
Radioactive Waste Management Act and, therefore, requires legislative
approval before the Company can begin to store fuel. Petitions by the
Company, MPUC, and the Minnesota Department of Public Service to the
Minnesota Supreme Court to review the Appeals Court decision were denied.
Upon denial by the Supreme Court to review the case, the Company immediately
halted all construction and fabrication activities in order to bring the
Company in compliance with the law. The Company has requested approval for
the facility from the Minnesota Legislature during the 1994 session which
began on Feb. 22, 1994.
The bill allowing NSP to construct an onsite dry cask storage facility
at Prairie Island is being considered by two committees of the Minnesota
State House of Representatives (House) and two committees of the Minnesota
State Senate (Senate). Both the House and Senate energy committees have
passed the bill. The Senate environmental committee defeated the bill and
refused to refer it to the Senate floor by a 10-8 vote. A hearing of the
House environmental committee has not been scheduled. The time limit for
consideration of the bill by the House and Senate committees expires March
25, 1994. If these committees do not approve the bill by that time, efforts
will be made to obtain approval on the House and Senate floors.
The consequences of not receiving legislative approval would include
premature shutdown of the Prairie Island plant, the need to obtain
replacement power to meet customer needs, and the need to seek rate recovery
of the plant investment and decommissioning costs. Specifically, Prairie
Island Unit 2 would be shutdown in May 1995 and Prairie Island Unit 1 would
be shutdown in February 1996 without significant modification of normal plant
operations. If operations at Prairie Island cease, the Company estimates
that the present value of the cost of supplying replacement power and
recovering its investment in the plant and unrecognized decommissioning costs
will be at least $1.8 billion. The Company would request recovery of these
costs, including a return on its investment, through utility rates. However,
at this time the amount of such costs and the regulators' ultimate response
to such a request is unknown. (See Note 15 of Notes to Financial Statements
under Item 8 regarding the possible effects on operating results of the
potential shutdown of the Company's Prairie Island nuclear power generating
facility.)
The Company and NRG made contractual commitments to convert municipal
solid waste to boiler fuel and burn the fuel to generate electricity. NRG
operates resource recovery plants that produce RDF from the waste. The RDF
is burned at the Company's Red Wing and Wilmarth plants in the Company's
service area, the French Island plant in the Wisconsin Company's service
area, and the Elk River plant owned by United Power Association. Processing
and burning RDF provides an additional economical source of electric capacity
and energy, which is beneficial to NSP's electric customers. The Company's
commitment to this program enables counties to meet state-mandated goals to
reduce the amount of solid waste now going to landfills. In addition, the
program provides for increased materials recovery and increased use of
municipal solid waste as an energy source.
NSP has met or exceeded the removal and disposal requirements for
polychlorinated biphenyl (PCB) equipment as required by state and federal
regulations. NSP has removed all known PCB capacitors from its distribution
system. NSP also has removed 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 beneficially 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 July 1986, the Minnesota Pollution Control Agency (MPCA) board
voted to accept an Administrative Law Judge's recommendation regarding an
acid deposition control plan. The control plan set a sulfur dioxide
emissions cap of 1.3 times the Company's 1984 system-wide emissions,
commencing in 1990. The plan also required a sulfur dioxide emission rate
based upon Reasonably Available Control Technology (RACT) to be determined
for the Allen S. King Plant. In 1989, the Company reached agreement with the
MPCA on an interim emissions rate of 1.9 lbs/MBTU. This interim rate was
lowered to 1.8 lbs/MBTU in May 1993. In September 1993 a hearing before an
Administrative Law Judge (ALJ) took place to set a final RACT limit. In
December 1993 the ALJ recommended a final RACT limit of 1.6 lbs/MBTU. A
final decision from the MPCA was reached in February 1994 adopting the ALJ
recommendation. The limit of 1.6 lbs/MBTU may require the Allen S. King
Plant to modify its current fuel blend and to conduct more frequent boiler
cleanings.
The U.S. Environmental Protection Agency (EPA) in 1991 issued waste
combustor air quality regulations. As of Feb. 11, 1996, the regulations
impose new restrictions on currently permitted emissions. The MPCA expects
to issue statewide waste combustor rules in 1994 that would be more
restrictive than the new federal requirements beginning in 1997. To meet the
new federal and state requirements, 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. Equipment may cost between
$6 million and $10 million. Further regulations that could affect pollution
control equipment are expected to be approved by the EPA in 1995.
The Clean Air Act, including the Amendments of 1990, (the "Clean Air
Act") impose stringent limits on emissions of sulfur dioxide and nitrogen
oxides by electric utility generating plants. The legislation enacted in
1990 is extremely complex and its overall financial impact on NSP will depend
on the final interpretation and implementation of rules to be issued by the
EPA. NSP is participating in the rulemaking process for the development of
regulations that achieve the goals of the legislation in a reasonable and
cost-effective manner. NSP has expended significant funds over the years to
reduce sulfur dioxide emissions at its plants. Additional construction
expenditures may be required to comply with parts of the Clean Air Act.
Based on revised emission standards proposed by the EPA in 1993, NSP's excess
emission allowances available under the Clean Air Act may be significantly
reduced. Because the Company is only beginning to implement some provisions
of the Clean Air Act, its overall financial impact is unknown at this time.
The majority of the Company's power plants meet state and federal limits for
opacity and air quality. Capital expenditures will be required for opacity
compliance in 1994-1998 at certain facilities as discussed below.
As a part of its Clean Air Act compliance effort, the Company will
test a type of air quality control device called a wet electrostatic
precipitator at the Sherburne County Generating Plant (Sherco). The
equipment will be installed in 1994 inside one of the existing acid gas
scrubber modules. Testing, anticipated to be completed by the end of 1995,
will determine the equipment's operational requirements and ability to reduce
particulate emissions and opacity. The equipment is being examined as one
option to lower opacity from Sherco units 1 and 2, as required by the EPA.
Until testing is completed, it is unknown whether the equipment will result
in full compliance with air quality standards. Total costs for equipment to
reduce particulate emissions and opacity range from $90 million for the
equipment being tested to $300 million for other technology options.
The Company has completed testing for air toxics at its major
facilities and shared these results with state and federal agencies. The
Company also is engaged in research to reduce levels of mercury emissions.
The Clean Air Act requires the EPA to look at issuing rules for air toxics
for electric utilities. The MPCA is considering the development of air toxic
rules in 1994. There also is interest in the Minnesota Legislature to pass
a bill further restricting the emissions of mercury in the state. The
Company cannot predict at this time what additional actions, if any, it may
need to take if any such rules are passed.
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. Estimates of present cost of implementation of overall water
quality monitoring does not have a material impact on NSP's operating
results.
The pending reauthorization of the Federal Clean Water Act will
probably result in more stringent water quality rules, regulations and
standards that will result in slightly greater operating costs for NSP
facilities.
Site Remediation
The Company has been designated by the EPA as a "potentially
responsible party" (PRP) for eight waste disposal sites to which the Company
sent materials. Under applicable law, the Company, along with each PRP,
could be held jointly and severally liable for the total site remediation
costs. Those costs have been estimated at $85 million for all eight PRP
sites. However the amount could be in excess of $85 million.
Settlement with the EPA and other PRPs has been reached for two of
these disposal sites for reimbursement of the federal government's past
costs of remedial action. One of the sites, South Andover Salvage Yards,
in Andover, Minnesota, is contaminated by several chemicals, including PCBs.
The contamination was attributed to past disposal by the Company and 13 other
PRPs. The Company's total allocation for both sites was approximately $1.4
million, which has already been paid. Of that amount, approximately $1.3
million was paid in 1993 related to the Andover site. By reaching early
settlement, the Company avoided litigation costs, increased costs of
investigation and remediation and possible penalties that could have resulted
and substantially increased the Company's allocation. The Company instituted
legal action to recover costs from non-participating PRPs at the South Andover
site and recovered a portion of its costs. The Company has reached tentative
settlement with the EPA, state agencies and other parties at a third site.
The Company's allocation for remediation of this site is estimated to be
approximately $150,000. For the remaining five sites, neither the amount of
cleanup costs nor the final method of their allocation among all designated
PRP's has been determined. However, the current estimate of the Company's
share of future remediation costs for all five sites is approximately $0.9
million.
Until final settlement, neither the amount of cleanup costs nor the
final method of their allocation among all designated PRPs can be determined.
While it is not feasible to determine the precise outcome of these matters,
amounts accrued represent the best current estimate of the Company's future
liability for the cleanup costs of these sites. It is the Company's practice
to vigorously pursue and, if necessary, litigate with insurers to recover
costs. Through litigation, the Company has recovered from other PRPs a
portion of the remedial costs paid to date. Management also believes that
costs incurred in connection with the sites, which are not recovered from
insurance carriers or other parties, may be recoverable in future ratemaking.
The Wisconsin Company has been notified by a group of PRPs of possible
responsibility for cleanup of a solid and hazardous waste landfill site. The
Wisconsin Company contends that it did not dispose of hazardous wastes in the
subject landfill during the time period in question. Because neither the
amount of cleanup costs nor the final method of their allocation among all
designated PRPs has been determined, it is not feasible to determine the
outcome of this matter at this time.
The Company is continuing to investigate 14 properties either
presently or previously owned by the Company that were, at one time, sites
of gas manufacturing or storage plants, or coal gas pipelines. The purpose
of this investigation is to determine if waste materials are present, if such
materials constitute an environmental or health risk, if the Company has any
responsibility for remedial action and if recovery under the Company's
insurance policies can contribute to any remediation costs. The total cost
of remediation of these sites is expected to range from $10 million to
approximately $16 million, including $3.1 million which has been paid to
date. The Company has commenced remediation efforts at five of the 14 sites.
One of the active sites has been completed, while the remaining four are in
various stages of remediation. Monitoring continues at the completed site.
No agreement or consent order has been negotiated to perform any extensive
site investigations or clean-up at the other nine sites. The Company
currently estimates its liability for the 14 sites to be approximately $7
million. Based upon information currently available with regard to these
sites, management believes that accruals recorded represent the best current
estimate of the costs of any required clean-up or remedial actions for former
gas operating sites of the Company. Management believes costs incurred in
connection with the sites that are not recovered from insurance carriers or
other parties may be allowable costs for future ratemaking purposes. The
Company has requested approval of deferred accounting of investigation and
remediation expenses. The request is pending MPUC approval.
NSP has not developed any specific site restoration and exit plans for
its fossil fuel plants, hydroelectric plants or substation sites as it
currently intends to operate at these sites indefinitely. If such plans were
developed in the future, NSP would intend to treat the costs as a removal
cost of retirement and include it in depreciation expense. Removal costs are
estimated based on historical experience and a amount is currently included in
depreciation expense.
Contingencies
In October 1992, the Company disclosed to the Minnesota Pollution
Control Agency (MPCA), the EPA and the NRC that its reports on halogen
content of water discharged at the Company's Prairie Island nuclear
generating plant were based on estimates of halogen content rather than
actual physical samples of water discharged as required by the plant's
permit. Even though the water discharges at the plant did not exceed the
halogen levels allowed under the permit, the applicable state and federal
statutes would permit the imposition of fines, the institution of criminal
sanctions, and/or injunctive relief for the reporting violations. Corrective
actions were taken by the Company, and the Company cooperated with state and
federal authorities in the investigation of the reporting violations. In
November 1993, the United States Attorney's Office announced that three
chemistry technicians responsible for reporting halogen content in discharge
water would be charged with misdemeanor violations of the Federal Clean Water
Act. No civil or criminal actions against the Company have been announced.
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 electric and magnetic fields
and some forms of cancer. The nation's electric utilities, including NSP,
have participated in the sponsorship of more than $50 million in research to
determine the possible health effects of electric and magnetic fields.
Through its participation with the Electric Power Research Institute, NSP
will continue its investigation and research with regard to possible health
effects posed by exposure to EMF. No litigation has been commenced or claims
asserted against NSP for adverse health effects related to EMF. However,
several immaterial claims have been asserted against NSP for diminution of
property values due to EMF. No litigation has commenced or is expected from
these claims.
Both regulatory requirements and environmental technology change
rapidly. Accordingly, NSP cannot presently estimate the extent to which it
may be required by law, in the future, to make additional capital
expenditures or to incur additional operating expenses for environmental
purposes. NSP also cannot predict whether future environmental regulations
might result in significant reductions in generating capacity or efficiency
or otherwise affect NSP's income, operations or facilities.
CAPITAL SPENDING AND FINANCING
NSP's capital spending program is designed to assure that there will
be adequate generating and distribution capacity to meet the future electric
and gas needs of its utility service area, and to fund investments in non-
regulated businesses. NSP continually reassesses needs and, when necessary,
appropriate changes are made in the capital expenditure program.
Total NSP capital expenditures (including allowance for funds used
during construction and excluding business acquisitions) totaled $362 million
in 1993, compared to $428 million and $350 million expended in 1992 and 1991,
respectively. These capital expenditures include gross additions to utility
property of $357 million (excluding Viking property acquired), $419 million
and $339 million for the three years ended 1993, 1992 and 1991 respectively.
Internally generated funds provided approximately 99% of the capital
expenditures for 1993, 49% for 1992 and 58% for 1991. In addition to capital
expenditures, NSP invested $159 million in 1993 to acquire three energy-
related businesses. (See Note 4 of Notes to Financial Statements under Item
8.)
NSP's utility capital expenditures (including allowance for funds used
during construction) are estimated to be $396 million for 1994 and $1.8
billion for the five years ended Dec. 31, 1998. Included in NSP's projected
utility capital expenditures is $55 million in 1994 and $282 million during
the five years ended Dec. 31, 1998, for nuclear fuel for NSP's three existing
nuclear units. The remaining capital expenditures through 1998 are for many
utility projects, none of which are extraordinarily large relative to the
total capital expenditure program. Approximately 80% of the 1994 utility
capital expenditures and approximately 95% of the 1994-1998 utility capital
expenditures are expected to be provided by internally generated funds. The
foregoing estimates of utility capital expenditures and internally generated
funds may be subject to substantial changes due to unforeseen factors, such
as changed economic conditions, competitive conditions, resource planning,
new government regulations, changed tax laws and rate regulation. Further,
the estimates assume the continued operation of the Company's Prairie Island
generating facility. (See Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations and "Environmental Matters"
herein.)
Although they may vary depending on the success, timing, and level of
involvement in projects currently under consideration, potential capital
requirements for NSP's non-regulated projects are estimated to be $130
million in 1994 and $540 million for the five-year period 1994-1998. The
majority of these non-regulated capital requirements relate to equity
investments (excluding project debt) in NRG's international projects,
as discussed previously. The remainder consists mainly of affordable housing
investments by Eloigne Company, most of which are expected to be financed
through project debt. Equity investments by NRG and Eloigne would be funded
through their own internally generated funds or through equity investments by
NSP. Such equity investments by NSP are expected to be financed on a long-term
basis through NSP's internally generated funds or through NSP's issuance of
common stock and debt.
NSP continues to evaluate opportunities to enhance shareholder returns
through business acquisitions. Long-term financing may be required for
acquisitions that NSP consummates.
EMPLOYEES AND EMPLOYEE BENEFITS
The total number of full- and part-time employees of NSP is
approximately 7,880. About 3,150 employees of NSP are represented by five
local IBEW labor unions. The labor contracts with the unions expired on Dec.
31, 1993. On March 14, 1994, a three-year contract offer was rejected and
an authorization to strike was approved by the IBEW membership by nearly a
2-to-1 margin. Representatives from the union and NSP resumed discussions
on March 21, 1994. An interim agreement between NSP and the unions is in
place with an expiration date of March 31, 1994. Negotiations are continuing
and NSP is unable to predict the outcome of negotiations at this time.
In 1993, NSP reviewed employee and retiree benefits and implemented
the following changes that are effective for 1994. These changes will
support NSP's goal of providing market-based benefits and are expected to
keep employee compensation and benefit costs close to 1993 levels.
Active nonbargaining medical premium increases: A two-year cost
sharing strategy for medical benefits for nonbargaining employees was
implemented in 1994. The strategy consisted of employees contributing 10%
in 1994 and 20% in 1995 of the total medical cost.
Retiree medical premium increases: Retiree medical premiums were
increased in 1994 for existing and future retirees. For existing qualifying
retirees, pension benefits have been increased to offset some of the premium
increase. For future retirees, a six-year cost-sharing strategy was
outlined.
Nonbargaining pension plan lump sum option changes: Currently,
nonbargaining employees have the option to receive their pension in either
a lump sum or in monthly installments. Beginning in 1994, nonbargaining
employees will be able to choose a lump sum distribution in 25% increments
upon termination of employment. Employees taking less than 100 percent will
receive the rest of their benefits in monthly installments.
Nonbargaining 401(k) changes: NSP currently offers eligible employees
a 401(k) Retirement Savings Plan. NSP will match up to $500 of nonbargaining
employees pre-tax 401(k) contributions.
Nonbargaining wage increases: No base wage scale increases were
implemented in January 1994. Effective in 1994, NSP implemented a market-
based pay structure for nonbargaining employees. NSP's new pay system uses
the latest salary surveys that indicate how local and regional companies pay
their employees for comparable positions.
<TABLE>
OPERATING STATISTICS
<CAPTION>
1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
Electric Operating Revenues (millions)
Residential
With space heating $ 68.2 $ 63.4 $ 67.9 $ 62.8 $ 65.3
Without space heating 583.4 534.7 568.7 522.6 507.4
Small commercial and industrial 327.9 312.6 315.9 299.4 287.0
Large commercial and industrial 780.4 718.7 713.2 671.6 634.2
Street lighting and other 29.2 29.7 30.7 29.5 30.9
Total retail 1 789.1 1 659.1 1 696.4 1 585.9 1 524.8
Sales for resale 159.5 138.0 145.0 138.0 116.1
Miscellaneous 26.3 26.2 21.8 25.2 13.6
Total $ 1 974.9 $1 823.3 $ 1 863.2 $ 1 749.1 $ 1 654.5
Kilowatt-hour Sales (billions)
Residential
With space heating 1.1 1.1 1.1 1.1 1.2
Without space heating 8.0 7.6 8.2 7.8 7.7
Small commercial and industrial 5.3 5.2 5.3 5.2 5.0
Large commercial and industrial 17.1 16.4 16.3 15.8 15.3
Street lighting and other .4 .4 .4 .4 .4
Total retail 31.9 30.7 31.3 30.3 29.6
Sales for resale 8.0 6.5 6.1 6.3 5.1
Total 39.9 37.2 37.4 36.6 34.7
Gas Operating Revenues (millions)
Residential
With space heating $ 220.8 $ 178.2 $ 179.2 $ 164.0 $ 170.7
Without space heating 2.7 2.5 2.6 2.7 2.9
Commercial and industrial firm 131.5 105.8 105.7 97.0 99.4
Total firm 355.0 286.5 287.5 263.7 273.0
Commercial and industrial interruptible 52.2 41.6 40.8 43.8 45.7
Miscellaneous 3.4 2.0 3.1 3.2 2.7
Total gas sales 410.6 330.1 331.4 310.7 321.4
Interstate transmission (Viking) 9.0 0 0 0 0
Agency and transportation deliveries 9.5 6.1 6.5 4.7 3.3
Total gas sold and delivered $ 429.1 $ 336.2 $ 337.9 $ 315.4 $ 324.7
Mcf Sales (millions)
Residential
With space heating 40.9 35.2 37.5 33.4 36.0
Without space heating .3 .3 .4 .4 .4
Commercial and industrial firm 28.6 24.3 25.4 22.8 24.1
Total firm 69.8 59.8 63.3 56.6 60.5
Commercial and industrial interruptible 18.6 15.8 15.8 16.7 16.7
Miscellaneous .2 .1 .3 .6 .4
Total gas sales 88.6 75.7 79.4 73.9 77.6
Other gas delivered (millions of Mcf)
Interstate transmission (Viking) 75.2 0 0 0 0
Agency and transportation deliveries 8.1 7.3 7.5 6.3 5.6
Total gas sold and transported 171.9 83.0 86.9 80.2 83.2
</TABLE>
EXECUTIVE OFFICERS *
Present Positions and Business Experience
Name Age During the Past Five Years
James J Howard 58 Chairman of the Board and Chief Executive
Officer since 7/01/90; and prior thereto
Chairman of the Board, President and Chief
Executive Officer.
Edwin M Theisen 63 President and Chief Operating Officer since
7/01/90; and prior thereto President and Chief
Executive Officer of Northern States Power
Company (a Wisconsin corporation), a wholly
owned subsidiary of the Company.
Leon R Eliason 54 President - NSP Generation since 1/01/93; Vice
President - Nuclear Generation from 7/01/90 to
12/31/92; and prior thereto General Manager -
Nuclear Plants.
Keith H Wietecki 44 President - NSP Gas since 1/11/93; Vice
President - Corporate Strategy from 1/01/93
to 1/10/93; Vice President - Electric
Marketing & Sales from 4/25/90 to 12/31/92;
and prior thereto Vice President - Electric
Marketing and Customer Service.
Douglas D Antony 51 Vice President - Nuclear Generation since
1/01/93; General Manager - Monticello Nuclear
Site from 9/01/90 to 12/31/92; Plant Manager -
Monticello from 8/15/89 to 8/31/90; and prior
thereto General Superintendent - Training
Center.
Vincent E Beacom 64 Vice President - Minnesota Electric since
1/01/93; Senior Vice President - Gas
Operations from 7/01/90 to 12/31/92; and
prior thereto Vice President - Commercial
and Division Operations Northern States
Power Company (a Wisconsin corporation), a
wholly owned subsidiary Company.
Arland D Brusven 61 Vice President - Finance and Treasurer since
1/01/93; Vice President and Treasurer from
9/01/90 to 12/31/92; and prior thereto
Secretary and Financial Counsel.
Jackie A Currier 42 Vice President - Corporate Strategy since
1/11/93; Director - Corporate Finance and
Assistant Treasurer from 9/17/92 to 1/10/93;
Director - Corporate Finance from 6/01/90 to
9/16/92; General Manager - Budget & Control
from 4/01/89 to 5/31/90; and prior thereto
Manager - Departmental & Capital Budgets.
Gary R Johnson 47 Vice President & General Counsel since
11/01/91; and prior thereto Vice President
- Law.
Cynthia L Lesher 45 Vice President - Human Resources since
3/01/92; Director - Power Supply Human
Resources from 8/15/91 to 2/29/92; Manager
- White Bear Lake Area from 5/21/90 to
8/14/91; Manager - Metro Credit from
1/15/89 to 5/20/90; and prior thereto
Manager - Occupational Health/Safety.
Edward J McIntyre 43 Vice President and Chief Financial Officer
since 1/01/93; President and Chief
Executive Officer of Northern States Power
Company (a Wisconsin corporation), a
wholly owned subsidiary of the Company
from 7/01/90 to 12/31/92; an prior thereto
Vice President - Gas Utility.
Roger D Sandeen 48 Vice President, Controller and Chief
Information Officer since 4/22/92; Vice
President and Controller from 7/01/89 to
4/21/92; and prior thereto Vice President
and Treasurer of KVI Associates, Inc.
(a real estate development company
managing assets in excess of $150
million).
Robert H Schulte 41 Vice President - Customer Service since
1/01/93; Vice President - Rates and
Corporate Strategy from 7/01/90 to
12/31/92; and prior thereto
General Manager - South Dakota Region.
Loren L Taylor 47 Vice President - Customer Operations since
1/01/93; Vice President - Transmission and
Inter-Utility Services from 11/01/89 to
12/31/92; and prior thereto Vice President
- Human Resources.
*As of 3/01/94
Item 2 - Properties
The Company's major electric generating facilities consist of the
following:
Projected
Summer Net
Capability
Station and Unit Fuel Installed (MW)
Sherburne
Unit 1 Coal 1976 712
Unit 2 Coal 1977 712
Unit 3 Coal 1987 514
Prairie Island
Unit 1 Nuclear 1973 513
Unit 2 Nuclear 1974 512
Monticello Nuclear 1971 539
King Coal 1968 567
Black Dog
4 Units Coal 1952-1960 463
High Bridge
2 Units Coal 1956-1959 262
Riverside
2 Units Coal 1964-1987 366
All of NSP's major generating stations are located in Minnesota on
land owned by the Company. At December 31, 1993, NSP's electric transmission
and distribution system consisted of 6,534 miles of overhead transmission
lines, 28,100 miles of overhead distribution pole lines, 396 miles of
underground conduit and 13,872 miles of underground cable.
The gas properties of NSP include about 6,785 miles of natural gas
distribution mains. Viking owns a 500-mile gas pipeline.
Manitoba Hydro, Minnesota Power Company and the Company completed
the construction of a 500-Kv transmission interconnection Winnipeg, Manitoba,
Canada, and the Minneapolis-St Paul, Minnesota, area in May 1980. NSP has a
contract with Manitoba Hydro-Electric Board for 500 Mw of firm power
utilizing this transmission line. (See Note 15 of Notes to Financial
Statements under Item 8.) In addition, the Company is interconnected with
Manitoba Hydro through a 230 Kv transmission line completed in 1970.
Virtually all of the utility plant of the Company and the Wisconsin
Company are subject to the lien of their first mortgage bond indentures
pursuant to which they have issued first mortgage bonds.
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have
arisen against NSP. Management, after consultation with legal counsel, has
recorded an estimate of the probable cost of settlement or other disposition
for such matters.
On July 22, 1993, a natural gas explosion occurred on the Company's
distribution system in St. Paul, Minn. Total damages are estimated to exceed
$1 million. The Company has a self-insured retention deductible of $1
million, with general liability coverage of $150 million, which includes
coverage for all injuries and damages. Four personal injury lawsuits have
been filed by individuals injured in the explosion with Ramsey County,
Minnesota District Court. The litigation is in a preliminary stage and the
ultimate costs to the Company are unknown at this time.
On July 14, 1993, the Company filed a lawsuit in US District Court for
the District of Minnesota. The suit was filed in the interest of the
Company's ratepayers against Westinghouse Electric Corp. (Westinghouse), the
manufacturer of the Prairie Island steam generators, because of problems with
the steam generators susceptibility to corrosion. The Company seeks to
recover the past and future costs of inspections, maintenance, modifications
and repairs made to the Prairie Island steam generators and related systems
as a result of Westinghouse defects. The defects are "serious" in that they
have caused the Company to incur significant expenditures in order to ensure
that Prairie Island is a safe and economically efficient generating station.
The scheduling order requires discovery to be completed by Oct. 1, 1995. NSP
and Westinghouse must be ready for trial by Feb. 1, 1996. Safety has not
been, nor will be compromised in any way as a result of the defects because the
plant has been and continues to be well-maintained. The steam generator
problem is less severe at Prairie Island than at most other plants with the
same model steam generator. This is due to specific plant design features,
including a lower reactor coolant water temperature than most of the other
plants. Other reasons are due to the higher standards used at Prairie Island
in such areas as water chemistry and preventative maintenance. Based on
analysis done, it is the Company's best estimate that the steam generators
can be maintained so replacement will not be necessary before the units' 40-
year operating licenses expire.
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 "Regulation and Revenues"
under Item 1, incorporated herein by reference.
Item 4 - Submission of Matters to a Vote of Security Holders
None
PART II
Item 5 - Market for Registrant's Common Equity and
Related Stockholder Matters
Quarterly Stock Data
The Company's common stock is listed on the New York Stock Exchange
(NYSE), Chicago Stock Exchange (CHX) and the Pacific Stock Exchange (PSE).
Following are the reported high and low sales prices based on the NYSE
Composite Transactions for the quarters of 1993 and 1992 and the dividends
declared per share during those quarters:
1993 1992
High Low Dividends High Low Dividends
First Quarter $47 $42 1/4 $.630 $43 $39 1/4 $.605
Second Quarter 46 7/8 42 7/8 .645 42 38 1/2 .630
Third Quarter 47 7/8 44 3/4 .645 45 5/8 41 .630
Fourth Quarter 46 3/8 40 1/8 .645 45 3/8 41 5/8 .630
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 December 31, 1993, the payment of cash
dividends on common stock was not restricted.
1993 1992 1991 1990 1989
Shareholders at
year-end 86 404 72 525 72 704 73 867 75 396
Book value per share
at year-end $27.32 $25.91 $25.21 $24.42 $23.76
Shareholders as of March 18, 1994 were 86,775.
<TABLE>
Item 6 - Selected Financial Data
<CAPTION>
1993 1992 1991 1990 1989 1983
(Dollars in millions except per share data)
<S> <C> <C> <C> <C> <C> <C>
Utility operating revenues $2 404.0 $2 159.5 $2 201.1 $2 064.5 $1 979.2 $1 685.1
Utility operating expenses $2 100.1 $1 903.5 $1 895.6 $1 775.7 $1 675.3 $1 435.3
Income from continuing operations
before accounting change $211.7 $160.9 $207.0 $193.0 $219.2 $181.4
Net income $211.7 $206.4 $224.1 $195.5 $221.9 $183.9
Earnings available for common stock $197.2 $190.3 $206.1 $177.3 $202.6 $170.3
Average number of common and
equivalent shares outstanding (000's) 65 211 62 641 62 566 62 541 62 541 60 863
Earnings per average common share:
Continuing operations
before accounting change $3.02 $2.31 $3.02 $2.79 $3.20 $2.76
Total $3.02 $3.04 $3.29 $2.83 $3.24 $2.80
Dividends declared per share $2.565 $2.495 $2.395 $2.295 $2.195 $1.453
Total assets $5 587.7 $5 142.5 $4 918.8 $4 931.6 $4 832.5 $3 395.4
Long-term debt $1 291.9 $1 299.9 $1 233.9 $1 239.5 $1 262.7 $1 086.2
Ratio of earnings (from continuing
operations before accounting change,
including AFC) to fixed charges 4.0 3.2 3.9 3.7 4.1 4.9
Notes:
1) Operating revenues and operating expenses in all years prior to 1992 have
been restated to exclude the results of discontinued telephone operations.
2) In 1992, the Company changed its method of accounting for revenue
recognition. (See Note 3 of Notes to Financial Statements under Item 8.)
</TABLE>
Item 7 Management's Discussion and Analysis of Financial Condition and
Results of Operations
Northern States Power Company, a Minnesota corporation (the Company), has one
significant subsidiary, Northern States Power Company, a Wisconsin
corporation (the Wisconsin Company), and several other subsidiaries,
including Viking Gas Transmission Company (Viking) and NRG Energy, Inc.
(NRG), both Delaware corporations. The Company and its subsidiaries
collectively are referred to herein as NSP.
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 1993 and 1992 and should be read in connection with the
Financial Statements and Notes thereto. Trends and contingencies of a
material nature are discussed to the extent known and considered relevant.
Liquidity and Capital Resources
Financial Condition and Cash Flows - With rate increases granted in 1993,
NSP's financial condition remained strong and its cash flows and earnings
from operations improved from 1992, despite cooler-than-average summer
weather. NSP's 1992 cash flows and earnings before accounting changes were
significantly reduced by unusual weather, including the coolest summer in 77
years. The 1992 earnings included $45.5 million from a change in accounting
for unbilled revenues, which did not affect cash flows or customer rates.
During 1993, NSP continued to meet its long-range objectives for capital
structure of approximately 45-50 percent common equity and 40-45 percent
debt. The pretax interest coverage ratio before accounting changes, excluding
AFC, was 3.9 in 1993 and 3.1 in 1992. NSP's objective range for interest
coverage is 3.5-5.0.
Financing Requirements - NSP's need for capital funds is primarily related to
the construction of plant and equipment to meet the needs of its electric and
gas utility customers and to fund equity commitments or other investments in
its non-regulated businesses. Total NSP capital expenditures (including AFC
and excluding business acquisitions) were $362 million in 1993. Of that
amount, $284 million related to replacements and improvements of NSP's
electric system and $36 million involved construction of natural gas
distribution facilities. Internally generated funds provided 99 percent of
NSP's capital expenditures for 1993 and 85 percent of the $1.8 billion in
capital expenditures incurred for the five-year period 1989-1993. NSP
estimates that its utility capital expenditures will be $396 million in 1994.
Of that amount, $316 million is scheduled for electric facilities and $43
million for natural gas facilities. Internally generated funds from utility
operations are expected to provide approximately 80 percent of 1994 utility
capital expenditures and approximately 95 percent of the $1.8 billion in
utility capital expenditures estimated for the five-year period 1994-1998.
These utility capital expenditure estimates include approximately $100
million of anticipated expenditures for pollution control facilities required
under the Clean Air Act. In addition to utility capital expenditures,
expected financing requirements for the 1994-1998 period include
approximately $390 million to retire long-term debt and meet first mortgage
bond sinking fund requirements.
NSP expects to obtain external capital for these requirements by
issuing long-term debt, common stock and preferred stock. Utility financing
requirements for the period 1994-1998 may be affected by factors such as load
growth, changes in capital expenditure levels, rate increases allowed by
regulatory agencies, new legislation, changes in environmental regulations
and other regulatory requirements.
NSP expects to invest significant amounts in non-regulated projects,
including domestic and international power projects. Projects currently
being pursued include joint ventures to acquire electric generating plants
in Australia and Germany, and open-cast coal mining operations in Germany.
Non-regulated projects are expected to be financed primarily through project
debt. The remaining project costs are expected to be funded through equity
investments from NSP and other investors. Over the long-term, NSP's equity
investments are expected to be financed through internally generated funds
or NSP's issuance of common stock and debt. Although they may vary depending
on the success, timing and level of involvement in projects currently under
consideration, potential capital requirements for NSP's non-regulated
projects are estimated to be approximately $130 million in 1994 and
approximately $540 million for the five-year period 1994-1998. These amounts
include expected equity investments by NSP of approximately $60 million for
the Australia project in 1994 and up to $100 million for the Germany projects
through 1996.
In addition to capital expenditures, NSP invested $159 million in 1993
to acquire three energy-related businesses. (See Note 4 to the Financial
Statements.) NSP continues to evaluate opportunities to enhance shareholder
returns through business acquisitions. Long-term financing may be required
for such acquisitions.
Financing Flexibility - 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 earn a fair return on investors' capital. Financing
flexibility is enhanced by providing working capital needs and a high
percentage of total capital requirements from internal sources, and having
the ability, if necessary, to issue long-term securities and obtain
short-term credit. Access to securities markets at a reasonable cost is
determined in a large part by credit quality. The Company's first mortgage
bonds are rated AA- by Standard & Poor's Corporation, Aa2 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 only 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 place limits on the amount of first mortgage bonds that
may be issued. The Minnesota Public Utilities Commission (MPUC) and the
Public Service Commission of Wisconsin (PSCW) have jurisdiction over
securities issuance. At Dec. 31, 1993, with an assumed interest rate of 8
percent, the Company could have issued about $1.8 billion of additional first
mortgage bonds under its indenture and the Wisconsin Company could have
issued about $280 million of additional first mortgage bonds under its
indenture. NSP expects to maintain adequate access to long-term and short-term
debt markets in 1994.
The Company registered $600 million of first mortgage bonds with the
Securities and Exchange Commission (SEC) in December 1993. Depending on
capital market conditions, the Company expects to issue approximately $450
million of this debt in 1994, primarily for refinancings, with the remainder
issued over the next several years, for the purpose of raising additional
capital or redeeming 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 $350 million in short-term borrowing levels. The
Company had approximately $106 million in commercial paper debt outstanding
as of Dec. 31, 1993. The Company plans to keep its credit lines at or above
the level of commercial paper borrowings. Commercial banks presently provide
credit lines of approximately $215 million. These credit lines make
short-term financing available in the form of bank loans.
The Company's Articles of Incorporation authorize the maximum amount
of preferred stock that may be issued. Under these provisions, the Company
could have issued all $460 million of its remaining authorized, but unissued
preferred stock at Dec. 31, 1993, and remained in compliance with all
interest and dividend coverage requirements.
The level of common stock authorized, under the Company's Articles of
Incorporation, is 160 million shares. Registration Statements filed with the
SEC provide for the sale of up to 1,650,000 shares of common stock under the
Company's Dividend Reinvestment and Stock Purchase Plan, Executive Long-Term
Incentive Award Stock Plan, and Employee Stock Ownership Plan (ESOP) as of
Dec. 31, 1993. The Company may issue new shares or purchase shares on the
open market for its stock plans. (See Note 6 to the Financial Statements for
discussion of stock awards outstanding.) As discussed below, the Company
issued new common stock in 1993 under a general stock offering and under its
shareholder, employee and customer stock programs. At Dec. 31, 1993, the
total number of common shares outstanding was 66,879,577. The Company does
not plan any general stock offerings for 1994.
1993 Financing Activity - During 1993, NSP engaged in numerous financing
activities. The Company issued 4,281,217 shares of common stock. Of these
shares, 2.6 million were sold to a group of underwriters on May 20, 1993. The
offering price to the public was $43.625 per share, with net proceeds of $110
million to the Company. Of the remaining new shares, 940,000 shares were
issued under the Dividend Reinvestment and Stock Purchase Plan, 174,308
shares were issued under the Executive Long-Term Incentive Award Stock Plan
and 566,909 shares were issued to the ESOP.
On Oct. 30, 1993, the Company redeemed all 350,000 shares of its $7.84
series Cumulative Preferred Stock at $103.12 per share, plus accrued
dividends through Oct. 31, 1993.
During 1993, the Company issued $350 million, and the Wisconsin Company
issued $150 million, of long-term debt to refinance higher rate debt, redeem
preferred stock, repay scheduled maturities of debt and extend the term of
short-term borrowings. In addition, $116 million of long-term debt was issued
by subsidiaries to finance the acquisitions of Viking and the Minneapolis
Energy Center. (See Note 4 to the Financial Statements.) In connection with
the early redemption of $453 million of long-term debt, NSP incurred
approximately $14 million in reacquisition premiums, which will be amortized
over the term of the newly issued debt.
Results of Operations
NSP's results of operations during 1993 and 1992 were primarily dependent on
the operations of the Company's and Wisconsin Company's utility businesses
consisting of the generation, transmission and sale of electricity and the
distribution, transportation and sale of natural gas. NSP's utility revenues
are dependent on customer usage which varies with weather conditions, general
business conditions, the state of the economy and the cost of energy
services, the recovery of which is determined by various regulatory
authorities. The historical and future trends of NSP's operating results have
been and are expected to be impacted by the following factors:
Weather - NSP's earnings can be dramatically impacted by unusual weather. Mild
weather, mainly a cool summer, reduced 1993 earnings by an estimated 18
cents. However, this was an improvement over 1992 when a warm winter and the
coolest summer in 77 years reduced earnings by an estimated 51 cents.
Operating Contingency - The Company is experiencing uncertainty regarding its
ability to store used nuclear fuel from its Prairie Island nuclear generating
facility. The facility stores its used nuclear fuel on an interim basis in
a storage pool in the plant, pending the availability of a U. S. Department
of Energy high-level radioactive waste storage or permanent disposal
facility, or a private interim storage facility. At current operating levels,
the pool will be filled in 1994 so the Company has proposed to augment
Prairie Island's interim storage capacity by using steel containers for dry
storage of used nuclear fuel on the plant site. Without additional onsite
storage or significant modification of normal plant operations, Prairie
Island Unit 2 would be shutdown in May 1995 and Prairie Island Unit 1 would
be shutdown in February 1996. These two units supply about 20 percent of the
Company's output. The Company has obtained a Certificate of Need from the
MPUC allowing use of a limited number of steel containers, providing adequate
storage at least through the year 2001. The Nuclear Regulatory Commission has
also issued a license approving a dry storage facility on the plant site for
Prairie Island's used fuel. However, in June 1993, the Minnesota Court of
Appeals decided that the additional temporary storage facilities must be
approved by the Minnesota Legislature. The Company has requested such
approval from the Legislature and expects a decision on this issue during the
current session, which began on Feb. 22, 1994. Although hearings have begun,
the Company cannot predict what action the Minnesota Legislature will take.
If operations at Prairie Island cease, the Company estimates that the present
value of the cost of supplying replacement power and recovering its
investment in the plant and unrecognized decommissioning costs will be $1.8
billion. The Company would request recovery of these costs, including a
return on its investment, through utility rates. However, at this time the
need for such costs and the regulators' ultimate response to such a request
is unknown. (See Note 15 to the Financial Statements regarding the possible
effects on operating results of the potential shutdown of the Company's
Prairie Island nuclear power generating facility.)
Regulation - NSP's utility rates are approved by the Federal Energy Regulatory
Commission (FERC) and state commissions. Rates are designed to recover plant
and operating costs and an allowed return, using an annual period upon which
rate case filings are based. NSP's utility companies request increases in
customers' rates as needed and file them with the governing commissions. The
rates charged to retail customers in Wisconsin are reviewed and adjusted
biennially. Because rate increases are not requested annually in Minnesota,
NSP's primary jurisdiction, the impact of inflation on operating costs
continues to be a factor affecting NSP's earnings, shareholders' equity and
other financial results. Except for Wisconsin electric operations, NSP's rate
schedules provide for cost-of-energy adjustments to billings and revenues for
changes in the cost of fuel for electric generation, purchased power and
purchased gas. For Wisconsin electric operations, the biennial retail rate
review process considers changes in electric fuel and purchased energy costs
in lieu of a cost-of-energy adjustment clause. In addition to changes in
operating costs, other factors affecting rate filings are sales growth,
conservation programs and demand-side management efforts.
Rate Increases - During 1992 and 1993, NSP filed for 1993 rate increases in
Minnesota, North Dakota, South Dakota and Wisconsin to offset increasing
costs for purchased power commitments, depreciation, property taxes,
postretirement benefits and other expenses. NSP received approvals for
approximately $102 million of annualized rate increases for retail customers
in those states as well as wholesale customers in Minnesota and Wisconsin.
These rate changes increased 1993 revenues by approximately $83 million; the
full impact of these increases will be realized in 1994. On Jan. 31, 1994,
three intervenors filed an appeal of the MPUC's decision concerning the
method of calculating the rate of return on common equity granted in the
Minnesota electric and gas rate cases. The amount at issue is approximately
$7 million in annual revenues for the Company. (See Note 2 to the Financial
Statements for further discussion of 1993 rate case results.)
In 1993, NSP filed for 1994 rate increases for North Dakota retail
electric and Wisconsin retail gas customers. NSP received approval for
approximately $2.6 million of rate increases in these two jurisdictions,
effective January 1994. No significant rate filings in other jurisdictions
are expected for 1994.
Acquisitions - NSP made three strategically important business acquisitions
in 1993. These include a gas pipeline, an energy services marketing business,
and a steam heating and chilled water cooling system business. (See Note 4
to the Financial Statements for more discussion of these acquisitions,
including the pro forma results of these acquisitions on an annual basis.)
Competition - The Energy Policy Act of 1992 (the Act) is expected to bring
comprehensive and significant changes to the electric utility industry. Many
provisions of the Act are expected to increase competition in the industry
in the next few years. The Act's reform of the Public Utility Holding Company
Act (PUHCA) promotes creation of wholesale power generators and authorizes
the FERC to require utilities to provide wholesale transmission services to
third parties. The legislation allows utilities and non-regulated companies
to build, own and operate power plants nationally and internationally without
being subject to restrictions that previously applied to utilities under the
PUHCA. Other producers may compete for NSP's customers as a result of such
PUHCA reform. Management believes this legislation will promote the continued
trend of increased competition in the electric energy markets.
Many states are considering proposals to require "retail wheeling",
which is the delivery of power generated by a third party to retail
customers. Retail wheeling represents yet another development of a
competitive electric industry. NSP management plans to continue its efforts
to be a low-cost supplier of electricity and an active participant in the
competitive market for electricity.
During 1992 and 1993, the FERC issued a series of orders (together
called Order 636) addressing interstate natural gas pipeline service
restructuring. This restructuring will "unbundle" each of the services -
sales, transportation, storage and ancillary services - traditionally
provided by the gas pipeline companies. Order 636 ended the traditional
pipeline sales service function, which in the past had met local distribution
companies' (LDCs) needs for reliability of supply and flexibility for meeting
varying load conditions. NSP believes some uncertainty remains as to whether
the new unbundled services under Order 636 will prove to be as reliable and
flexible as the traditional sales service. The implementation of Order 636
also will apply more pressure on all LDCs to keep gas supply and transmission
pricing for large customers competitive in light of the alternatives now
available to these customers. Interstate pipelines will be allowed to
recover, subject to negotiations with customers, 100 percent of prudently
incurred transition costs attributable to Order 636 restructuring. Although
negotiations are in process, NSP estimates that it will be responsible for
less than $10 million of transition costs, over a proposed five-year period.
NSP's regulatory commissions have previously approved recovery of similar
restructuring charges in retail gas rates. New service agreements went into
effect between NSP and its pipeline transporters on Nov. 1, 1993. NSP does
not expect these new agreements under Order 636 to materially affect its cost
of gas supply. NSP's acquisitions of Viking and a gas marketing business (as
discussed in Note 4 to the Financial Statements) have enhanced the ability
to participate in the more competitive gas transportation business. In
implementing Order 636, Viking incurred no restructuring costs.
Impact of Non-Regulated Investments - NSP expects to invest significant
amounts in non-regulated projects, including domestic and international power
production projects through NRG, as described previously under "Financing
Requirements". Depending on the success and timing of involvement in these
projects, NSP's non-regulated earnings are expected to increase materially
in the next few years. However, the projects generating the increased
earnings may present additional risk. Current and future investments in
international projects are subject to uncertainties prior to final legal
closing, and continuing operations are subject to foreign government and
partnership actions. NRG plans to hedge its exposure to currency fluctuations
to the extent permissible by hedge accounting requirements. NRG will use
well-established financial instruments of sufficient credit quality to
protect the economic value of foreign-currency denominated assets. (With
respect to risk of potential losses from unsuccessful non-regulated projects,
see Note 1 to the Financial Statements for discussion of capitalized
expenditures for projects under development.)
Employee Compensation and Benefits - In 1993, NSP conducted an extensive
review of its employee compensation and benefits, and retiree benefits. As
a result, several changes will be implemented, commencing in 1994, that will
support NSP's goal of providing market-based compensation and benefits. These
changes, which include no base wage increase for non-union employees in 1994,
are expected to keep compensation and benefit costs comparable to 1993
levels. NSP's labor agreements with its five local unions expired on Dec. 31,
1993. An interim agreement with the unions expires March 31, 1994. Although
NSP's final offer for settlement (made on Feb. 4, 1994) was rejected by the
union membership on March 14, 1994 and an authorization to strike was
approved, the parties resumed discussions on March 21, 1994. NSP is not able
to predict the outcome of negotiations at this time.
Environmental Matters - Like other utilities, the Company has been named as
a potentially responsible party at eight waste disposal sites and is in the
process of investigating the remediation of 14 former coal-gasification and
other sites. The Company has recorded an estimate of the probable costs to
be incurred in connection with remediation of these sites. To the extent
costs are not recovered from insurers or other parties, the Company expects
to seek recovery of such costs in future ratemaking proceedings.
In general, NSP has been experiencing a trend toward more environmental
monitoring and compliance costs. This trend has caused and may continue to
cause slightly higher operating expenses and capital expenditures. The timing
and amount of environmental costs, including those for site remediation, are
currently unknown. In 1993, 1992 and 1991, the Company spent about $15
million, $20 million and $6 million, respectively, for capital expenditures
on environmental improvements at utility facilities. The Company expects to
incur approximately $9 million in capital expenditures for compliance with
environmental regulations in 1994. (See Note 15 to the Financial Statements
for further discussion of these and other environmental contingencies that
could affect NSP.)
Wholesale Customers - In 1992, nine of the Company's 19 municipal wholesale
electric customers created a joint action municipal power agency to serve
their future power supply needs and notified the Company of their intent to
terminate their power supply agreements with the Company effective in July
1995 or July 1996. These nine customers currently represent approximately $24
million in annual revenues and a maximum demand load of approximately 150
megawatts.
In 1992 and 1993, the Company signed long-term power supply agreements
with the remaining 10 municipal customers. The agreements commit the
customers to purchase power from the Company for up to 13 years (through
2005) at fixed rates rising at up to 3 percent per year. The 10 customers
represent approximately $8 million in current annual revenue and a maximum
demand load of approximately 55 megawatts. The rates contained in the
agreements were accepted by the FERC on Feb. 23, 1994.
During October 1993, the Company signed an electric power agreement to
provide Michigan's Upper Peninsula Power Company (UPPCO) with up to 90
megawatts of baseload service, peaking service options and load regulation
service options for 20 years beginning in January 1998 through December 2017.
Load regulation service is designed to change the level of power delivery
during each hour to match UPPCO's load requirements. The rates, terms and
conditions of the agreement are subject to FERC approval. The Michigan Public
Utilities Commission must also approve the transaction. Beginning in 1998,
annual revenues of approximately $12 million-$16 million are expected to be
provided under the agreement, depending on contract options that UPPCO can
exercise.
Legislative Changes - The Omnibus Budget Reconciliation Act of 1993 (the Act)
was signed into law on Aug. 10, 1993. The only provision of the Act that had
a significant effect on NSP was the increase in the federal corporate income
tax rate from 34 percent to 35 percent retroactive to Jan. 1, 1993. The
effect of the higher tax rate was an increase of about $3.2 million in income
tax expense. Most of this cost increase was offset by higher revenues from
1993 rate increases approved in Minnesota. (See Note 2 to the Financial
Statements.) Deferred tax liabilities were increased for the rate change by
approximately $32 million. However, due to regulatory deferral of utility tax
adjustments, earnings were reduced only by immaterial adjustments to deferred
tax liabilities for non-regulated operations.
Wind-Generated Power - In October 1993, the Company signed a 25-year agreement
for the purchase of 25 megawatts of wind-generated electric capacity, and
associated energy to be produced in Minnesota. The wind generating plant is
expected to be fully operational by May 1994. This contract is the first
phase of the Company's plan to obtain 100 megawatts of wind-generated
electricity by 1997. The Company can recover the cost of energy purchases
through cost-of-energy adjustment clauses in electric rates.
Accounting Changes - As discussed in Note 13 to the Financial Statements, in
1993, NSP adopted Statement of Financial Accounting Standards (SFAS) No. 106
- - Employers' Accounting for Postretirement Benefits Other than Pensions and
began recording postretirement benefits on an accrual basis. NSP's utility
companies had previously been allowed rate recovery for postretirement
benefits as paid. In the 1993 rate increases discussed above, NSP's utility
companies obtained rate recovery for substantially all of the increased costs
(approximately $20 million) accrued under SFAS No. 106 in 1993. Due to rate
recovery of higher costs, there was no material impact on NSP's operating
results from this accounting change. Recent changes in interest rates have
resulted in different actuarial assumptions used in the benefit cost
calculations for postretirement benefits. Due to offsetting changes in other
actuarial assumptions and demographics, NSP's benefit costs for such plans
are not expected to increase from these changes in 1994. (See Note 13 to the
Financial Statements for more information on changes in actuarial
assumptions.)
NSP also adopted in 1993 SFAS No. 109 - Accounting for Income Taxes.
Because the provisions of SFAS No. 109 are not materially different than the
tax accounting procedures previously used by NSP, there was virtually no
impact on earnings or financial condition.
In 1992, the Company changed its accounting method for recognizing
revenue. Earnings in 1992 increased by 88 cents per share, including 73 cents
related to prior years, from recording estimated unbilled revenues for
utility service in Minnesota, North Dakota and South Dakota. (See Note 3 to
the Financial Statements for more information on the effects of this
accounting change.)
In 1994, NSP will be required to adopt SFAS No. 112 - Employers'
Accounting for Postemployment Benefits. This standard will require the
accrual of certain postemployment costs (such as injury compensation and
severance) that are payable in future periods. The impact of adopting SFAS
No. 112 is expected to be immaterial.
The Financial Accounting Standards Board (FASB) has announced
preliminary plans to change the accounting for stock compensation expense
effective in 1997 with disclosure requirements effective in 1994. Also, the
FASB has approved a proposed change in employers' accounting for employee
stock ownership plans effective in 1994. Based on NSP's review of these
future accounting changes, NSP does not expect a material impact on its
results of operations or financial condition.
NSP currently follows predominant industry practice in recording its
environmental liabilities for plant decommissioning and site exit costs as
a component of utility plant. The FERC and the SEC currently are evaluating
the financial presentation of these obligations, which could require a
reporting reclassification as early as 1994.
1993 Compared with 1992 and 1991
NSP's 1993 earnings per share were $3.02, up 71 cents from the $2.31 earned
before accounting changes in 1992 and equal to the $3.02 earned from
continuing operations in 1991. In addition to the revenue and expense changes
discussed below, 1993 earnings were impacted by a higher average number of
common and equivalent shares outstanding for earnings-per-share calculations
in 1993 due to the stock issuances discussed previously under "1993 Financing
Activity."
Electric Revenues and Production Expenses
Revenues - Sales to retail customers, which account for more than 90 percent
of NSP's electric revenue, increased 4.0 percent in 1993 and decreased 2.3
percent in 1992. Cool summer weather reduced sales in 1992 and, to a lesser
extent, in 1993. During 1993, NSP added 14,353 retail customers, a
1.1-percent increase. Total sales of electricity, including wholesale,
increased 7.3 percent in 1993.
On a weather-adjusted basis, sales to retail customers are estimated
to have increased 2.1 percent in 1993 and 2.8 percent in 1992. Retail sales
growth for 1994 is estimated to be 3.4 percent over 1993, or 2.2 percent on
a weather-adjusted basis.
Sales to other utilities increased 22.2 percent in 1993 due to higher
demand from utilities in flood-stricken Midwestern states.
The table below summarizes the principal reasons for the electric
revenue changes during the past two years.
(Millions of dollars) 1993 vs 1992 1992 vs 1991
Retail sales growth
(excluding weather impacts) $32 $34
Estimated impact of weather on
retail sales volume 34 (85)
Rate changes 74 20
Sales to other utilities 20 (2)
Cost of energy clauses and other (8) (7)
Total revenue increase (decrease) $152 $(40)
The 1992 sales growth is net of a $1.4-million revenue decrease, and
1992 cost-of-energy clause change is net of an $11 million revenue increase
from recording unbilled revenues, which were not recorded in 1991.
Electric Production Expenses - Fuel expense for electric generation increased
$19.4 million, or 6.6 percent, in 1993, compared with a decrease of $20.4
million, or 6.5 percent, in 1992. Total output from NSP's generating plants
increased 8.4 percent in 1993 and decreased 3.1 percent in 1992. The fuel
expense increase in 1993 was due to higher output to meet sales demand,
partially offset by lower cost of fuel. The fuel expense decrease in 1992 was
due to lower output (because the cool summer reduced demand) and lower cost
of fuel. The lower cost of fuel per megawatt hour of generation in 1993 and
1992 reflects the increased use of low-cost purchases as discussed below.
Purchased power costs increased $53.0 million, or 34.1 percent, in 1993
and $20.0 million, or 14.7 percent, in 1992. The increase in 1993 was largely
due to a demand expense increase of $42 million for the capacity charges from
the power purchase agreements with Manitoba Hydro-Electric Board (MH), as
discussed in Note 15 to the Financial Statements. Energy purchased from other
utilities increased in both 1993 and 1992 due to economically priced energy
available to meet growing retail demand and sales opportunities to other
utilities that provided net ratepayer benefit. Demand expenses in 1994 are
expected to increase $22 million over 1993 levels due to the MH agreements.
Revenues are adjusted for changes in electric fuel and purchased energy
costs from amounts currently included in approved base rates through fuel
adjustment clauses in all jurisdictions except as noted below for Wisconsin.
While the lag in implementing these billing adjustments is approximately 60
days, an estimate of the adjustments is recorded in unbilled revenue in the
month costs are incurred. In Wisconsin, the biennial retail rate review
process considers changes in electric fuel and purchased energy costs in lieu
of a fuel adjustment clause.
Gas Revenues and Purchases
Revenues - NSP categorizes gas sales as firm (primarily space heating
customers) and interruptible (commercial/industrial customers with an
alternate energy supply). Firm sales in 1993 increased 17.0 percent over 1992
sales, while firm sales in 1992 decreased 5.6 percent from 1991. Warm weather
in the first quarter of 1992 is the main cause for both of these variations.
NSP added 11,728 firm gas customers in 1993, a 3.1-percent increase.
On a weather-adjusted basis, firm sales are estimated to have increased
7.2 percent in 1993 and 3.6 percent in 1992. NSP estimates 1994 firm gas
sales to decrease by 2.9 percent relative to 1993, with a 2.2-percent
decrease on a weather-adjusted basis due to an unbilled revenue adjustment
in 1993. Without this adjustment, estimated weather-adjusted firm gas sales
would have increased 0.9 percent in 1993 and would be estimated to increase
0.7 percent in 1994.
Interruptible gas deliveries, including sales of gas purchased for
resale and customer-owned gas that NSP transported, increased 15.3 percent
in 1993 and decreased 0.9 percent in 1992.
The table below summarizes the principal reasons for the gas revenue
changes during the past two years.
(Millions of dollars) 1993 vs 1992 1992 vs 1991
Sales growth $17 $7
Estimated impact of weather
on sales volume 28 (24)
Acquisition of Viking Gas 9
Rate changes 9
Purchased gas adjustment
and other 30 15
Total revenue increase (decrease) $93 $(2)
The 1992 sales growth is net of a $1.5-million decrease from recording
unbilled revenues, which were not recorded in 1991.
Purchased Gas - The cost of gas purchased and transported increased $61.7
million, or 28.0 percent, in 1993 due to higher sendout and higher purchased
gas prices. In 1992, the cost of gas purchased and transported increased
$9.0 million, or 4.3 percent, due to higher purchased gas prices, somewhat
offset by lower sendout relative to 1991. The average cost per thousand cubic
feet (mcf) of gas sold in 1993 was 13.3 percent higher than it was in 1992,
when the cost was 7.1 percent higher than it was in 1991. NSP views the
increases in 1992 and 1993 as a recovery from unsustainably low wellhead gas
prices in the 1990-91 period. Revenues are adjusted for changes in purchased
gas costs from amounts currently included in approved base rates through
purchased gas adjustment clauses.
Other Operating Expenses and Factors
Other Operation, Maintenance and Administrative and General - These expenses,
in total, decreased by $27.2 million, or 4.0 percent, compared with an
increase of 1.8 percent in 1992. The 1993 decrease was the result of fewer
scheduled plant maintenance outages, reduced employee levels and lower
administrative costs. The 1992 increase was the result of higher levels of
scheduled plant and distribution system maintenance and higher employee
wages. Wages in 1993 included an accrual of $14 million for incentive
compensation. Due to lower earnings as a result of mild weather, compensation
in 1992 did not include incentive amounts. (See Note 7 to the Financial
Statements for a summary of administrative and general expenses.)
Conservation and Energy Management - Costs in 1993 were higher than in 1992
and 1991 because NSP's regulators have approved higher expenditure levels for
conservation and demand-side management efforts.
Depreciation and Amortization - The increases in depreciation for all periods
reflect higher levels of depreciable plant and, in 1993, changes in the
depreciable lives of certain property. (See Note 1 to the Financial
Statements.)
Property and General Taxes - Property and general taxes increased in each of
the reported periods primarily as a result of higher property tax rates and
property additions. Property taxes in 1992 were reduced by $4.5 million due
to revisions to accrued 1991 taxes (payable in 1992) based on final tax
statements.
Income Taxes - The variations in income taxes are primarily attributable to
fluctuations in pretax book income. Taxes in 1993 also increased about $3
million due to a 1-percent increase in the federal tax rate. (See Note 9 to
the Financial Statements for a detailed reconciliation of the statutory tax
rate to the actual effective tax rate.)
Allowance for Funds Used During Construction (AFC) - The differences in AFC
for the reported periods are attributable to varying levels of construction
work in progress and lower AFC rates associated with increased use of
low-cost short-term borrowings.
Other Income and Deductions-Net - Other income and deductions increased $9.7
million in 1993 and decreased $0.8 million in 1992. The increase in 1993 was
due to higher non-regulated operating income from improved refuse-derived
fuel (RDF) operations and acquired businesses. Non-regulated operating income
in 1992 reflects one-time expenses from unsuccessful energy projects and
reduced profitability of RDF operations. Decreases in interest income and
non-regulated operating income in 1992 were offset by lower expenses for
regulatory compliance and legal contingencies. Interest income declined in
1992 due to decreases in the amount of investments held. (See Note 7 to the
Financial Statements for a summary of amounts included in other income and
deductions.)
Interest Charges - Interest on long-term debt increased in 1993 due to new
debt issued to finance business acquisitions and to refinance short-term
borrowings. The increase was partially offset by interest savings from
refinancing debt at lower rates. Other interest charges have increased due
to amortization of refinancing costs, including debt issuance costs and
reacquisition premiums.
Item 8 - Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for financial statements included herein.
See Note 17 of Notes to Financial Statements for summarized quarterly
financial data.
INDEPENDENT AUDITORS' REPORT
Northern States Power Company:
We have audited the accompanying consolidated financial statements of
Northern States Power Company (Minnesota) and its subsidiaries, listed in the
accompanying table of contents in Item 14(a)1. Our audits also included the
financial statement schedules listed in the accompanying table of contents
in Item 14(a)2. These consolidated financial statements and financial
statement schedules are the responsibility of the Companies' management. Our
responsibility is to express an opinion on the consolidated financial
statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the consolidated financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall consolidated financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Companies at December 31,
1993 and 1992 and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1993 in conformity
with generally accepted accounting principles. Also, in our opinion, such
financial statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly in all
material respects the information set forth therein.
As discussed in Note 3 to the consolidated financial statements, the
Companies changed their method of accounting for postretirement health care
costs in 1993 and revenue recognition in 1992.
(Deloitte & Touche)
DELOITTE & TOUCHE
Minneapolis, Minnesota
February 7, 1994
<TABLE>
Consolidated Statements of Income
<CAPTION>
Year Ended Dec. 31
(Thousands of dollars, except per share data) 1993 1992 1991
<S> <C> <C> <C>
Utility Operating Revenues $2 403 992 $2 159 522 $2 201 158
Utility Operating Expenses
Electric production expenses -
fuel and purchased power 524 126 451 696 452 157
Cost of gas purchased and transported 282 028 220 370 211 361
Other operation 304 675 307 232 301 388
Maintenance 161 413 180 585 182 540
Administrative and general 182 535 187 975 179 860
Conservation and energy management 29 358 17 626 17 894
Depreciation and amortization 264 517 242 914 234 163
Property and general taxes 223 108 204 439 198 998
Income taxes 128 346 90 669 117 336
Total 2 100 106 1 903 506 1 895 697
Utility Operating Income 303 886 256 016 305 461
Other Income and Expense
Allowance for funds used during
construction - equity 7 328 8 993 7 534
Other income and deductions - net 8 618 (1 041) (290)
Total 15 946 7 952 7 244
Income Before Interest Charges 319 832 263 968 312 705
Interest Charges
Interest on long-term debt 104 714 103 035 102 929
Other interest and amortization 8 848 6 203 6 783
Allowance for funds used during
construction - debt (5 470) (6 198) (4 019)
Total 108 092 103 040 105 693
Income From Continuing Operations
Before Accounting Change 211 740 160 928 207 012
Discontinued Operations
Income from discontinued telephone
operations (net of income taxes) 237
Gain on disposal of telephone operations
(net of income taxes of $9,863) 16 798
Total 17 035
Accounting Change
Cumulative effect on prior year of
change in accounting principle -
unbilled revenues (net of deferred
income taxes of $30,594) 45 512
Net Income 211 740 206 440 224 047
Preferred Stock Dividends 14 580 16 172 17 994
Earnings Available for Common Stock $197 160 $190 268 $206 053
Average number of common and equivalent
shares outstanding (000's) 65 211 62 641 62 566
Earnings per average common share:
Continuing operations before accounting change $3.02 $2.31 $3.02
Discontinued telephone operations .27
Cumulative effect of unbilled revenue
accounting change .73
Total $3.02 $3.04 $3.29
Common Dividends Declared per Share $2.565 $2.495 $2.395
See Notes to Financial Statements
</TABLE>
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
Year Ended Dec. 31
(Thousands of dollars) 1993 1992 1991
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net Income $211 740 $206 440 $224 047
Adjustments to reconcile net income
to cash from operating activities:
Depreciation and amortization 286 855 261 457 255 826
Nuclear fuel amortization 43 120 45 129 48 886
Deferred income taxes from operations 12 256 5 186 23 696
Investment tax credit amortization (9 320) (9 708) (9 629)
Allowance for funds used during
construction - equity (7 328) (8 993) (7 534)
Cumulative effect of unbilled revenue
accounting change - net of tax (45 512)
Gain on disposal of telephone operations (26 661)
Conservation program expenditures -
net of amortization (21 185) (16 948) (2 739)
Cash provided by (used for) changes
in certain working capital items 33 259 (31 478) (103 923)
Cash provided by changes in other
assets and liabilities 12 437 4 029 4 625
Net Cash Provided by Operating Activities 561 834 409 602 406 594
Cash Flows from Investing Activities:
Capital expenditures (361 695) (427 815) (349 862)
Increase (decrease) in construction payables 2 598 (2 863) 7 120
Allowance for funds used during
construction - equity 7 328 8 993 7 534
Sale of short-term investments - net 62 1 552 70 853
Investment in external decommissioning fund (32 578) (27 929) (40 871)
Business acquisitions (159 385)
Proceeds from sale of telephone operations 48 000
Investments in non-regulated projects
and other (27 099) 1 548 (241)
Net Cash Used for Investing Activities (570 769) (446 514) (257 467)
Cash Flows from Financing Activities:
Change in short-term debt -
net issuances (repayments) (40 361) 146 561
Proceeds from issuance of long-term debt 613 120 126 531 49 957
Repayment of long-term debt including
reacquisition premiums (489 106) (48 344) (23 833)
Proceeds from issuance of common stock 183 654 2 940
Redemption of preferred stock
including premium (36 092) (25 838)
Dividends paid (180 220) (171 355) (166 394)
Net Cash Provided by (Used for)
Financing Activities 50 995 30 495 (140 270)
Net Increase (Decrease) in Cash and
Cash Equivalents 42 060 (6 417) 8 857
Cash and Cash Equivalents at Beginning
of Period 15 752 22 169 13 312
Cash and Cash Equivalents at End of Period $57 812 $15 752 $22 169
Cash Provided by (Used for) Changes
in Certain Working Capital Items:
Accounts receivable and accrued
utility revenues $(50 403) $(14 108) $(32 121)
Materials and supplies inventories 13 911 (5 280) (10 327)
Payables and accrued liabilities
(excluding construction payables) 54 247 5 206 (7 661)
Customer rate refunds 12 235 (11 987) (73 086)
Other 3 269 (5 309) 19 272
Net $33 259 $(31 478) $(103 923)
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized) $107 037 $99 669 $102 574
Income taxes $120 491 $93 032 $118 123
See Notes to Financial Statements
</TABLE>
<TABLE>
Consolidated Balance Sheets
<CAPTION>
Dec. 31
(Thousands of dollars) 1993 1992
<S> <C> <C>
Assets
Utility Plant
Electric - including construction
work in progress: 1993, $174,893;
1992, $147,763 $6 167 670 $5 956 865
Gas 621 871 481 157
Other 237 293 199 912
Total 7 026 834 6 637 934
Accumulated provision for depreciation (2 888 144) (2 593 213)
Nuclear fuel - including amounts in
process: 1993, $15,358; 1992, $29,725 749 078 711 517
Accumulated provision for amortization (673 669) (630 548)
Net utility plant 4 214 099 4 125 690
Current Assets
Cash and cash equivalents 57 812 15 752
Short-term investments - at cost,
which approximates market 26 88
Accounts receivable - net of
accumulated provision for
uncollectible accounts: 1993,
$4,476; 1992, $4,046 266 531 224 618
Accrued utility revenues 111 296 100 172
Federal income tax refund receivable 20 927 24 525
Materials and supplies - at average cost
Fuel 41 776 53 826
Other 103 599 105 041
Prepayments and other 40 885 28 724
Total current assets 642 852 552 746
Other Assets
Regulatory assets 334 354 239 487
External decommissioning fund
and other investments 169 745 108 865
Non-regulated property - net of
accumulated depreciation of $63,267
and $54,669, respectively 156 707 94 305
Intangible assets and other 69 961 21 368
Total other assets 730 767 464 025
Total $5 587 718 $5 142 461
Liabilities and Equity
Capitalization (See Consolidated Statements of Capitalization)
Common stockholders' equity $1 827 454 $1 622 098
Preferred stockholders' equity 240 469 275 493
Long-term debt 1 291 867 1 299 850
Total capitalization 3 359 790 3 197 441
Current Liabilities
Long-term debt due within one year 90 618 32 426
Redeemable long-term debt 141 600 41 600
Short-term debt - commercial paper 106 200 146 561
Accounts payable 210 654 180 149
Taxes accrued 177 853 161 533
Interest accrued 24 110 27 590
Dividends declared on common and
preferred stocks 46 195 43 220
Estimated rate refunds to customers 12 235
Accrued payroll and other 61 557 39 065
Total current liabilities 871 022 672 144
Other Liabilities
Deferred income taxes 788 378 770 092
Deferred investment tax credits 187 466 200 207
Regulatory liabilities 243 880 232 466
Pension and other benefit obligations 64 224 38 037
Other long-term obligations and
deferred income 72 958 32 074
Total other liabilities 1 356 906 1 272 876
Commitments and Contingent Liabilities
(See Note 15)
Total $5 587 718 $5 142 461
See Notes to Financial Statements
</TABLE>
<TABLE>
Consolidated Statements of Changes in Common Stockholders' Equity
<CAPTION>
Number of Retained Shares Held
(Dollar amounts in thousands) Shares Issued Par Value Premium Earnings by ESOP
<S> <C> <C> <C> <C> <C>
Balance at Dec. 31, 1990 62 541 404 $156 354 $368 021 $1 010 341 $(7 626)
Net Income 224 047
Dividends Declared:
Cumulative preferred stock
at required rates (17 994)
Common stock (149 787)
Capital Stock Expense and Other (48)
Loan to ESOP to purchase shares (15 000)
Repayment of ESOP loan 8 522
Balance at Dec. 31, 1991 62 541 404 $156 354 $368 021 $1 066 559 $(14 104)
Net Income 206 440
Dividends Declared:
Cumulative preferred stock
at required rates (16 172)
Common stock (156 109)
Exercise of Stock Options and
Other Stock Awards 56 956 142 2 805
Preferred Stock Redemption
and Stock Issuance Costs (7) (822)
Repayment of ESOP loan 8 991
Balance at Dec. 31, 1992 62 598 360 $156 496 $370 819 $1 099 896 $(5 113)
Net Income 211 740
Dividends Declared:
Cumulative preferred stock
at required rates (14 580)
Common stock (168 615)
Issuances of Common Stock 4 281 217 10 703 176 296
Preferred Stock Redemption
and Stock Issuance Costs (3 345) (1 069)
Loan to ESOP to purchase shares (15 000)
Repayment of ESOP loan 9 226
Balance at Dec. 31, 1993 66 879 577 $167 199 $543 770 $1 127 372 $(10 887)
See Notes to Financial Statements
</TABLE>
<TABLE>
Consolidated Statements of Capitalization
<CAPTION>
Dec. 31
(Thousands of dollars) 1993 1992
<S> <C> <C>
Common Stockholders' Equity
Common stock - authorized 160,000,000
shares of $2.50 par value; issued shares:
1993, 66,879,577; 1992, 62,598,360 $167 199 $156 496
Premium on common stock 543 770 370 819
Retained earnings 1 127 372 1 099 896
Leveraged common stock held by ESOP
- shares at cost: 1993, 239,940; 1992, 143,217 (10 887) (5 113)
Total common stockholders' equity $1 827 454 $1 622 098
Cumulative Preferred Stock - authorized 7,000,000
shares of $100 par value; outstanding shares:
1993, 2,400,000; 1992, 2,750,000
Minnesota Company
$3.60 series, 275,000 shares $27 500 $27 500
$4.08 series, 150,000 shares 15 000 15 000
$4.10 series, 175,000 shares 17 500 17 500
$4.11 series, 200,000 shares 20 000 20 000
$4.16 series, 100,000 shares 10 000 10 000
$4.56 series, 150,000 shares 15 000 15 000
$6.80 series, 200,000 shares 20 000 20 000
$7.00 series, 200,000 shares 20 000 20 000
$7.84 series, 350,000 shares 35 000
Variable Rate series A, 300,000 shares 30 000 30 000
Variable Rate series B, 650,000 shares 65 000 65 000
Total 240 000 275 000
Premium on preferred stock 469 493
Total preferred stockholders' equity 240 469 275 493
Long-Term Debt
First Mortgage Bonds Minnesota Company
Series due:
Sept. 1, 1993, 4 3/8% $15 000 March 1, 2002, 7 3/8% 50 000
June 1, 1995, 6 1/8% 30 000 Feb. 1, 2003, 7 1/2% 50 000
March 1, 1996, 6.2% 8 800* Jan. 1, 2004, 8 3/8% 75 000
Aug. 1, 1996, 5 7/8% 45 000 May 1, 2005, 9 1/2% 79 200
Oct. 1, 1997, 5 7/8% 100 000 Dec. 1, 1992-2006, 6.54% 24 400**
Oct. 1, 1997, 6 1/2% 30 000 March 1, 2011, Variable Rate 13 700*
May 1, 1998, 6 3/4% 45 000 Dec. 1, 2013, 10 3/8% 100 000*
Oct. 1, 1999, 8% 45 000 July 1, 2019, 9 1/8% 100 000
March 1, 2001, 8% 50 000 June 1, 2020, 9 3/8% 100 000
June 1, 2001, 8 1/4% 50 000
Total $1 011 100 $1 011 100
Issuance of Series due Dec. 1, 2000, 5 3/4% 100 000
Issuance of Series due April 1, 2003, 6 3/8% 80 000
Issuance of Series due Dec. 1, 2005, 6 1/8% 70 000
Less redemption of 1993, 1999, 2001, 2005 and 2013 series bonds (339 200)
Less sinking fund and other redemptions (2 000)
Less redeemable bonds classified as current (13 700) (13 700)
Less current maturities, including in 1993 the 2004 series
bonds redeemed in January 1994 (76 100) (16 000)
Net $830 100 $981 400
*Pollution control financing
**Resource recovery financing
See Notes to Financial Statements
Dec. 31
(Thousands of dollars) 1993 1992
Long-Term Debt - continued
First Mortgage Bonds Wisconsin Company -
(less reacquired bonds of $42 at Dec. 31, 1992)
Series due:
Aug. 1, 1994, 4 1/2% $10 938
Dec. 1, 1999, 9 1/4% 7 800
Oct. 1, 2003, 5 3/4% $40 000
Oct. 1, 2003, 7 3/4% 24 570
July 1, 2016, 9 1/4% 47 500
March 1, 2018, 9 3/4% 38 400
April 1, 2021, 9 1/8% 49 000 49 500
March 1, 2023, 7 1/4% 110 000
Total 199 000 178 708
Less current maturities - 1999 series redeemed in January 1993 (7 800)
Less sinking fund requirements not reacquired (1 808)
Net $199 000 $169 100
Guaranty Agreements Minnesota Company
Series due:
Feb. 1, 1992-2003, 5.41% $6 100* $6 400*
May 1, 1992-2003, 5.69% 25 250* 25 750*
Feb. 1, 2003, 7.40% 3 500* 3 500*
Total 34 850 35 650
Less current maturities (700) (800)
Net $34 150 $34 850
Miscellaneous Long-Term Debt
City of Becker Pollution Control Revenue Bonds - Series due
Dec. 1, 2005, 7.25% $9 000* $9 000*
April 1, 2007, 6.80% 60 000* 60 000*
March 1, 2019, Variable Rate 27 900* 27 900*
Sept. 1, 2019, Variable Rate 100 000*
Anoka County Resource Recovery Bond - Series due
Dec. 1, 1992-2008, 7.04% 26 100** 26 950**
City of La Crosse, Resource Recovery Bond - Series due
Nov. 1, 2011, 7 3/4% 18 600** 18 600**
Viking Gas Transmission Company Senior Notes - Series due
Oct. 31, 2008, 6.4% 31 644
NRG Energy Center, Inc. (Minneapolis Energy Center)
Senior Secured Notes - Series due June 15, 2013, 7.31% 83 518
Employee Stock Ownership Bank Loans due 1992-1995, Variable Rate 10 887 5 113
Other 8 397 4 075
Total 376 046 151 638
Less redeemable Becker bonds classified as current (127 900) (27 900)
Less current maturities (13 818) (6 018)
Net $234 328 $117 720
Unamortized discount on long-term debt - net (5 711) (3 220)
Total long-term debt 1 291 867 1 299 850
Total capitalization $3 359 790 $3 197 441
*Pollution control financing
**Resource recovery financing
See Notes to Financial Statements on pages
</TABLE>
Notes to Financial Statements
1. Summary of Accounting Policies
System of Accounts - Northern States Power Company, a Minnesota corporation
(the Company), and two wholly owned subsidiaries of the Company, Northern
States Power Company, a Wisconsin corporation (the Wisconsin Company), and
Viking Gas Transmission Company (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 significant subsidiary companies. All significant intercompany
transactions and balances have been eliminated in consolidation. The Company
and its subsidiaries collectively are referred to herein as NSP.
Revenues - Revenues are recognized based on services provided to customers
each month. Because customer utility 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. In 1991, revenues of the Company were recorded for billings
rendered to customers on a monthly cycle billing basis and estimated unbilled
revenues were not recorded. (See Note 3 for discussion of accounting change
in 1992.)
The Company's rate schedules, applicable to substantially all of its
customers, include cost-of-energy adjustment clauses, under which rates are
adjusted to reflect changes in average costs of fuels, purchased power and
gas purchased for resale. 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 power. The biennial
retail rate review process for Wisconsin electric operations considers
changes in electric fuel and purchased energy costs in lieu of a
cost-of-energy adjustment.
Utility Plant and Retirements - Utility Plant is stated at original cost. The
cost of additions to utility plant includes contracted work, direct labor and
materials, allocable overhead costs and allowance for funds used during
construction. The cost of units of property retired, plus net removal cost,
is charged to the accumulated provision for depreciation and amortization.
Maintenance and replacement of items determined to be less than units of
property are charged to operating expenses.
Allowance for Funds Used during Construction (AFC) - AFC, a non-cash item, is
computed by applying a composite pretax rate, representing the cost of
capital for construction, to qualified Construction Work in Progress (CWIP).
The rates were 7.4 percent in 1993, 8.0 percent in 1992 and 10.0 percent in
1991. The amount of AFC capitalized as a construction cost in CWIP is
credited to other income and interest charges. AFC amounts capitalized in
CWIP are included in utility rate base for establishing utility service
rates.
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 1993 study, as approved by the MPUC, recommended
an increase of approximately $0.9 million in annual depreciation accruals.
The 1992 study, as approved by the MPUC, recommended no change in 1992
depreciation. The Company also submitted in 1993 an average service life
filing for transmission, distribution and general properties, which is filed
every five years. The filing, as approved by the MPUC, increased depreciation
by approximately $4.7 million from 1992 levels. Depreciation provisions, as
a percentage of the average balance of depreciable property in service, were
3.47 percent in 1993, 3.36 percent in 1992 and 3.35 percent in 1991.
Decommissioning - The annual provision for the estimated decommissioning costs
for the Company's nuclear plants has been calculated using an
internal/external sinking fund method. The calculation, which results in
annual charges to depreciation expense, is designed to provide for full
accrual and rate recovery of the future decommissioning costs, including
reclamation and removal, over the estimated operating lives of the Company's
nuclear plants. Decommissioning of all nuclear facilities is planned to occur
in the years 2010-2022 using the prompt dismantlement method, and the total
obligation for decommissioning is expected to be funded approximately 45
percent by internal funds and 55 percent by external funds. Based on a 1990
study, the Company estimates total decommissioning costs will approximate
$750 million in 1993 dollars, for which the Company has recorded $302 million
in the accumulated provision for depreciation; $101 million of this balance
has been deposited in external trust funds. An updated study will not be used
for recording decommissioning accruals until approved by the MPUC. Such
approval is not expected to occur until after the Minnesota Legislature makes
its decision on fuel storage at the Company's Prairie Island nuclear plant.
(See Note 15.) Decommissioning costs recorded for 1993, 1992 and 1991 were
$43 million, $40 million and $40 million, respectively.
Nuclear Fuel Expense - The original cost of nuclear fuel is amortized to fuel
expense on the basis of energy expended. Nuclear fuel expense also includes
a disposal cost of 0.1 cent per kilowatt-hour sold from nuclear generation,
as required by the Nuclear Waste Policy Act of 1982. Disposal expenses were
$8.7 million, $6.8 million and $11.9 million for 1993, 1992 and 1991,
respectively. Disposal expenses reflect reductions of $2.6 million in 1993
and $3.7 million in 1992 due to a change in the basis of charging customers,
retroactive to 1983. Nuclear fuel expense in 1993 also includes about $1
million for a portion of the assessment from the U.S. Department of Energy
(DOE) for the decommissioning and decontamination of the DOE's uranium
enrichment facility. (See Note 8.)
Environmental Costs - Costs related to environmental remediation are accrued
when it is probable that a liability has been incurred and the amount of the
liability can be reasonably estimated. When a single estimate of the
liability cannot be determined, the low end of the estimated range is
recorded. Costs are charged to expense (or deferred as a regulatory asset
based on expected recovery from customers in future rates) if they relate to
the remediation of conditions caused by past operations or if they are not
expected to benefit future operations. Where the expenditure relates to
facilities currently in use (such as pollution control equipment), the costs
are capitalized and depreciated over the future service periods. Estimated
costs are recorded at undiscounted amounts, independent of any insurance or
rate recovery, based on prior experience. Accrued obligations are regularly
adjusted as new information is received. 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 related to decommissioning and restoration of its power
plants and substation sites as a removal cost of retirement through plant
depreciation expense.
Income Taxes - NSP records income taxes in accordance with Statement of
Financial Accounting Standards (SFAS) No. 109 - Accounting for Income Taxes.
SFAS No. 109 requires the use of the liability method of accounting for
deferred income taxes. Before 1993, NSP followed SFAS No. 96 - Accounting for
Income Taxes, resulting in substantially the same accounting as SFAS No. 109.
Income taxes are deferred for all temporary differences between pretax
financial and taxable income and between the book and tax bases of assets and
liabilities. Deferred taxes are recorded using the tax rates scheduled by law
to be in effect when the temporary differences reverse. Due to the effects
of regulation, current income tax expense is provided for the reversal of
some temporary differences previously accounted for by the flow-through
method. Also, regulation results in the creation of certain regulatory assets
and liabilities related to income taxes as discussed in Note 8.
Investment tax credits are deferred and amortized over the estimated
lives of the related property.
Cash Equivalents - NSP considers investments in certain debt instruments
(primarily commercial paper) with a remaining maturity of three months or
less at the time of purchase to be cash equivalents.
Regulatory Deferrals - As regulated utilities, the Company, the Wisconsin
Company and Viking account for certain income and expense items under the
provisions of SFAS No. 71 - Accounting for the Effects of Regulation. In
doing so, certain costs that would otherwise be charged to expense are
deferred as regulatory assets based on expected recovery from customers in
future rates. Likewise, certain credits that would otherwise 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 being amortized consistent with ratemaking treatment as
established by regulators. Note 8 describes in more detail the nature and
amounts of these regulatory deferrals.
Other Assets - NSP and its various subsidiaries have invested in many
non-regulated projects whose earnings are reported on the equity method of
accounting. Several of these projects are still in the development stage.
Other investments include project development expenditures of $16.5 million
as of Dec. 31, 1993, which have been capitalized based on expected recovery
from cash flows of future project operations.
The purchase of the Minneapolis Energy Center by NRG in 1993 (see Note
4) at a price exceeding the underlying fair value of net assets acquired
resulted in goodwill. This goodwill and other intangible assets acquired are
being amortized using the straight-line method over 30 years. NSP will
periodically evaluate the recovery of goodwill based on an analysis of
estimated undiscounted future cash flows.
Intangible and other assets also include deferred financing costs of
approximately $12.6 million at Dec. 31, 1993, which are being amortized over
the remaining maturity period of the related debt.
Reclassifications - Certain reclassifications have been made to the 1992 and
1991 income statement to conform with the 1993 presentation. In addition, the
1992 balance sheet has been reclassified to conform with the 1993
presentation of regulatory deferrals. These reclassifications had no effect
on net income or earnings per share.
2. Rate Matters - 1993 Rate Increases
Minnesota Jurisdiction - In November 1992, the Company filed applications for
1993 rate increases with the MPUC totaling $119.1 million and $14.9 million
for Minnesota retail electric and natural gas customers, respectively. This
represented annual increases of approximately 9 percent and 5.8 percent,
respectively. In December 1992, the MPUC issued orders granting interim
increases (subject to refund) of $71.2 million (5.4 percent) for electric
service and $8.4 million (3.3 percent) for gas service, effective Jan. 1,
1993. In June 1993, the Company adjusted its proposed electric rate increase
to $112.3 million and its gas rate request to $12.4 million.
The Company received initial orders from the MPUC in September 1993 for
both the gas and electric cases. Final orders came in December 1993 for the
gas case and in January 1994 for the electric case, allowing annualized
retail rate increases of $10.0 million (3.9 percent) for gas and $72.2
million (5.4 percent) for electric. The return on equity granted in both
cases was 11.47 percent. Refunds of interim electric rates collected are
required in the amount of approximately $12 million and are expected to be
paid in May 1994. No refunds of interim gas rates collected are required.
Final gas and electric rates are expected to be implemented in March and
April 1994, respectively.
On Jan. 31, 1994, an appeal of the MPUC's determination on the allowed
return on equity was filed with the Minnesota Court of Appeals by the
Minnesota Department of Public Service, the Office of the Minnesota Attorney
General and the Minnesota Energy Consumers intervenor groups. The appeal
concerns the method of calculating the rate of return on common equity for
both the electric and gas cases. The amount at issue is approximately $7
million in annual revenues for the Company. The ultimate financial impact of
this appeal, if any, is not determinable at this time. A decision by the
court is expected by the end of 1994.
Other Jurisdictions - The Wisconsin Company received approval of annualized
retail rate increases of $8.0 million (3.1 percent) for Wisconsin electric
customers and $1.1 million (1.8 percent) for Wisconsin gas customers. The new
rates have been in effect since January 1993. The Company's approved
annualized rate increase of $4.8 million (5.3 percent) for North Dakota
electric customers was effective April 21, 1993. The Company's approved
annualized rate increase of $4.2 million (6.5 percent) for South Dakota
electric customers has been in effect since May 1, 1993. Increased annualized
wholesale electric rates of $0.9 million (3.6 percent) were accepted by the
FERC for nine Minnesota Company wholesale customers, effective Sept. 21,
1993. Increased annualized wholesale electric rates of $0.6 million (3.7
percent) were accepted by the FERC for the Wisconsin Company's 10 wholesale
municipal utilities effective Sept. 1, 1993.
3. Accounting Changes
Postretirement Benefits - (See Note 13 for discussion of NSP's 1993 change in
accounting for postretirement medical and death benefits.) There was no
material effect on net income due to rate recovery of the expense increases.
Of the $20 million in 1993 cost increases over 1992 due to adoption of SFAS
No. 106, about $5 million was capitalized, $12 million was deferred to be
amortized over rate recovery periods in 1994-1996 and about $3 million was
expensed but essentially offset by rate increases.
Income Taxes - As discussed in Note 1, NSP adopted SFAS No. 109 - Accounting
for Income Taxes, effective Jan. 1, 1993. Adoption of SFAS No. 109 had no
effect on earnings or financial condition due to its similarity to SFAS No.
96 - Accounting for Income Taxes, which NSP adopted in 1988 and which SFAS
No. 109 supersedes.
Revenue Recognition - Effective Jan. 1, 1992, the Company changed its revenue
recognition method to include the accrual of estimated unbilled revenues for
electric and gas service in its Minnesota, North Dakota and South Dakota
operations. This accounting practice has been used by the Wisconsin Company
since 1977. This change resulted in a better matching of revenues and
expenses, and is consistent with predominant utility industry practice and
the ratemaking principles in NSP's two major jurisdictions (Minnesota and
Wisconsin). The effect on 1992 income before accounting changes was an
increase of approximately $9.8 million (16 cents per share), while the effect
on total 1992 earnings was an increase of approximately $55.3 million (88
cents per share). If the accounting change had been applied retroactively to
Jan. 1, 1991, income from continuing operations for 1991 would have been
$204.4 million ($2.98 per share).
1994 Changes - In 1994, NSP will adopt SFAS No. 112 - Accounting for
Postemployment Benefits and a new accounting standard for employers'
transactions with ESOP plans. SFAS No. 112 requires the accrual of certain
employee costs (such as injury compensation and severance) to be paid in
future periods. The adoption of these new accounting standards is not
expected to have a material effect on NSP's results of operations or
financial condition.
4. Business Acquisitions
Viking Gas Transmission Company - On June 10, 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, for approximately $45
million, $32 million of which was financed with project debt. 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. Viking presently 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 the FERC.
Minneapolis Energy Center - On Aug. 20, 1993, NRG Energy, Inc. (NRG), a wholly
owned subsidiary of the Company, acquired the assets of the Minneapolis
Energy Center (MEC), a district heating and cooling system in downtown
Minneapolis, Minn. The system uses steam and chilled water generating
facilities to heat and cool buildings for about 85 heating and 25 cooling
customers. The purchase price was $110 million, $84 million of which was
financed with project debt. The purchase price primarily included facilities,
long-term service agreements and goodwill.
Cenergy, Inc. - On Oct. 1, 1993, Cenergy, Inc., a non-regulated subsidiary of
the Company, acquired certain assets of Centran Corporation (Centran), a
natural gas marketing company. Cenergy, Inc., a national marketer of energy
services with approximately 30 employees and approximately 300 customers, is
headquartered in Minneapolis, Minn., and has additional offices in Houston
and Corpus Christi, Texas; Louisville, Ky.; and Chesapeake, Va. The purchase
price was $4 million. Assets purchased included proven oil and gas reserves,
office equipment and a customer marketing data base.
Operating Results - The following represents unaudited operating results
presented on a pro forma basis as if the acquisitions described above
occurred on Jan. 1, 1992. Actual results, including Viking since June 10,
1993, MEC since Aug. 20, 1993, and the acquired Centran operations since Oct.
1, 1993, are shown for comparative purposes.
Year Ended Dec. 31
(Dollars in millions except EPS) 1993 1992
Actual Results
Utility operating revenues $2 404.0 $2 159.5
Non-regulated operating
revenues and sales $90.7 $62.6
Net income $211.7 $206.4
Earnings per share $3.02 $3.04
Pro Forma Amounts
Utility operating revenues $2 411.9 $2 176.0
Non-regulated operating
revenues and sales $161.2 $272.6
Net income $212.6 $204.9*
Earnings per share $3.04 $3.01*
*Includes pretax writedown of $2.3 million (2 cents per share) of deferred
environmental costs for Viking.
5. Cumulative Preferred Stock
The Company has two series of adjustable rate preferred stock. The dividend
rates are calculated quarterly and based on prevailing rates of certain
taxable government debt securities indices. At Dec. 31, 1993, the annualized
dividend rates were $5.50 for series A and $5.50 for series B.
At Dec. 31, 1993, the various preferred stock series were callable at
prices per share ranging from $102.00 to $103.75, plus accrued dividends. In
1993, the Company redeemed all 350,000 shares of its $7.84 series Cumulative
Preferred Stock at $103.12 per share. In 1992, the Company redeemed all
250,000 shares of its $8.80 series Cumulative Preferred Stock at $103.35 per
share.
6. 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, 1993, the payment of cash dividends on common stock was not
restricted.
NSP has an Executive Long-Term Incentive Award Stock Plan that permits
granting non-qualified stock options. The options currently granted may be
exercised one year from the date of grant and are exercisable thereafter for
up to nine years. The plan also allows certain employees to receive other
awards for restricted stock, stock appreciation rights and other performance
awards. Performance awards are valued in dollars, but are paid in shares
based on market price at the time of payment. Transactions under the various
stock incentive programs, which may result in the issuance of new shares,
were as follows:
Stock Awards
(Thousands of shares) 1993 1992 1991
Outstanding Jan. 1 528.7 403.3 161.0
Options granted 196.9 201.8 232.2
Other stock awards 9.5 .8 16.9
Options and awards exercised (174.3) (57.0) 0
Options and awards forfeited (22.2) (20.1) (6.8)
Other (1.5) (.1) 0
Outstanding at Dec. 31 537.1 528.7 403.3
Option price ranges:
Unexercised
at Dec. 31 $33.25-$43.50 $33.25-$40.94 $33.25-$36.44
Exercised during
the year $33.25-$40.94 $33.25-$36.44
Using the treasury stock method of accounting for outstanding stock
options, the weighted average number of shares of common stock outstanding
for the calculation of primary earnings per share includes any dilutive
effects of stock options and other stock awards as common stock equivalents.
The differences between shares used for primary and fully diluted earnings
per share were not material.
7. Detail of Certain Income and Expense Items
Administrative and general (A&G) expense for utility operations consists of
the following:
(Thousands of dollars) 1993 1992 1991
A&G salaries and wages $52 085 $49 096 $48 710
Pensions and benefits -
all utility employees 63 938 65 278 58 306
Information technology, facilities
and administrative support 30 504 35 139 33 698
Insurance and claims 18 598 20 512 21 404
Other 17 410 17 950 17 742
Total $182 535 $187 975 $179 860
Other income and deductions - net consist of the following:
(Thousands of dollars) 1993 1992 1991
Non-regulated operations:
Operating revenues and sales $90 654 $62 616 $76 342
Operating expenses
(excluding income taxes) 81 403 65 744* 69 327
Pretax operating income (loss) 9 251 (3 128) 7 015
Interest and investment income 4 522 3 452 6 489
Equity in earnings of
non-regulated projects 3 030 2 382 226
Charitable contributions (4 752) (4 585) (4 231)
Costs disallowed recovery
by regulators (296) (1 603) (6 100)
Legal and regulatory contingencies (100) (1 300) (5 100)
Other - net (excluding income taxes) (643) (752) (494)
Income tax (expense) benefit (2 394) 4 493 1 905
Total $8 618 $(1 041) $(290)
*Includes $6.8 million in writedowns and losses from unsuccessful
non-regulated projects.
8. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory
assets and liabilities shown on the Balance Sheet at Dec. 31:
(Thousands of dollars) 1993 1992
AFC recorded in plant on a net-of-tax basis $165 915 $164 740
Losses on reacquired debt 48 529 33 185
Conservation and energy management programs 46 939 25 754
Environmental costs 45 568 505
Deferred postretirement benefit costs 15 514 2 112
State commission accounting adjustments 6 246 5 954
Unrecovered purchased gas costs and other 5 643 7 237
Total regulatory assets $334 354 $239 487
Excess deferred income taxes
collected from customers $113 276 $106 975
Investment tax credit deferrals 120 123 119 847
Pension costs 6 969 2 017
Fuel refunds and other 3 512 3 627
Total regulatory liabilities $243 880 $232 466
The environmental costs item includes an assessment from the DOE for the
Company's allocated share of decontamination and decommissioning costs
related to the DOE's uranium enrichment facility. The Company's total DOE
assessment of $46 million was made in 1993. This assessment will be payable
in annual installments (currently $3.1 million) for up to 15 years and will
be expensed on a monthly basis in the 12 months following each payment.
Future installments are subject to inflation adjustments under DOE rules. The
FERC has approved wholesale ratemaking recovery of these assessments as paid
through the cost-of-energy adjustment clause. Since the Company's retail
regulators currently fully conform to the FERC's cost-of-energy adjustment
clause procedures, management also expects recovery of these DOE assessments
in retail ratemaking as payments are made each year.
The AFC regulatory asset and the tax-related regulatory liabilities
result from NSP's income tax accounting practices as discussed in Note 1. The
excess deferred income tax liability represents the net amount expected to
be reflected in future customer rates based on the collection in prior
ratemaking of deferred income tax amounts in excess of the actual liabilities
recorded by NSP. This excess is the net effect of the use of flow-through tax
accounting in prior ratemaking and the impact of changes in statutory tax
rates in 1981, 1986-87 and 1993. This regulatory liability will change each
year as the related deferred income tax liabilities change.
9. Income Tax Expense
Total income tax expense from operations differs from the amount computed by
applying the statutory federal income tax rate (35 percent in 1993 and 34
percent in 1992 and 1991) to net income before income tax expense. The
reasons for the difference are as follows:
(Thousands of dollars) 1993 1992 1991
Tax Computed at Statutory
Federal Rate $119 868 $84 015 $118 829
Increases (decreases) in tax from:
State income taxes net of federal
income tax benefit 20 838 13 421 20 822
Tax credits recognized (9 545) (8 846) (9 511)
Nontaxable AFC - equity included
in book income (2 565) (3 058) (2 562)
Net-of-tax AFC included in
book depreciation 4 403 4 518 4 594
Use of the flow-through method
for depreciation in prior years 7 004 5 884 6 163
Effect of tax rate changes for
plant-related items (4 648) (5 202) (6 798)
Dividends paid on ESOP shares (3 009) (3 245) (3 199)
Other - net (1 606) (1 311) (2 888)
Total income tax expense
from operations $130 740 $86 176 $125 450
Effective federal and state
income tax rate 38.2% 34.9% 35.9%
Composite federal and state
statutory tax rate 40.9% 39.9% 39.9%
Income taxes are comprised of the
following expense (benefit) items:
Included in utility operating
expenses:
Current federal tax expense $92 099 $69 198 $72 197
Current state tax expense 25 787 18 535 21 081
Deferred federal tax expense 15 010 8 518 25 157
Deferred state tax expense 4 431 2 533 7 779
Tax credits recognized (8 981) (8 115) (8 878)
Total 128 346 90 669 117 336
Included in other income and expense:
Current federal tax expense 7 853 1 490 3 708
Current state tax expense 2 289 613 1 128
Deferred federal tax expense (6 736) (4 518) (5 580)
Deferred state tax expense (449) (1 347) (850)
Tax credits recognized (563) (731) (311)
Total 2 394 (4 493) (1 905)
Included in discontinued operations:
Current federal tax expense -
operations 129
Current federal tax expense - gain 10 193
Current state tax expense -
operations 28
Current state tax expense - gain 2 921
Deferred federal tax expense (2 271)
Deferred state tax expense (539)
Tax credits recognized (442)
Total 10 019
Total income tax expense from
operations $130 740 $86 176 $125 450
The components of NSP's net deferred tax liability at Dec. 31 were as
follows:
(Thousands of dollars) 1993 1992
Deferred tax liabilities:
Differences between book and
tax bases of property $792 542 $765 957
Regulatory assets 128 991 90 856
Tax benefit transfer leases 87 924 97 852
Other 7 050 5 791
Total deferred tax liabilities $1 016 507 $960 456
Deferred tax assets:
Regulatory liabilities $95 504 $92 165
Deferred investment tax credits 73 648 74 047
Deferred compensation, vacation
and other accrued liabilities
not currently deductible 62 811 29 715
Other 11 341
Total deferred tax assets $243 304 $195 927
Net deferred tax liability $773 203 $764 529
The Omnibus Budget Reconciliation Act of 1993 (the Act) was signed into
law on Aug. 10, 1993, and increased the federal corporate income tax rate
from 34 percent to 35 percent retroactive to Jan. 1, 1993. Deferred tax
liabilities were increased for the rate change by approximately $32 million.
However, due to regulatory deferral of utility tax adjustments, earnings were
reduced by immaterial adjustments to deferred tax liabilities related to
non-regulated operations.
10. Long-Term Debt
The annual sinking-fund requirements of the Company's and the Wisconsin
Company's First Mortgage Indentures are the amounts necessary to redeem 1
percent of the highest principal amount of each series of first mortgage
bonds at any time outstanding, excluding those series issued for pollution
control and resource recovery financings, and excluding certain other series
totaling $320 million. The Company may, and has, applied property additions
in lieu of cash payments on all series except for the 91/8 percent Series due
July 1, 2019, as permitted by its First Mortgage Indenture. The Wisconsin
Company may also apply property additions in lieu of cash on all series as
permitted by its First Mortgage Indenture. Except for minor exclusions, all
real and personal property is subject to the liens of the first mortgage
indentures.
The variable rate First Mortgage Bonds Series due March 1, 2011, and the
variable rate City of Becker Pollution Control Revenue Bonds Series due March
1, 2019, and Sept. 1, 2019, are redeemable upon seven days' notice at the
option of the bondholder. Thus, the principal amount of these bonds
outstanding at Dec. 31, 1993, is reported under current liabilities on the
balance sheet. Their tax-exempt interest rates are subject to change, weekly
or at various periods, and are based on prevailing rates for similar issues.
The interest rates applicable to these issues averaged 3.0 percent, 2.6
percent and 2.5 percent, respectively, at Dec. 31, 1993.
The Company and the Wisconsin Company have entered into interest rate
swap agreements with the underwriters of certain first mortgage bond issues,
which effectively convert the interest cost for this debt from fixed to
variable rate as summarized below:
Amount of Term of Net Effective
Swap (millions Swap Interest Cost at
Series of dollars) Agreement Dec. 31, 1993
5 7/8% Series due
Oct. 1, 1997 $100 Maturity 3.38%
7 1/4% Series due
March 1, 2023 $20 March 1, 1998 5.56%
The variable rates change semiannually. Interest rate swap transactions
are recognized as an adjustment of interest expense over the terms of the
agreements.
Maturities and sinking-fund requirements on long-term debt are as
follows: 1994, $90,618,000; 1995, $41,348,000; 1996, $61,931,000; 1997,
$138,401,000; and 1998, $57,352,000.
On Jan. 24, 1994, the Company notified bondholders that $150 million of
first mortgage bonds would be redeemed on Feb. 24, 1994. These bonds have
been classified as long-term debt based on the refinancing of such debt using
first mortgage bond proceeds obtained in February 1994.
11. Short-Term Borrowings
NSP has approximately $215 million of commercial bank credit lines under
commitment fee arrangements. These credit lines make short-term financing
available in the form of bank loans and support for commercial paper sales.
There were no borrowings against these credit lines at Dec. 31, 1993 and
1992. At Dec. 31, 1993, the Company had $106.2 million in short-term
commercial paper borrowings outstanding at interest rates varying from 3.3
to 3.5 percent.
12. Fair Value of Financial Instruments
SFAS No. 107 - Disclosures About Fair Value of Financial Instruments requires
disclosure of the estimated fair value of financial instruments. For cash,
cash equivalents and short-term investments, the carrying amount approximates
fair value because of the short maturity of those instruments. The fair
values of the Company's long-term investments in an external nuclear
decommissioning fund are estimated based on quoted market prices for those
or similar investments. The fair value of NSP's long-term debt is estimated
based on the quoted market prices for the same or similar issues, or the
current rates offered to NSP for debt of the same remaining maturities. The
estimated Dec. 31 fair values of NSP's financial instruments are as follows:
1993 1992
Carrying Fair Carrying Fair
(Thousands of dollars) Amount Value Amount Value
Cash, cash equivalents
and short-term investments $57 838 $57 838 $15 840 $15 840
Long-term decommissioning
investments $101 378 $110 130 $68 800 $72 180
Long-term debt including
current portion $1 524 085 $1 584 435 $1 373 876 $1 437 999
13. Benefit Plans and Other Postretirement Benefits
Pension Benefits - NSP has a non-contributory, defined benefit pension plan
that covers substantially all employees. Benefits are based on a combination
of years of service, the employee's highest average pay for 48 consecutive
months and Social Security benefits.
For regulatory purposes, the Company's pension expense is determined and
recorded under the aggregate-cost method. SFAS No. 87 - Employers' Accounting
for Pensions provides that any difference between the pension expense
recorded for ratemaking purposes and the amounts determined under SFAS No.
87 should be recorded as assets or liabilities on the balance sheet.
Net annual periodic pension cost includes the following components:
(Thousands of dollars) 1993 1992 1991
Service cost-benefits earned
during the period $25 015 $24 080 $22 097
Interest cost on projected
benefit obligation 71 075 69 853 65 557
Actual return on assets (152 019) (115 455) (246 678)
Net amortization and deferral 66 299 39 019 181 543
Net periodic pension cost
determined under SFAS No. 87 10 370 17 497 22 519
Costs recognized (deferred)
due to actions of regulators 5 117 2 741 (1 549)
Total pension costs recorded
during the period 15 487 20 238 20 970
Less costs recognized for 1988
early retirement program (165) (165)
Net periodic pension cost
recognized for ratemaking $15 487 $20 073 $20 805
The funded status of the plan as of Dec. 31 is as follows:
(Thousands of dollars) 1993 1992
Actuarial present value of benefit obligation:
Vested $655 002 $614 446
Nonvested 139 346 129 183
Accumulated benefit obligation $794 348 $743 629
Projected benefit obligation $974 160 $914 019
Plan assets at fair value 1 244 650 1 156 782
Plan assets in excess of
projected benefit obligation (270 490) (242 763)
Unrecognized prior service cost (22 580) (14 790)
Unrecognized net actuarial gain 315 049 269 086
Unrecognized net transitional asset 767 843
Net pension liability included
in other liabilities $22 746 $12 376
The weighted average discount rate used in determining the actuarial
present value of the projected obligation was 7 percent in 1993 and 8 percent
in 1992. The rate of increase in future compensation levels used in
determining the actuarial present value of the projected obligation was 5
percent in 1993 and 6 percent in 1992. While the 1993 assumption changes had
no effect on 1993 pension costs, the effect of the changes in 1994 is
expected to be a cost decrease of approximately $3 million. The assumed
long-term rate of return on assets used for cost determinations under SFAS
No. 87 was 8 percent in 1993 and 1992 and 8.5 percent in 1991. The effect of
the 1992 change in the assumed rate of return was an increase of $4.3 million
in the estimated SFAS No. 87 net periodic pension cost in 1992. Plan assets
principally consist of common stock of public companies and U.S. government
securities.
Postretirement Health Care - Effective Jan. 1, 1993, NSP adopted the
provisions of SFAS No. 106 - Employers' Accounting for Postretirement
Benefits Other Than Pensions. SFAS No. 106 requires the actuarially
determined obligation for postretirement health care and death benefits to
be fully accrued by the date employees attain full eligibility for such
benefits, which is generally when they reach retirement age. This is a
significant change from NSP's prior policy of recognizing benefit costs on
a cash basis after retirement. In conjunction with the adoption of SFAS No.
106, NSP elected to amortize on a straight-line basis over 20 years the
unrecognized accumulated postretirement benefit obligation (APBO) of $215.6
million for current and future retirees. This obligation considers
anticipated 1994 plan design changes, including Medicare integration,
increased retiree cost sharing and managed indemnity measures not in effect
in 1993.
Prior to 1993, NSP funded benefit payments to retirees internally. While
NSP generally prefers to continue using internal funding of benefits paid and
accrued, significant levels of external funding have been imposed by NSP's
regulators, as discussed below, including the use of tax-advantaged trusts.
Plan assets held in such trusts as of Dec. 31, 1993, consisted of investments
in equity mutual funds and cash equivalents.
The following table sets forth the health care plan's funded status in
1993.
(Millions of dollars) Dec. 31, 1993 Jan. 1, 1993
APBO:
Retirees $120.2 $105.8
Fully eligible plan participants 18.8 18.8
Other active plan participants 90.8 91.0
Total APBO 229.8 215.6
Plan Assets 6.1 0
APBO in excess of plan assets 223.7 215.6
Unrecognized net actuarial loss (1.3)
Unrecognized transition obligation (204.8) (215.6)
Postretirement benefit obligation
included in other liabilities $17.6 $0
The assumed health care cost trend rate used in measuring the APBO at
Dec. 31, 1993, was 14.1 percent for those under age 65 and 8.0 percent for
those over age 65. The assumed cost trend rates are expected to decrease each
year until they reach 4.5 percent for both age groups in the year 2004, after
which they are assumed to remain constant. The trend rates used in the Jan.
1, 1993, calculations were 15.1 percent and 9.0 percent, respectively,
eventually decreasing to 5.5 percent in 2004. A 1-percent increase in the
assumed health care cost trend rate for each year would increase the APBO as
of Dec. 31, 1993, by approximately 17 percent, and service and interest cost
components of the net periodic postretirement cost by approximately 20
percent. The assumed discount rate used in determining the APBO was 7 percent
for Dec. 31, 1993, and 8 percent for Jan. 1, 1993, compounded annually. The
assumed long-term rate of return on assets used for cost determinations under
SFAS No. 106 was 8 percent for both measurement dates. While the assumption
changes made for the Dec. 31 calculations had no effect on 1993 benefit
costs, the effect of the changes in 1994 is expected to be a cost decrease
of approximately $2 million.
In 1992 and 1991, NSP recognized $12.8 million and $11.2 million,
respectively, as the cost attributable to postretirement health care and
death benefits based on payments made. The net annual periodic postretirement
benefit cost recorded for 1993 consists of the following components:
(Millions of dollars) 1993
Service cost-benefits earned during the year $4.4
Interest cost (on service cost and APBO) 17.5
Actual return on assets (.1)
Amortization of transition obligation 10.8
Net amortization and deferral .1
Net periodic postretirement health care
cost under SFAS No. 106 32.7
Costs deferred due to actions of regulators (12.1)
Net periodic postretirement health care
cost recognized for ratemaking $20.6
Regulators of NSP's retail rates in Minnesota, Wisconsin and North
Dakota have allowed full recovery of increased benefit costs under SFAS No.
106, effective in 1993. Expense recognition and rate recovery of increased
1993 accrual costs for Minnesota have been deferred until 1994 through 1996,
consistent with rate orders received. External funding was required in
Minnesota and Wisconsin to the extent it is tax advantaged; funding began for
Wisconsin in 1993 and must begin by the next general rate filing for
Minnesota.
Rate increases for Minnesota and Wisconsin wholesale electric customers
were approved by the FERC and provided recovery of accrued SFAS No. 106
benefits under new rates beginning in September 1993. A rate increase for
Viking wholesale gas customers was approved by the FERC, before Viking's
acquisition by the Company, and provided recovery of accrued benefits
beginning in July 1993. The FERC has required external funding for all
benefits paid and accrued under SFAS No. 106.
The impact of adopting SFAS No. 106 on other utility jurisdictions and
non-regulated operations was not material.
ESOP - NSP also has a leveraged Employee Stock Ownership Plan (ESOP) that
covers substantially all employees. Employer contributions to this plan are
generally made to the extent NSP realizes a tax savings on its income
statement from dividends paid on shares held by the ESOP. Contributions to
the ESOP in 1993, 1992 and 1991, which approximate expenses determined under
the shares-allocated method, were $6,281,000, $6,415,000 and $6,326,000,
respectively. ESOP contributions have no material effect on NSP earnings
because the contributions (net of tax) are essentially offset by the tax
savings provided by the dividends paid on ESOP shares. (See Note 9.)
14. Joint Plant Ownership
The Company is a participant in a jointly owned 855-megawatt coal-fired
electric generating unit, Sherburne County Generating Station Unit No. 3
(Sherco 3), which began commercial operation Nov. 1, 1987. Undivided
interests in Sherco 3 have been financed and are owned by the Company (59
percent) and Southern Minnesota Municipal Power Agency (41 percent). The
Company is the operating agent under the joint ownership agreement. The
Company's share of related expenses for Sherco 3 since commercial operations
began are included in Utility Operating Expenses. The Company's share of the
gross cost recorded in Utility Plant at Dec. 31, 1993 and 1992, was
$584,822,000 and $582,799,000, respectively. The corresponding accumulated
provisions for depreciation were $114,251,000 and $96,035,000.
15. Commitments and Contingent Liabilities
Commitments - NSP estimates utility capital expenditures, including
acquisitions of nuclear fuel, will be $396 million in 1994 and $1.8 billion
for 1994-1998. There also are contractual commitments for the disposal of
spent nuclear fuel.
Rentals under operating leases were approximately $27.5 million, $25.1
million and $22.7 million for 1993, 1992 and 1991, respectively.
Fuel Contracts - NSP has long-term 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 1994 and 2013, require minimum contractual purchases and deliveries
of fuel, and additional payments for the rights to purchase coal in the
future. In total, NSP is committed to the purchase and receipt of
approximately $374 million of coal, $129 million of nuclear fuel and $607
million of natural gas, or to make payments in lieu thereof, under these
contracts. Because NSP has other sources of fuel available and because
suppliers are expected to continue to provide reliable fuel supplies, risk
of loss from non-performance under these contracts is not considered
significant. In addition, NSP's risk of loss (in the form of increased costs)
from market price changes in fuel is mitigated through the cost-of-energy
adjustment provision of the ratemaking process, which provides for recovery
of nearly all fuel costs.
Power Agreements - The Company has executed several agreements with the
Manitoba Hydro-Electric Board (MH) for hydroelectricity. A summary of the
agreements is as follows:
Years Megawatts
Participation Power Purchases 1994-2005 500
Seasonal Participation Power
Purchase 1994-1996 1994 150
1995-1996 250
Seasonal Peaking Power Purchases 1994-1996 200
Seasonal Diversity Exchanges:
Summer exchanges from MH 1994 400
1995-2014 150
1997-2016 200
Winter exchanges to MH 1995-2014 150
1996-2015 200
2015-2017 400
2018 200
The cost of the participation power purchase commitment is based on 80
percent of the costs of owning and operating Sherco 3 (adjusted to 1993
dollars). The total estimated annual costs for all MH agreements are $68.2
million for 1994 and approximately $70 million thereafter. These commitments,
which represent about 38 percent of MH's output capability in 1993, account
for approximately 13 percent of the Company's 1993 system capability. The
risk of loss from non-performance by MH is not considered significant and the
risk of loss from market price changes is mitigated through cost-of-energy
rate adjustments.
The Company and MH jointly have made commitments to provide additional
transmission capacity to accomplish the seasonal diversity exchanges and to
provide 200 megawatts of transmission capacity for United Power Association.
The Company's agreements with MH call for the addition of facilities that
will allow the Company's existing 500-kilovolt line from Winnipeg to the Twin
Cities to accommodate the additional levels of transactions. The Company and
MH began construction in early 1992, received all the necessary approvals in
1993 and expect to complete construction in 1995.
The Company has an agreement with Minnkota Power Cooperative (MPC) for
the purchase of summer season capacity and energy. From 1994 through 2001,
the Company will buy 150 megawatts of summer season capacity for $12.4
million annually. From 2002 through 2015, the Company will purchase 100
megawatts of capacity for $10.0 million annually. Energy under the agreement
will be priced against the cost of fuel consumed per megawatt-hour at the
Coyote Generating Station in North Dakota. The Company also has three
seasonal (summer) purchase power agreements, with MPC, Minnesota Power and
Rochester Public Utility, for the purchase of 270 megawatts in 1994 and 250
megawatts in 1995 and 1996. The annual cost of this capacity will be
approximately $3 million.
The Company has agreements with several non-regulated entities to
purchase electric capacity and associated energy. The total annual cost of
current commitments for non-regulated installed capacity ranges from
approximately $18 million for 119 megawatts in each of the years 1994-2011,
decreasing thereafter to $0.8 million in 2033. The Company is negotiating a
new power-purchase agreement with an independent power producer, which is
expected to provide an additional 232 megawatts of electric capacity and
associated energy, beginning in 1997.
Nuclear Insurance - The Company's public liability for claims resulting from
any nuclear incident is limited to $9.4 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 $9.2 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 $79.3 million for each of its three licensed reactors to be
applied for public liability arising from a nuclear incident at any licensed
nuclear facility in the United States. The maximum funding requirement is $10
million per reactor during any one year.
The Company purchases insurance for property damage and decontamination
clean-up costs with coverage limits of $2.35 billion for the Prairie Island
nuclear plant site and $2.15 billion for the Monticello nuclear plant site.
The Prairie Island coverage consists of $950 million from American Nuclear
Insurers/ Mutual Atomic Energy Liability Underwriters (ANI/MAELU) and $1.4
billion from Nuclear Electric Insurance Limited (NEIL). The Monticello
coverage consists of $750 million from ANI/MAELU and $1.4 billion from NEIL.
Under the insuring agreement with NEIL, the Company is subject to assessments
of up to $23.3 million in each calendar year, 7.5 times the amount of its
annual premium.
NEIL also provides insurance coverage for increased costs of generation
and purchased power resulting from an accidental outage of a nuclear
generating unit. Under the policy, the Company is subject to assessments of
up to $6.7 million in each calendar year, five times the amount of its annual
premium.
Environmental Contingencies - Other long-term liabilities include an accrual
of $48 million at Dec. 31, 1993, for estimated costs associated with
environmental reclamation, restoration and cleanup activities. Approximately
$40 million of the liability relates to a 1993 DOE assessment as discussed
in Note 8 to the Financial Statements. 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 decommissioning costs related
to the Company's nuclear generating plants. Consistent with predominant
industry practice, the Company's decommissioning accruals are included in
Utility Plant-Accumulated Depreciation as discussed in Note 1 of the
Financial Statements. The FERC, the FASB and the SEC currently are reviewing
the accounting and reporting guidelines for decommissioning cost accruals.
Until such guidelines require a different presentation, the Company plans to
continue its current reporting of plant decommissioning obligations as
accumulated depreciation.
NSP has not developed any specific site restoration and exit plans for
its fossil fuel plants, hydroelectric plants or substation sites as it
currently intends to operate at these sites indefinitely. If such plans were
developed in the future, NSP would intend to treat the costs as a removal
cost of retirement and include it in depreciation expense.
(See Note 1 for discussion of NSP's pre-funding of the federal nuclear
fuel disposal program.)
NSP has met or exceeded the removal and disposal requirements for
polychlorinated biphenyls (PCB) equipment as required by state and federal
regulations. NSP has removed nearly all PCB capacitors, transformers and
equipment from its distribution system and power plants. Any future cleanup
or remediation costs for past PCB disposal is unknown at this time. Minimal
costs are expected to be incurred for future removal and disposal of PCB
equipment. PCB-contaminated mineral oil is detoxified and beneficially reused
or burned for energy recovery at a permitted facility.
The Company has been designated by the Environmental Protection Agency
(EPA) as a "potentially responsible party" (PRP) for eight waste disposal
sites to which the Company sent materials. Under applicable law, the Company,
along with each PRP, could be held jointly and severally liable for the total
remediation costs of all eight sites, which are estimated to approximate $85
million. However, the amount could be in excess of $85 million. The Company
is not aware of the other parties' inability to pay or if responsibility for
any of the sites is disputed by any party. The Company's share of the costs
associated with these eight sites is approximately $2.5 million. Of this
amount, about $1.4 million has already been paid in connection with two of
the eight sites for which the Company has settled with the EPA and other
PRPs. For the remaining six sites, neither the amount of cleanup costs nor
the final method of their allocation among all designated PRPs has been
determined. However, the Company has recorded an estimate of future costs of
approximately $1 million for all six sites. While it is not feasible to
determine the outcome of these matters, amounts accrued represent the best
current estimate of the Company's future liability for the cleanup costs of
these sites. It is the Company's practice to vigorously pursue and, if
necessary, litigate with insurers to recover costs. Through litigation, the
Company has recovered from other PRPs a portion of the remedial costs paid
to date. Management believes costs incurred in connection with the sites,
which are not recovered from insurance carriers or other parties, might be
allowed recovery in future ratemaking. Until the Company is identified as a
PRP, it is not possible for the Company to predict the timing or amount of
any costs associated with cleanup sites other than those discussed above.
The Wisconsin Company has been notified by a group of PRPs for possible
responsibility for cleanup of a solid and hazardous waste landfill site. The
Wisconsin Company contends that it did not dispose of hazardous wastes in the
subject landfill during the time period in question. Because neither the
amount of cleanup costs nor the final method of their allocation among all
designated PRPs has been determined, it is not feasible to determine the
outcome of this matter at this time.
The Company also is continuing to investigate 14 properties either
presently or previously owned by the Company, which were at one time sites
of gas manufacturing, gas storage plants or gas pipelines. The purpose of
this investigation is to determine if waste materials are present, if such
materials constitute an environmental or health risk, if the Company has any
responsibility for remedial action and if recovery under the Company's
insurance policies can contribute to any remediation costs. Of the 14 gas
sites under investigation, the Company has already remediated one site and
is actively taking remedial action at four of the sites. The Company has paid
$3.1 million to date on these sites. The one remediated site continues to be
monitored. The Company currently estimates its liability for these four sites
to be approximately $5 million with payment expected over the next one to
five years. The estimate is based on prior experience and includes
investigation, remediation and litigation costs. The possible range of the
liability for these four sites could be from $5 million to approximately $11
million, depending on the extent of contamination. As for the other nine
sites, the Company currently estimates its liability to be approximately $2
million. This estimate assumes the development and remediation of one site
with the remaining eight sites requiring only monitoring. The time frame for
payment of these costs currently is undeterminable. While it is not feasible
to determine the precise outcome of all of these matters, the accruals
recorded represent the current best estimate of the costs of any required
cleanup or remedial actions at the Company's former gas operating sites.
Management also believes that costs incurred in connection with the sites,
which are not recovered from insurance carriers or other parties, might be
allowed recovery in future ratemaking.
The Clean Air Act, including the Amendments of 1990 (the Clean Air Act),
imposes stringent limits on emissions of sulfur dioxide and nitrogen oxides
by electric utility generating plants. The legislation enacted in 1990 is
extremely complex and its overall financial impact on NSP will depend on the
final interpretation and implementation of rules to be issued by the EPA. NSP
is participating in the rulemaking process for the development of regulations
that achieve the goals of the legislation in a reasonable and cost-effective
manner. NSP has expended significant funds over the years to reduce sulfur
dioxide emissions at its plants. Additional construction expenditures may be
required to comply with parts of the Clean Air Act. Based on revised emission
standards proposed by the EPA in 1993, NSP's excess emission allowances
available under the Clean Air Act may be significantly reduced. Because NSP
is only beginning to implement some provisions of the Clean Air Act, its
overall financial impact is unknown at this time. The majority of NSP's power
plants meet state and federal limits for opacity and air quality. Capital
expenditures will be required for opacity compliance in 1994-1998 at certain
facilities, and such costs are considered in the capital expenditure
commitments disclosed previously. NSP plans to seek recovery of these
expenditures in future rate proceedings.
In October 1992, the Company disclosed to the Minnesota Pollution
Control Agency, the EPA and the Nuclear Regulatory Commission that reports
on halogen content of water discharged at the Company's Prairie Island
nuclear generating plant were based on estimates of halogen content rather
than actual physical samples of water discharged as required by the plant's
permit. Even though the water discharges at the plant did not exceed the
halogen levels allowed under the permit, the applicable state and federal
statutes would permit the imposition of fines, the institution of criminal
sanctions and/or injunctive relief for the reporting violations. Corrective
actions were taken by the Company, and the Company cooperated with state and
federal authorities in the investigation of the reporting violations. No
civil or criminal actions against the Company have been announced.
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. On July 22, 1993, a natural gas
explosion occurred on the Company's distribution system in St. Paul, Minn.
Total damages are estimated to exceed $1 million. The Company has a
self-insured retention deductible of $1 million, with general liability
coverage of $150 million, which includes coverage for all injuries and
damages. While four lawsuits have been filed, the litigation following this
incident is in a preliminary stage and the ultimate costs to the Company are
unknown at this time.
Operating Contingency - The Company is experiencing uncertainty regarding its
ability to store used nuclear fuel from its Prairie Island nuclear generating
facility. The facility stores its used nuclear fuel on an interim basis in
a storage pool in the plant, pending the availability of a U.S. Department
of Energy high-level radioactive waste storage or permanent disposal
facility, or a private interim storage facility. At current operating levels,
the pool will be filled in 1994 so the Company has proposed to augment
Prairie Island's interim storage capacity by using steel containers for dry
storage of used nuclear fuel on the plant site. Without additional onsite
storage or significant modification of normal plant operations, Prairie
Island Unit 2 would be shutdown in May 1995 and Prairie Island Unit 1 would
be shutdown in February 1996. These two units supply about 20 percent of the
Company's output. The Company has obtained a Certificate of Need from the
MPUC allowing use of a limited number of steel containers, providing adequate
storage at least through the year 2001. The Nuclear Regulatory Commission has
also issued a license approving a dry storage facility on the plant site for
Prairie Island's used fuel. However, in June 1993, the Minnesota Court of
Appeals decided that the additional temporary storage facilities must be
approved by the Minnesota Legislature. The Company has requested such
approval from the Legislature and expects a decision on this issue during the
current session, which began on Feb. 22, 1994. Although hearings have begun,
the Company cannot predict what action the Minnesota Legislature will take.
The Company's net investment in the Prairie Island generating facility
at Dec. 31, 1993, was $520 million. Future plant decommissioning costs in
excess of amounts not accrued and collected in rates were $247 million at
Dec. 31, 1993. Should the facility need to be shut down due to the full
utilization of spent fuel storage capacity, the Company would request
recovery of, and a return on, its investment and unrecorded plant
decommissioning costs through utility rates. However, at this time the
regulators' ultimate response to such a request is unknown. Without the
generating capability of the Prairie Island facility, the Company estimates
that an incremental increase in purchased power and fuel expenses of at least
$200 million per year could be incurred. To the extent such additional costs
represent energy purchases, current rate treatment provides recovery through
cost-of-energy adjustments to customer rates. The Company will request
recovery of costs associated with additional capacity purchases or
investments in new plants through general rate filings. However, at this time
the need for such costs and the regulators' ultimate response to such a
request is unknown. The Company estimates that the present value of the cost
of supplying replacement power and recovering its investment in the plant and
unrecognized decommissioning costs will be $1.8 billion.
16. Segment Information
Year Ended Dec. 31
(Thousands of dollars) 1993 1992 1991
Utility operating revenues
Electric $1 974 916 $1 823 316 $1 863 238
Gas 429 076 336 206 337 920
Total operating revenues $2 403 992 $2 159 522 $2 201 158
Utility operating income before
income taxes*
Electric $393 758 $321 837 $383 049
Gas 38 474 24 848 39 748
Total operating income
before income taxes $432 232 $346 685 $422 797
Utility depreciation and amortization
Electric $245 200 $225 134 $217 625
Gas 19 317 17 780 16 538
Total depreciation and
amortization $264 517 $242 914 $234 163
Capital expenditures
Electric $284 239 $367 522 $290 793
Gas 36 312 42 850 32 576
Other 41 144 17 443 26 493
Total capital expenditures $361 695 $427 815 $349 862
Net utility plant
Electric $3 834 131 $3 812 688 $3 709 811
Gas 379 968 313 002 287 167
Total net utility plant 4 214 099 4 125 690 3 996 978
Other corporate assets 1 373 619 1 016 771 921 860
Total assets $5 587 718 $5 142 461 $4 918 838
*1992 amounts include an increase from the operating income impact of the
1992 change in accounting for revenues of $9.6 million for electric and $6.8
million for gas.
<TABLE>
17. Summarized Quarterly Financial Data (Unaudited)
<CAPTION>
Quarter Ended
(Thousands of dollars) March 31, 1993 June 30, 1993 Sept. 30, 1993(1) Dec. 31, 1993
<S> <C> <C> <C> <C>
Utility operating revenues $640 753 $545 263 $601 924 $616 052
Utility operating income 81 046 59 547 90 076 73 217
Net income 54 481 35 892 67 655 53 712
Earnings available for common stock 50 679 32 149 63 912 50 420
Earnings per common share $.81 $.50 $.96 $.75
Dividends declared per common share $.630 $.645 $.645 $.645
Stock prices - high $47 $46 7/8 $47 7/8 $46 3/8
- low $42 1/4 $42 7/8 $44 3/4 $40 1/8
Quarter Ended
(Thousands of dollars) March 31, 1992(2) June 30, 1992 Sept. 30, 1992 Dec. 31, 1992
Utility operating revenues $563 763 $500 251 $523 375 $572 133
Utility operating income 66 552 53 827 76 586 59 051
Income before accounting change 44 268 31 079 55 698 29 883
Net income 89 780 31 079 55 698 29 883
Earnings available for common stock 85 352 26 999 51 817 26 100
Earnings per common share:
Income before accounting change $.63 $.43 $.83 $.42*
Net income $1.36 $.43 $.83 $.42*
Dividends declared per common share $.605 $.630 $.630 $.630
Stock prices - high $43 $42 $45 5/8 $45 3/8
- low $39 1/4 $38 1/2 $41 $41 5/8
(1) The amounts for the third quarter of 1993 have been restated
to reflect the impact on the first three quarters of revenue
and expense adjustments based on the final 1993 Minnesota retail
electric rate order. Retail electric revenues increased by $13.9
million and net income increased by $7.8 million. The restatement
increased earnings per share by 12 cents. The impact on the first
and second quarters of 1993 was immaterial (an increase of 3 cents)
and was recorded entirely in the third quarter of 1993.
(2) Net income includes cumulative effect of change in accounting for
unbilled revenues of $45.5 million, or 73 cents per share.
*Includes writedowns and losses from non-regulated projects of
approximately 6 cents per share.
</TABLE>
Item 9 - Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
During 1993 there were no changes in or 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 1994 Proxy Statement for its Annual Meeting of
Shareholders to be held April 27, 1994 on pages 2 through 7 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
1994 Proxy Statement for its Annual Meeting of Shareholders to be held April
27, 1994 on pages 8 through 20 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
1994 Proxy Statement for its Annual Meeting of Shareholders to be held April
27, 1994 on page 7 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
1994 Proxy Statement for its Annual Meeting of Shareholders to be held April
27, 1994 on pages 3 through 5 under the captions "Class I - Directors Whose
Terms Expire in 1996", "Class II - Nominees for Terms Expiring in 1997",
"Class III - Directors Whose Terms, Expire in 1995", which is incorporated
herein by reference.
PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports on
Form 8-K
(a) 1. Financial Statements
Included in Part II of this report:
Independent Auditors' Report.
Consolidated Statements of Income for the three years ended
December 31, 1993.
Consolidated Statements of Cash Flows for the three years
ended December 31, 1993.
Consolidated Balance Sheets, December 31, 1993 and 1992.
Consolidated Statements of Changes in Common
Stockholders' Equity for the three years ended
December 31, 1993
Consolidated Statements of Capitalization,
December 31, 1993 and 1992.
Notes to Financial Statements.
(a) 2. Financial Statement Schedules
Included in Part IV of this report:
Schedules for the three years ended December 31, 1993:
V - Utility Plant and Non-regulated Property
VI - Accumulated Provision for Depreciation and
Amortization of Utility Plant and Non-regulated
Property.
Notes to Schedules V and VI.
IX - Short-Term Borrowings
X - Supplementary Income Statement Information
Schedules other than those listed above 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 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 January 22, 1992. (Exhibit
3.02 to Form 10-K for the year 1991, File No. 1-3034).
4.01* Trust Indenture, dated February 1, 1937, from the Company to
Harris Trust and Savings Bank, as Trustee. (Exhibit B-7 to
File No. 2-5290).
4.02* Supplemental and Restated Trust Indenture, dated May 1, 1988,
from the Company to Harris Trust and Savings Bank, as Trustee.
(Exhibit 4.02 to Form 10-K for the year 1988, File No. 1-3034).
Supplemental Indenture between the Company and said Trustee,
supplemental to Exhibit 4.01, dated as follows:
4.03* Jun. 1, 1942 (Exhibit B-8 to File No. 2-97667).
4.04* Feb. 1, 1944 (Exhibit B-9 to File No. 2-5290).
4.05* Oct. 1, 1945 (Exhibit 7.09 to File No. 2-5924).
4.06* Jul. 1, 1948 (Exhibit 7.05 to File No. 2-7549).
4.07* Aug. 1, 1949 (Exhibit 7.06 to File No. 2-8047).
4.08* Jun. 1, 1952 (Exhibit 4.08 to File No. 2-9631).
4.09* Oct. 1, 1954 (Exhibit 4.10 to File No. 2-12216).
4.10* Sep. 1, 1956 (Exhibit 2.09 to File No. 2-13463).
4.11* Aug. 1, 1957 (Exhibit 2.10 to File No. 2-14156).
4.12* Jul. 1, 1958 (Exhibit 4.12 to File No. 2-15220).
4.13* Dec. 1, 1960 (Exhibit 2.12 to File No. 2-18355).
4.14* Aug. 1, 1961 (Exhibit 2.13 to File No. 2-20282).
4.15* Jun. 1, 1962 (Exhibit 2.14 to File No. 2-21601).
4.16* Sep. 1, 1963 (Exhibit 4.16 to File No. 2-22476).
4.17* Aug. 1, 1966 (Exhibit 2.16 to File No. 2-26338).
4.18* Jun. 1, 1967 (Exhibit 2.17 to File No. 2-27117).
4.19* Oct. 1, 1967 (Exhibit 2.01R to File No. 2-28447).
4.20* May 1, 1968 (Exhibit 2.01S to File No. 2-34250).
4.21* Oct. 1, 1969 (Exhibit 2.01T to File No. 2-36693).
4.22* Feb. 1, 1971 (Exhibit 2.01U to File No. 2-39144).
4.23* May 1, 1971 (Exhibit 2.01V to File No. 2-39815).
4.24* Feb. 1, 1972 (Exhibit 2.01W to File No. 2-42598).
4.25* Jan. 1, 1973 (Exhibit 2.01X to File No. 2-46434).
4.26* Jan. 1, 1974 (Exhibit 2.01Y to File No. 2-53235).
4.27* Sep. 1, 1974 (Exhibit 2.01Z to File No. 2-53235).
4.28* Apr. 1, 1975 (Exhibit 4.01AA to File No. 2-71259).
4.29* May 1, 1975 (Exhibit 4.01BB to File No. 2-71259).
4.30* Mar. 1, 1976 (Exhibit 4.01CC to File No. 2-71259).
4.31* Jun. 1, 1981 (Exhibit 4.01DD to File No. 2-71259).
4.32* Dec. 1, 1981 (Exhibit 4.01EE to File No. 2-83364).
4.33* May 1, 1983 (Exhibit 4.01FF to File No. 2-97667).
4.34* Dec. 1, 1983 (Exhibit 4.01GG to File No. 2-97667).
4.35* Sep. 1, 1984 (Exhibit 4.01HH to File No. 2-97667).
4.36* Dec. 1, 1984 (Exhibit 4.01II to File No. 2-97667).
4.37* May 1, 1985 (Exhibit 4.36 to Form 10-K for the year 1985,
File No. 1-3034).
4.38* Sep. 1, 1985 (Exhibit 4.37 to Form 10-K for the year 1985,
File No. 1-3034).
4.39* Jul. 1, 1989 (Exhibit 4.01 to Form 8-K dated July 7, 1989,
File No. 1-3034).
4.40* Jun. 1, 1990 (Exhibit 4.01 to Form 8-K dated June 1, 1990,
File No. 1-3034).
4.41* Oct. 1, 1992 (Exhibit 4.01 to Form 8-K dated October 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 December 7,
1993, File No. 1-3034).
4.44* Feb. 1, 1994 (Exhibit 4.01 to Form 8-K dated February 10,
1994, File No. 1-3034).
4.45* Trust Indenture, dated April 1, 1947, from the Wisconsin
Company to Firstar Trust Company (formerly First Wisconsin
Trust Company), as Trustee. (Exhibit 7.01 to File No. 2-
6982).
Supplemental Indentures between the Wisconsin Company and said
Trustee, supplemental to Exhibit 4.45 dated as follows:
4.46* Mar. 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.47* Jun. 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.48* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.49* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693).
4.50* Sep. 1, 1973 (Exhibit 2.01F to File No. 2-48805).
4.51* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146).
4.52* Mar. 1, 1982 (Exhibit 4.39 to Form 10-K for the year 1982,
File No. 10-3140).
4.53* Jun. 1, 1986 (Exhibit 4.01I to File No. 33-6269).
4.54* Mar. 1, 1988 (Exhibit 4.01J to File No. 33-20415).
4.55* 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)
4.56* Apr. 1, 1991 (Exhibit 4.01L to File No. 33-39831).
4.57* Mar. 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4, 1993,
File No. 10-3140).
4.58* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21,
1993, File No. 10-3140).
10.01* Mid-continent Area Power Pool (MAPP) Agreement, dated March
31, 1972, between the local power suppliers in the North
Central States area. (Exhibit 5.06B to File No. 2-44530).
10.02* Facilities agreement, dated July 21, 1976, between the Company
and the Manitoba Hydro-Electric Board relating to the
interconnection of the 500 Kv Line. (Exhibit 5.06I to file
No. 2-54310).
10.03* Transactions agreement, dated July 21, 1976, between the
Company and the Manitoba Hydro-Electric Board relating to the
interconnection of the 500 Kv Line. (Exhibit 5.06J to File
No. 2-54310).
10.04* Co-ordinating agreement, dated July 21, 1976, between the
Company and the Manitoba Hydro-Electric Board relating to the
interconnection of the 500 Kv Line. (Exhibit 5.06K to File
No. 2-54310).
10.05* Ownership and Operating Agreement, dated March 11, 1982,
between the Company, Southern Minnesota Municipal Power Agency
and United Minnesota Municipal Power Agency concerning
Sherburne County Generating Unit No. 3. (Exhibit 10.35 to
Form 10-K for the Year 1982, File No. 1-3034).
10.06* Transmission agreement, dated April 27, 1982, and Supplement
No. 1, dated July 20, 1982, between the Company and Southern
Minnesota Municipal Power Agency. (Exhibit 10.40 to Form 10-K
for the Year 1982, File No. 1-3034).
10.07* Power agreement, dated June 14, 1984, between the Company and
the Manitoba Hydro-Electric Board, extending the agreement
scheduled to terminate on April 30, 1993, to April 30, 2005.
(Exhibit 10.45 to Form 10-K for the Year 1984, File No. 1-3034).
10.08* Power Agreement, dated August 1988, between the Company and
Minnkota Power Company. (Exhibit 10.08 to Form 10-K for the
Year 1988, File No. 1-3034).
10.09 Energy Supply Agreement, dated October 26, 1993, between the
Company and Liberty Paper, Inc., relating to the supply of
steam and electricity to the LPI container-board facility in
Becker, MN.
Executive Compensation Arrangements and Benefit Plans Covering
Executive Officers
10.10* Executive Long-Term Incentive Award Stock Plan. (Exhibit
10.10 to Form 10-K for 1988, File No. 1-3034).
10.11* Terms and Conditions of Employment - James J Howard, President
and Chief Executive Officer, effective February 1, 1987.
(Exhibit 10.11 to Form 10-K for the Year 1986, File No. 1-3034).
10.12* NSP Severance Plan (Exhibit 10.14 to Form 10-K for the Year
1992, File No. 1-3034).
10.13* NSP Pension Plan (Exhibit 10.15 to Form 10-K for the Year
1992, File No. 1-3034).
10.14* NSP Employee Stock Ownership Plan (Exhibit 4.03, 4.04, 4.05
and 4.06 to Post-effective Amendment No. 5 to File No. 2-
61264).
10.15* NSP Retirement Savings Plan (Exhibit 10.17 to Form 10-K for
the Year 1992, File No. 1-3034).
10.16 NSP Deferred Compensation Plan amended effective January 1,
1993.
12.01 Statement of Computation of Ratio of Earnings to Fixed
Charges.
18.01* Independent Auditors' Preferability Letter. (Exhibit 18.01 to
Form 10-Q for the quarter ended March 31, 1992, File No. 1-3034).
21.01 Subsidiaries of the Registrant.
23.01 Independent Auditors' Consent.
(b) Reports on Form 8-K. The following reports on Form 8-K were filed
either during the three months ended December 31, 1993, or between
December 31, 1993 and the date of this report:
October 1, 1993 (Filed October 8, 1993) - Item 5. Other Events.
Re: Disclosure of the purchase of certain assets of Centran
Corporation, a natural gas marketing company, by a non-regulated
subsidiary of the Company.
December 7, 1993 (Filed December 9, 1993) - Item 5. Other Events.
Re: Disclosure of Underwriting Agreement and filing of a
prospectus supplement relating to $170,000,000 First Mortgage Bonds
($100,000,000, Series due December 1, 2000) ($70,000,000, Series
due December 1, 2005). Item 7. -Financial Statements and Exhibits.
Filing of Underwriting Agreement between the Company and various
underwriters, Supplemental Trust Indenture between the Company and
Harris Trust and Savings Bank, as trustee, creating First Mortgage
Bonds, Series due December 1, 2000 and Series Due December 1, 2005,
and the computation of ratio of earnings to fixed charges.
December 10, 1993 (Filed December 27, 1993) - Item 5. Other
Events. Re: Disclosure of a partnership agreement, in which a
non-regulated subsidiary of the Company is a party of, to purchase
a 400-megawatt share of the 900-megawatt Schkopau power plant near
Leipzig, Germany. Disclosure of a partnership agreement, in which
a non-regulated subsidiary of the Company is a party of, to acquire
a portion of the mining, power generation and associated operations
of the former state-owned, Mitleldeutsche Vereinigte
Braunkohlenwerke Aktiengesellschaft.
January 31, 1994 (Filed February 9, 1994) - Item 5. Other Events.
Re: Disclosure of an appeal filed with the Minnesota Court of
Appeals by rate case intervenors concerning the method of
calculating the rate of return on common equity. Disclosure that
the Company has been named as a potentially responsible party at
a Superfund site. Disclosure of the Company's Unaudited
Consolidated Financial Statements for 1993. Item 7. Financial
Statements, Pro Forma Financial Information and Exhibits. Filing
of the Company's Unaudited Financial Statements for 1993.
February 10, 1994 (Filed February 14, 1994) - Item 5. Other
Events. Re: Disclosure of Underwriting Agreement and filing of
a prospectus supplement relating to $200,000,000 First Mortgage
Bonds, Series due February 1, 1999. Item 7. Financial Statements
and Exhibits. Filing of Underwriting Agreement between the Company
and various underwriters, Supplemental Trust Indenture between the
Company and Harris Trust and Savings Bank, as trustee, creating
First Mortgage Bonds due February 1, 1999, and the computation of
ratio of earnings to fixed charges.
March 15, 1994 (Filed March 16, 1994) - Item 5. Other Events. Re:
Disclosure of the results of Minnesota State Legislative Committee
votes on the Company's plan to store additional spent nuclear fuel
at its Prairie Island Nuclear Generating Plant. Disclosure of the
International Brotherhood of Electrical Workers rejection of NSP's
contract offer and the continuation of negotiations.
<TABLE>
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE V
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1993
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
BALANCE RETIREMENTS OR OTHER CHANGES AND BALANCE
AT ADDITIONS SALES AT ORIGINAL RECLASSIFICATIONS AT
BEGINNING AT COST. ESTIMATED ADD OR (DEDUCT) END OF
CLASSIFICATION OF PERIOD COST IF NOT KNOWN (Note 1) PERIOD
(Thousands of dollars)
<S> <C> <C> <C> <C> <C>
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $1,677,945 $11,173 $2,733 $3 $1,686,388
Nuclear production 1,289,624 27,703 4,870 (47) 1,312,410
Hydraulic production 184,807 1,594 34 6 186,373
Other production plant 120,104 3,271 1,068 (4) 122,303
Transmission 719,971 62,555 2,838 (276) 779,412
Distribution 1,628,430 106,297 18,923 (1,336) 1,714,468
General 181,316 7,239 3,771 6 184,790
Electric plant held for future use 828 0 0 (70) 758
Plant acquisition adjustment 15 222 0 0 237
Leased to others 5,399 17 4 0 5,412
Electric plant under capital leases 696 0 471 0 225
Construction work in progress 147,730 27,130 0 34 174,894
Total 5,956,865 247,201 34,712 (1,684) 6,167,670
Gas:
Gas plant in service:
Production 11,414 1,102 0 (1) 12,515
Storage 26,777 599 0 1 27,377
Transmission 22,903 76,344 9 (33) 99,205
Distribution 399,742 32,167 3,263 (2,776) 425,870
General 12,107 4,840 435 73 16,585
Construction work in progress 8,214 1,011 0 0 9,225
Gas plant held for future use 0 0 0 0 0
Gas plant acquisition adjmnt 0 31,094 0 0 31,094
Total 481,157 147,157 3,707 (2,736) 621,871
Common 199,912 41,939 4,526 (32) 237,293
Total 6,637,934 436,297 42,945 (4,452) 7,026,834
Nuclear Fuel:
Stock Account 0 51,928 0 (51,928) 0
Assemblies in reactor 192,892 0 0 11,301 204,193
Spent Fuel 488,900 0 0 40,627 529,527
In process 29,725 (14,366) 0 (1) 15,358
Total 711,517 37,562 0 (1) 749,078
Total Utility 7,349,451 473,859 42,945 (4,453) 7,775,912
Telephone 0 0 0 0 0
NON-REGULATED PROPERTY 148,974 71,027 658 631 219,974
TOTAL $7,498,425 $544,886 $43,603 ($3,822) $7,995,886
( ) Denotes negative.
SEE NOTES TO SCHEDULES V AND VI
</TABLE>
<TABLE>
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE V
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1992
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
BALANCE RETIREMENTS OR OTHER CHANGES AND BALANCE
AT ADDITIONS SALES AT ORIGINAL RECLASSIFICATIONS AT
BEGINNING AT COST. ESTIMATED ADD OR (DEDUCT) END OF
CLASSIFICATION OF PERIOD COST IF NOT KNOWN (Note 1) PERIOD
(Thousands of dollars)
<S> <C> <C> <C> <C> <C>
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $1,655,308 $25,003 $2,544 $178 $1,677,945
Nuclear production 1,142,411 154,020 7,410 603 1,289,624
Hydraulic production 180,438 4,424 42 (13) 184,807
Other production plant 117,006 3,989 893 2 120,104
Transmission 695,404 31,527 6,067 (893) 719,971
Distribution 1,527,518 120,160 19,483 235 1,628,430
General 175,197 10,036 3,320 (597) 181,316
Electric plant held for future use 891 7 1 (69) 828
Plant acquisition adjustment 15 0 0 0 15
Leased to others 5,360 39 0 0 5,399
Electric plant under capital leases 1,838 0 1,142 0 696
Construction work in progress 184,666 (36,160) 0 (776) 147,730
Total 5,686,052 313,045 40,902 (1,330) 5,956,865
Gas:
Gas plant in service:
Production 11,410 13 1 (8) 11,414
Storage 26,319 468 18 8 26,777
Transmission 16,650 6,557 304 0 22,903
Distribution 370,046 34,329 4,633 0 399,742
General 12,216 731 929 89 12,107
Construction work in progress 10,805 (2,697) 0 106 8,214
Gas plant held for future use 0 0 0 0 0
Total 447,446 39,401 5,885 195 481,157
Common 177,680 22,912 1,686 1,006 199,912
Total 6,311,178 375,358 48,473 (129) 6,637,934
Nuclear Fuel:
Stock Account 818 44,607 0 (45,425) 0
Assemblies in reactor 190,331 0 0 2,561 192,892
Spent Fuel 446,036 0 0 42,864 488,900
In process 30,658 (933) 0 0 29,725
Total 667,843 43,674 0 0 711,517
Total Utility 6,979,021 419,032 48,473 (129) 7,349,451
Telephone 0 0 0 0 0
NON-REGULATED PROPERTY 145,594 3,734 354 0 148,974
TOTAL $7,124,615 $422,766 $48,827 ($129) $7,498,425
( ) Denotes negative.
SEE NOTES TO SCHEDULES V AND VI
</TABLE>
<TABLE>
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE V
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1991
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
BALANCE RETIREMENTS OR OTHER CHANGES AND BALANCE
AT ADDITIONS SALES AT ORIGINAL RECLASSIFICATIONS AT
BEGINNING AT COST. ESTIMATED ADD OR (DEDUCT) END OF
CLASSIFICATION OF PERIOD COST IF NOT KNOWN (Note 1) PERIOD
(Thousands of dollars)
<S> <C> <C> <C> <C> <C>
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $1,634,120 $32,186 $6,400 ($4,598) $1,655,308
Nuclear production 1,141,906 21,661 19,634 (1,522) 1,142,411
Hydraulic production 180,135 2,420 2,124 7 180,438
Other production plant 117,172 139 307 2 117,006
Transmission 673,987 24,055 2,405 (233) 695,404
Distribution 1,448,360 93,029 14,261 390 1,527,518
General 170,064 7,826 3,153 460 175,197
Electric plant held for future use 1,068 3 0 (180) 891
Plant acquisition adjustment 15 0 0 0 15
Leased to others 5,360 0 0 0 5,360
Electric plant under capital leases 3,829 0 1,991 0 1,838
Construction work in progress 138,903 45,763 0 0 184,666
Total 5,514,919 227,082 50,275 (5,674) 5,686,052
Gas:
Gas plant in service:
Production 11,280 131 1 0 11,410
Storage 26,034 285 0 0 26,319
Transmission 16,406 437 192 (1) 16,650
Distribution 346,504 26,531 3,074 85 370,046
General 12,316 488 545 (43) 12,216
Construction work in progress 8,379 2,426 0 0 10,805
Gas plant held for future use 0 0 0 0 0
Total 420,919 30,298 3,812 41 447,446
Common 155,108 26,200 3,005 (623) 177,680
Total 6,090,946 283,580 57,092 (6,256) 6,311,178
Nuclear Fuel:
Stock Account 1,227 43,781 0 (44,190) 818
Assemblies in reactor 191,977 0 0 (1,646) 190,331
Spent Fuel 400,200 0 0 45,836 446,036
In process 18,680 11,978 0 0 30,658
Total 612,084 55,759 0 0 667,843
Total Utility 6,703,030 339,339 57,092 (6,256) 6,979,021
Telephone 29,429 (972) 28,457 0 0
NON-REGULATED PROPERTY 151,179 6,955 12,515 (25) 145,594
TOTAL $6,883,638 $345,322 $98,064 ($6,281) $7,124,615
( ) Denotes negative.
SEE NOTES TO SCHEDULES V AND VI
</TABLE>
<TABLE>
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE VI
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1993
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
DEPRECIATION AND OTHER CHANGES
BALANCE AMORTIZATION CHARGED TO DEDUCTIONS AND
AT CLEARING RECLASSIFICATIONS
BEGINNING AND OTHER PROPERTY NET ADD OR (DEDUCT)
DESCRIPTION OF PERIOD INCOME ACCOUNTS RETIRED SALVAGE (NOTE 2)
<S> <C> <C> <C> <C> <C> <C>
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $632,979 $57,323 $0 $2,733 $357 ($16)
Nuclear production 705,641 86,601 0 4,870 (3,614) (25)
Hydraulic production 38,322 4,222 0 34 72 5
Other production plant 95,121 4,399 0 1,068 5 3
Transmission 234,503 19,930 0 2,806 142 1,851
Distribution 537,507 52,762 2,184 18,261 2,561 (1,064)
General 69,946 7,673 3,727 3,766 (364) (234)
Leased to others 1,697 104 0 4 3 0
Retirement work in progress (5,209) 0 0 0 (1,289) 0
Total 2,310,507 233,014 5,911 33,542 (2,127) 520
Gas:
Gas plant in service:
Production 6,910 230 0 0 0 0
Storage 15,088 1,065 0 0 0 0
Transmission 9,164 1,274 0 291 (156) 63,069
Distribution 147,907 14,881 0 3,462 989 (2,778)
General 4,451 393 510 435 (31) 2,009
Plant acquisition adjustment 0 1,118 0 0 0 0
Retirement work in progress (585) 0 0 0 (462) 0
Total 182,935 18,961 510 4,188 340 62,300
Common 80,252 10,454 361 4,332 5 256
Total 2,573,694 262,429 6,782 42,062 (1,782) 63,076
Limited-term Investments 19,519 2,924 0 0 0 0
Total 2,593,213 265,353 6,782 42,062 (1,782) 63,076
Nuclear fuel assemblies 630,548 43,121 0 0 0 0
NON-REGULATED PROPERTY 54,669 8,945 0 343 4 0
Telephone 0 0 0 0 0 0
TOTAL $3,278,430 $317,419 $6,782 $42,405 ($1,778) $63,076
COLUMN F
BALANCE
AT
END OF
DESCRIPTION PERIOD
<S> <C>
UTILITY PLANT:
Electric:
Electric plant in service
Steam production $687,196
Nuclear production 790,961
Hydraulic production 42,443
Other production plant 98,450
Transmission 253,336
Distribution 570,567
General 77,710
Leased to others 1,794
Retirement work in progress (3,920)
Total 2,518,537
Gas:
Gas plant in service:
Production 7,140
Storage 16,153
Transmission 73,372
Distribution 155,559
General 6,959
Plant acquisition adjustments 1,118
Retirement work in progress (123)
Total 260,178
Common 86,986
Total 2,865,701
Limited-term Investments 22,443
Total 2,888,144
Nuclear fuel assemblies 673,669
NON-REGULATED PROPERTY 63,267
Telephone 0
TOTAL $3,625,080
( ) Denotes negative.
SEE NOTES TO SCHEDULES V AND VI
</TABLE>
<TABLE>
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE VI
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1992
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
DEPRECIATION AND OTHER CHANGES
BALANCE AMORTIZATION CHARGED TO DEDUCTIONS AND
AT CLEARING RECLASSIFICATIONS
BEGINNING AND OTHER PROPERTY NET ADD OR (DEDUCT)
DESCRIPTION OF PERIOD INCOME ACCOUNTS RETIRED SALVAGE (NOTE 2)
(Thousands of dollars)
<S> <C> <C> <C> <C> <C> <C>
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $579,505 $56,074 $0 $2,520 $245 $165
Nuclear production 636,571 76,740 0 7,410 365 105
Hydraulic production 34,521 4,123 0 (53) 369 (6)
Other production plant 91,442 4,615 0 893 43 0
Transmission 224,830 17,268 0 5,607 1,380 (608)
Distribution 511,778 47,118 1,301 19,483 2,446 (761)
General 61,779 6,833 4,300 3,319 (527) (174)
Leased to others 965 103 0 0 0 629
Retirement work in progress (5,313) 0 0 0 (104) 0
Total 2,136,078 212,874 5,601 39,179 4,217 (650)
Gas:
Gas plant in service:
Production 6,619 292 0 1 0 0
Storage 14,124 982 0 18 0 0
Transmission 8,708 508 0 21 31 0
Distribution 139,738 14,101 0 4,434 1,498 0
General 4,375 257 566 929 (117) 65
Retirement work in progress (184) 0 0 0 401 0
Total 173,380 16,140 566 5,403 1,813 65
Common 70,088 4,599 7,085 1,502 (31) (49)
Total 2,379,546 233,613 13,252 46,084 5,999 (634)
Limited-term Investments 17,077 2,443 0 1 0 0
Total 2,396,623 236,056 13,252 46,085 5,999 (634)
Nuclear fuel assemblies 585,420 45,128 0 0 0 0
NON-REGULATED PROPERTY 47,920 6,749 0 0 0 0
Telephone 0 0 0 0 0 0
TOTAL $3,029,963 $287,933 $13,252 $46,085 $5,999 ($634)
COLUMN F
BALANCE
AT
END OF
DESCRIPTION PERIOD
<S> <C>
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $632,979
Nuclear production 705,641
Hydraulic production 38,322
Other production plant 95,121
Transmission 234,503
Distribution 537,507
General 69,946
Leased to others 1,697
Retirement work in progress (5,209)
Total 2,310,507
Gas:
Gas plant in service:
Production 6,910
Storage 15,088
Transmission 9,164
Distribution 147,907
General 4,451
Retirement work in progress (585)
Total 182,935
Common 80,252
Total 2,573,694
Limited-term Investments 19,519
Total 2,593,213
Nuclear fuel assemblies 630,548
NON-REGULATED PROPERTY 54,669
Telephone 0
TOTAL $3,278,430
( ) Denotes negative.
SEE NOTES TO SCHEDULES V AND VI
</TABLE>
<TABLE>
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE VI
ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1991
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
DEPRECIATION AND OTHER CHANGES
BALANCE AMORTIZATION CHARGED TO DEDUCTIONS AND
AT CLEARING RECLASSIFICATIONS
BEGINNING AND OTHER PROPERTY NET ADD OR (DEDUCT)
DESCRIPTION OF PERIOD INCOME ACCOUNTS RETIRED SALVAGE (NOTE 2)
(Thousands of dollars)
<S> <C> <C> <C> <C> <C> <C>
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $532,611 $53,975 $0 $6,398 $697 $14
Nuclear production 582,089 73,771 0 19,634 (345) 0
Hydraulic production 32,806 4,052 0 2,124 214 1
Other production plant 87,233 4,517 0 307 1 0
Transmission 209,625 16,719 0 2,071 (557) 0
Distribution 481,855 44,737 431 14,249 996 0
General 53,570 6,175 4,467 3,151 (398) 320
Leased to others 862 103 0 0 0 0
Retirement work in progress (6,455) 0 0 0 (1,142) 0
Total 1,974,196 204,049 4,898 47,934 (534) 335
Gas:
Gas plant in service:
Production 6,352 272 0 0 5 0
Storage 13,062 1,064 0 0 2 0
Transmission 8,259 495 0 192 (149) (3)
Distribution 130,784 13,077 0 3,227 983 87
General 4,021 224 599 545 (74) 2
Retirement work in progress (49) 0 0 0 135 0
Total 162,429 15,132 599 3,964 902 86
Common 60,094 7,128 6,198 3,005 (123) (450)
Total 2,196,719 226,309 11,695 54,903 245 (29)
Limited-term Investments 15,212 1,865 0 0 0 0
Total 2,211,931 228,174 11,695 54,903 245 (29)
Nuclear fuel assemblies 536,534 48,886 0 0 0 0
NON-REGULATED PROPERTY 41,264 6,767 0 111 0 0
Telephone 13,453 203 2 13,731 (73) 0
TOTAL $2,803,182 $284,030 $11,697 $68,745 $172 ($29)
COLUMN F
BALANCE
AT
END OF
DESCRIPTION PERIOD
<S> <C>
UTILITY PLANT:
Electric:
Electric plant in service:
Steam production $579,505
Nuclear production 636,571
Hydraulic production 34,521
Other production plant 91,442
Transmission 224,830
Distribution 511,778
General 61,779
Leased to others 965
Retirement work in progress (5,313)
Total 2,136,078
Gas:
Gas plant in service:
Production 6,619
Storage 14,124
Transmission 8,708
Distribution 139,738
General 4,375
Retirement work in progress (184)
Total 173,380
Common 70,088
Total 2,379,546
Limited-term Investments 17,077
Total 2,396,623
Nuclear fuel assemblies 585,420
NON-REGULATED PROPERTY 47,920
Telephone 0
TOTAL $3,029,963
( ) Denotes negative.
SEE NOTES TO SCHEDULES V AND VI
</TABLE>
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
NOTES TO SCHEDULES V AND VI
(Thousands of dollars)
For the year ended December 31, 1993:
1. Represents transfers and adjustments which were charged
to the following accounts:
Adjustment due to electric and gas meter inventory ($1 157)
Adjustment due to gas distribution main inventory (2 252)
Miscellaneous adjustments (413)
Total ($3 822)
2. Represents transfers and adjustments which were charged
to the following accounts:
Accumulated depreciation of Viking Gas utility
plant acquired $65 087
Adjustment due to gas distribution main inventory (2 252)
Miscellaneous adjustments 241
Total $63 076
For the year ended December 31, 1992:
1. Represents transfers and adjustments which were charged
to the following accounts:
Miscellaneous adjustments ($129)
2. Represents transfers and adjustments which were charged
to the following accounts:
Miscellaneous adjustments ($634)
For the year ended December 31, 1991:
1. Represents transfers and adjustments which were charged
to the following accounts:
Adjustment due to spare parts inventory ($6 130)
Miscellaneous adjustments (151)
Total ($6 281)
2. Represents transfers and adjustments which were charged
to the following accounts:
Miscellaneous adjustments ($29)
Depreciation is computed on the straight-line method based on estimated
useful lives of the various classes of property. Such provisions as a
percentage of the average balance of depreciable property in service were
3.47% in 1993, 3.36% in 1992 and 3.35% in 1991. Nuclear fuel is amortized
to fuel expense based on energy expended.
SCHEDULE IX
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
SHORT-TERM BORROWINGS FOR THE THREE YEARS ENDED DECEMBER 31, 1993
Primarily Commercial Paper
(Thousands of dollars)
1993 1992 1991
Balance at end of year $106 200 $146 561 $ 0
Weighted average interest rate
at end of year 3.3% 3.6% 0
Maximum month-end amount $172 280 $162 000 $ 0
outstanding during the year (1-31-93) (7-31-92)
Average amount outstanding
during the period (computed
on a daily basis) $ 76 966 $ 80 957 $390
Weighted average interest rate
during the year (computed
on a daily basis) 3.3% 3.6% 6.0%
SCHEDULE X
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE THREE YEARS ENDED DECEMBER 31, 1993
1993 1992 1991
(Thousands of dollars)
Taxes other than payroll and income taxes
charged to operating expenses:
Real and personal property $169 881 $154 060 $148 653
Gross earnings $26 292 $24 264 $24 787
Other $3 842 $3 620 $3 526
The amount of maintenance and depreciation charged to expense accounts other
than those set forth in the statement of income are not significant.
All other items are less than 1% of total revenues.
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 23, 1994 (E J McIntyre)
E J McIntyre
Vice President and Chief Financial
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report signed below by the following persons on behalf of the registrant
and in the capacities and on the date indicated.
(James J Howard) (E J McIntyre)
James J Howard E J McIntyre
Chairman of the Board and Director Vice President
(Principal Executive Officer) (Principal Financial Officer)
(Roger D Sandeen) (H Lyman Bretting)
Roger D Sandeen H Lyman Bretting
Vice President & Controller Director
(Principal Accounting Officer)
(David A Christensen) (W John Driscoll)
David A Christensen W John Driscoll
Director Director
(Dale L Haakenstad) (Allen F Jacobson)
Dale L Haakenstad Allen F Jacobson
Director Director
(Richard M Kovacevich) (Douglas W Leatherdale)
Richard M Kovacevich Douglas W Leatherdale
Director Director
(G M Pieschel) (Margaret R Preska)
G M Pieschel Margaret R Preska
Director Director
(A Patricia Sampson) (Edwin M Theisen)
A Patricia Sampson Edwin M Theisen
Director President and Director
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
DT 10.09 Energy Supply Agreement between the Company
and Liberty Paper, Inc.
DT 10.16 NSP Deferred Compensation Plan
DT 12.01 Statement of Computation of Ratio of
Earnings to Fixed Charges
DT 21.01 Subsidiaries of the Registrant
DT 23.01 Independent Auditors' Consent
DT = Filed electronically with this direct transmission.
AGREEMENT
BETWEEN
LIBERTY PAPER, INC.
AND
NORTHERN STATES POWER COMPANY
INDEX
Page
1. RECITALS 1
2. DEFINITIONS 2
3. SALE OF LAND 5
4. THERMAL ENERGY SUPPLY 8
5. ELECTRICITY SUPPLY 24
6. FIRE PROTECTION WATER SUPPLY 27
7. SOLID WASTE COMBUSTION 28
8. INDEMNITY 30
9. WARRANTIES AND REPRESENTATIONS 33
10. ARBITRATION 36
11. REMEDIES 39
12. EXTENSION AND RENEWAL 45
13. TERMINATION 45
14. MISCELLANEOUS 47
EXHIBIT A MAP SHOWING LOCATION OF TRACTS I AND II
EXHIBIT B STEAM SUPPLY SYSTEM DIAGRAM
EXHIBIT C CONDENSATE RETURN CHEMISTRY REQUIREMENTS
EXHIBIT D ELECTRIC SERVICE RATE SCHEDULE
EXHIBIT E SPECIFICATION FOR ACCEPTABLE SOLID WASTE
EXHIBIT F TERMINATION CHARGES FOR ELECTRICITY SUPPLY
AGREEMENT
This Agreement is between NORTHERN STATES POWER COMPANY ("NSP"), a
Minnesota corporation, and LIBERTY PAPER, INC. ("LPI"), a Minnesota
corporation.
1. RECITALS
1.1 NSP owns and operates a facility located in Sherburne County near
the City of Becker, Minnesota (herein referred to as "Sherburne County
Generating Plant"), which produces steam for the purpose of generating and
supplying electricity to NSP's customers. The primary fuel used to produce
steam at the Sherburne County Generating Plant is coal.
1.2 LPI intends to build, own and operate a facility adjacent to the
Sherburne County Generating Plant (herein referred to as "LPI facility"),
which will use steam and/or natural gas and electricity in the process of
recycling and manufacturing container board.
1.3 NSP desires to grant an option to LPI to purchase additional land
in the event LPI proposes to expand or add to the LPI facility, and LPI
desires an option for such land from NSP.
1.4 NSP desires to provide thermal energy for the LPI facility by means
of selling steam and/or natural gas, and LPI desires to purchase such steam
and/or natural gas from NSP.
1.5 NSP desires to sell electricity produced by its electrical system
to LPI and LPI desires to purchase such electricity from NSP.
1.6 LPI desires access to the fire protection water supply of the
Sherburne County Generating Plant for the protection of the LPI facility and
NSP is willing to provide access to this water supply to LPI.
1.7 LPI desires to have NSP accept the solid waste generated at the LPI
facility for use as fuel and NSP is willing to accept the solid waste for
use as fuel at one of its RDF-fueled generating plants.
1.8 NSP desires to grant an option to LPI for the purchase of land and
sell steam and/or natural gas and electricity to LPI as a single transaction
and provide the additional consideration of access to the Sherburne County
Generating Plant fire protection water supply and combustion of solid waste
generated at the LPI facility.
1.9 LPI desires an option from NSP for the purchase of such land and to
purchase the steam and/or natural gas and electricity and acknowledges that
if it terminates either the purchase of steam and/or natural gas or
electricity the additional consideration of access to the Sherburne County
Generating Plant fire protection water supply and combustion of solid waste
generated at the LPI facility will also terminate and LPI will pay
termination charges specified in the Agreement.
In consideration of the mutual covenants and agreements herein, NSP
and LPI agree as follows:
2. DEFINITIONS
2.1 The following terms when used in this Agreement shall have the
meanings specified: "Available" or "Availability" means the status of the
Steam Supply System when the System is capable of delivering steam at the
Delivery Point in a quantity which meets LPI's needs, but not to exceed one
hundred and eight (108) thousand pounds per hour, and in the quality of two
hundred and fifty (250) pounds per square inch gauge (Pslg) and four hundred
and twenty (420) degrees F, regardless of the LPI facility's ability to
accept steam.
"Compatible" means future expansion and/or addition to the LPI
facility does not materially interfere with the continued operation of the
Sherburne County Generating Facility or current or proposed uses of adjoining
NSP property.
"Condensate Return System" means the pipes, pumps, tanks, meters,
controls, wires, insulation, support structures and other equipment required
to return condensate from the LPI facility to the Sherburne County Generating
Plant.
"Contracted Demand Charge" means payments required by Paragraph
4.52 made by LPI to NSP for the purpose of obtaining electrical generating
capacity so the steam supply to the LPI facility will not be interrupted or
curtailed during periods of peak electrical demand on the NSP system.
"CPI Index" means the Consumer Price Index for all Urban Consumers
for All Cities, as published by the U. S. Department of Labor, Bureau of
Labor Statistics.
"Days" means Calendar Days. In computing any period of time in
this Agreement, the day of the last act, event, or default from which the
period of time begins to run shall not be included. The last Day of the
period so computed shall be included, unless it is a Saturday, Sunday or a
legal holiday.
"Delivery Point" for the Steam Delivery System means the
discharge of the isolation valve downstream of the Steam Delivery System
metering station located in or near the LPI facility as
designated on Exhibit B. Delivery Point for the Condensate Return System
means the inlet from the Condensate Return System to the condensate return
tank located in or near the LPI facility as designated on Exhibit B.
"Effective Date" means the first Day after which both NSP and LPI
have executed this Agreement.
"Energy Charge" means payments required by Paragraph 4.51 made
from LPI to NSP to reimburse NSP's costs to generate and deliver steam to the
LPI facility and return condensate.
"Fiscal Year" means the period of one year beginning on any
January 1 during the term of this Agreement, except that if this Agreement
or any provision hereof is terminated on other than a December 31 the last
Fiscal Year will be the period ending on such termination date and beginning
on the immediately preceding January 1.
"Fixed Facilities Charge" means the payment required by Paragraph
4.50 made from LPI to NSP for the use of the Steam Supply System.
"Full Capacity" means any time after which the average production
at the LPI facility achieves at least ninety percent (90%) of its one hundred
thousand (100,000) ton design capacity over any period of at least twelve
(12) consecutive calendar months.
"Steam Delivery System" means the pipes, pumps, meters, controls,
wires, insulation, support structures and other equipment required to deliver
steam to the LPI facility.
"Steam Supply System" means the boilers, pipes, pumps, meters,
controls, wires, insulation, support structures and other equipment required
to generate and deliver steam to the LPI facility and return condensate to
the Sherburne County Generating Plant. The Steam Supply System includes
the Condensate Return System and the Steam Delivery System.
"Tract I" means a parcel of land which NSP has donated to the
City of Becker, located in the City of Becker, Sherburne County, Minnesota,
described as:
The West 30 acres of the South 850 feet of the East 2575 feet of
the NW 114 of Section 6, Township 33 North, Range 28 West, hereinafter
referred to as Tract I.
"Tract II" means a parcel of land for which NSP shall grant LPI
an option located in the City of Becker, Sherburne County, Minnesota,
described as:
That part of the South 850 feet of the East 2575 feet of the NW
114 of Section 6, Township 33 North, Range 28 West lying East of the West 30
acres thereof, hereinafter referred to as Tract II.
3. SALE OF LAND
3.1 NSP acknowledges and agrees LPI intends to build and operate the LPI
facility on Tract I, a parcel of land located in the City of Becker,
Sherburne County, Minnesota adjacent to the Sherburne County Generating
Plant. The approximate location of Tract I is shown on Exhibit A.
3.2 NSP hereby grants to LPI a ten (10) year option to purchase by
warranty deed Tract II, a parcel of land located in the City of Becker,
Sherburne County, Minnesota adjacent to the Sherburne County Generating
Plant. The approximate location of Tract II is shown on Exhibit A.
3.3 LPI may exercise the option to purchase Tract II when the following
conditions have all been met:
(a) The LPI facility is operating or has operated at Full Capacity;
(b) LPI employs ninety (90) full-time, full-benefit or equivalent
employees in the operation of the LPI facility;
(c) LPI has executed a contract with NSP for the purchase of
additional steam or electricity capacity for an expansion or addition to the
LPI facility; and
(d) The proposed expansion or addition to the LPI facility is
Compatible with the Sherburne County Generating Plant.
Prior to the closing of the option to purchase Tract II, NSP will
provide LPI with evidence of the status of title to Tract II, which shall be
free of all liens and encumbrances other than any easements or rights-of-way
which are contemplated in this Agreement or which do not materially interfere
with use or value of Tract II.
3.4 LPI shall pay to NSP if it exercises the option to purchase Tract
II a purchase price which shall be an amount equal to one hundred thousand
dollars ($100,000.00) multiplied by the sum of (a) one, plus (b) the
difference between (i) the CPI Index as published most recently prior to the
date of the exercise of the option by LPI, minus (ii) the CPI Index as
published most recently prior to the Effective Date. Upon payment, NSP will
transfer Tract II to LPI by Warranty Deed.
3.5 The term of the option on Tract II shall begin on the Effective Date
of this Agreement.
3.6 NSP shall file within thirty (30) Days of the Effective Date a
memorandum with the Sherburne County Recorder stating the terms and
conditions of the option.
3.7 LPI shall be responsible and shall reimburse Malcolm Olson (herein
referred to as "Tenant") for any and all damages to the 1993 crop on Tract
II caused by LPI's construction of the LPI facility.
3.8 LPI acknowledges and agrees the lease between NSP and Tenant, dated
February 3, 1984, for agricultural crop use over Tract II shall remain in
full force and effect until the option to purchase is exercised by LPI. In
the event LPI exercises the option to purchase, LPI shall provide the Tenant
reasonable time to complete the annual term of the lease or be responsible
and reimburse Tenant for an equitable amount of crop damage based on the
average per acre yield and the then current commodity value.
3.9 LPI acknowledges and agrees existing irrigation wells and the
underground pipe located on Tract II shall remain in place until the option
to purchase is exercised by LPI. LPI shall grant Tenant an easement for same
to include access for maintenance and repair of said wells and pipe. LPI
shall take whatever precautions necessary to protect the wells and
underground pipe from damage. LPI shall reimburse Tenant for any damages to
such equipment by LPI, its agents or contractors.
3.10 NSP shall grant to the City of Becker, either by easement or
dedication, a thirty-five (35) foot wide strip of land for roadway or rail
purposes the south line of which shall be in common with the north lines of
Tracts I and II. NSP shall grant to the City of Becker, either by easement
or dedication, a twenty-five (25) foot wide strip of land for roadway or rail
purposes the north line of which shall be in common with the north line of
Tract II.
3.11 LPI shall not subdivide Tract II if the option to purchase is
exercised, except as may be required to obtain tax increment financing, pay
real estate taxes or by law. The transfer of any portion of the ownership
or production capacity of the LPI facility or any expansion or addition to
the LPI facility to a customer or affiliate of LPI shall not be considered
subdivision of the property.
3.12 LPI acknowledges and agrees NSP shall maintain a twenty (20) foot
utility corridor the south line of which shall be in common with the south
lines of Tracts I and II. In the event NSP proposes to install utilities in
the corridor, LPI shall have the right to review and approve the installation
of such utilities within sixty (60) Days notice of NSP's proposal. In the
event LPI does not approve the installation of the utilities, or any portion
or aspect of the utilities, LPI shall pay all additional costs and expenses,
including cost of land, for the installation of the utilities.
3.13 NSP shall reserve easements over Tract II for dust, fog, noise and
other such emissions which may be carried by the wind from the Sherburne
County Generating Plant and related appurtenances.
4. THERMAL ENERGY SUPPLY
4.1 LPI shall purchase steam and/or natural gas from NSP to provide
thermal energy for the LPI Facility. NSP shall provide steam to the LPI
Facility by means of a Steam Supply System which is described in Paragraph
4.3 of this Agreement. NSP shall make steam Available to LPI on either a
noninterruptible basis or an interruptible basis. Paragraphs 4.1 to 4.46
apply to the selection of either steam supply basis. Sale of steam from NSP
to LPI on a noninterruptible basis shall be in accordance with the terms of
Paragraphs 4.48 to 4.52. Sale of steam from NSP to LPI on an interruptible
basis shall be in accordance with the terms of Paragraphs 4.53 to 4.54. NSP
shall provide natural gas to the LPI Facility in accordance with the terms
of Paragraphs 4.55 to 4.56 of this Agreement.
4.2 LPI shall notify NSP in writing of LPI's choice of the form and
basis of thermal energy supply no later than November 1, 1993. The failure
of LPI to notify NSP in writing of its choice of the form and basis of
thermal energy supply by November 1, 1993 shall be deemed a selection of
steam on an interruptible basis.
Construction. Ownership. Operation and Maintenance of Steam Supply System
4.3 In the event LPI chooses steam for its thermal energy supply, NSP
shall construct, own, operate, and maintain a Steam Supply System which will
supply steam from the Sherburne County Generating Plant to the LPI facility.
NSP shall use the Steam Supply System to:
(a) generate steam of the quantity and quality specified in
Paragraph 4.21 from the Sherburne County Generating Plant for delivery to
the LPI facility;
(b) deliver steam of the quantity and quality specified in
Paragraph 4.21 from the Sherburne County Generating Plant to the LPI
facility;
(c) return condensate of the quantity and quality specified in
Paragraph 4.40 from the LPI facility to the Sherburne County Generating
Plant;
(d) provide for communication, which includes a dedicated phone
line and such links as may be required, between the Sherburne County
Generating Plant and the LPI facility to safely and reliably operate the
Steam Supply System.
A diagram of the Steam Supply System is attached to this Agreement as Exhibit
B.
4.4 NSP shall obtain all franchises, licenses, permits, rights-of-way
or easements necessary to construct, operate and maintain the Steam Supply
System. NSP shall contest, within reasonable limits, court proceedings,
orders, decrees, rules, regulations, laws and ordinances which would prevent
NSP from so doing; provided, NSP shall only be required to appeal to
conclusion at the first level of appeal from the original promulgation or
enactment of any such orders, decrees, rules, regulations, laws and
ordinances, whether such appeal is to administrative or judicial proceedings.
4.5 LPI shall cooperate and provide information and documentation
necessary for NSP to obtain the franchises, licenses, permits, rights-of-way
and easements.
4.6 LPI shall provide NSP with a right-of-way, along and in improvements
situated on the LPI facility, as necessary to construct, operate, maintain,
modify, repair, replace or make additions to the Steam Delivery System or
Condensate Return System. LPI shall further permit NSP the right of ingress
to and egress from the LPI facility, over and across the LPI facility by
means of roads and lanes thereon, if there is such, and otherwise by such
route or routes as shall be calculated to cause the least damage and
inconvenience to LPI and the LPI facility.
4.7 NSP shall have the right to enter the LPI facility upon notification
to LPI to construct, operate and maintain and, if necessary, modify, repair,
replace or make additions to the Steam Delivery System.
4.8 LPI shall furnish NSP, without charge to NSP, electricity,
instrument air and well-water as may be required to support the operation and
maintenance of the portion of the Steam Delivery System, including but not
limited to the condensate return pumps, located at the LPI facility.
4.9 NSP shall consult with LPI in the preparation of and make Available
to LPI as they become Available to NSP, the technical design specifications,
construction drawings and plans for review of the proposed configuration,
appearance, and location of the portion of the Steam Delivery System and
Condensate Return System to be located at the LPI facility. Such review by
LPI shall be conducted in a timely fashion, so as not to impact project
schedules.
4.10 LPI shall consult with NSP in the preparation of and make Available
to NSP as they become Available to LPI, the technical design
specifications, construction drawings and plans for review of the proposed
configuration, appearance, and location of any equipment which will be
connected to the Steam Delivery System and Condensate Return System. Such
review by NSP shall be conducted in a timely fashion, so as not to impact
project schedules.
4.11 During the construction, operation and maintenance of the Steam
Supply System by NSP, NSP shall exercise reasonable care not to engage in
acts or omissions which would cause loss or damage to the Steam Supply System
and use its best efforts to avoid damage to any property of LPI and
interference with LPI's operations at the LPI facility.
4.12 NSP shall perform annual maintenance on the Steam Delivery System.
Whenever possible, NSP shall schedule annual maintenance to coincide with
scheduled outages of the Sherburne County Generating Plant and the LPI
facility.
4.13 During the construction, operation and maintenance of the LPI
facility by LPI, LPI shall exercise reasonable care not to engage in acts
or omissions which would cause loss or damage to the Steam Supply System and
use its best efforts to avoid damage to any property of NSP and interference
with NSP's operations of its Sherburne County Generating Plant or the Steam
Supply System.
4.14 Written procedures which shall be consistent with this Agreement and
mutually acceptable to both parties shall govern the inspection, check-out,
testing, start-up, and operation of the Steam Delivery and Condensate Return
Systems. NSP shall develop and maintain all such procedures. NSP agrees to
develop such procedures in coordination with LPI. LPI agrees to provide, at
its own cost, technical resources reasonably required to support the
development of the procedures.
4.15 NSP shall designate a Project Manager for the construction and
start-up of the Steam Supply System. LPI shall designate a Project Manager
for construction of the LPI facility. The Project Managers shall be
responsible to schedule and coordinate the construction and start-up of the
Steam Supply System and for routine communication between NSP and LPI.
Operation and maintenance of the Steam Supply System shall be the
responsibility of NSP and the Sherburne County Generating Plant Manager or
his (her) designee.
4.16 Upon completion of the Steam Supply System, NSP shall purchase and
have in stock those spare parts for the Steam Delivery System which cannot
normally be obtained in less than twenty-four (24) hours, the failure of
which would disable the operation of such portions of the Steam Delivery
System.
4.17 LPI shall not, by reason of this Agreement or the payments made
pursuant to this Agreement, acquire any title, ownership or other rights in
or to the Sherburne County Generating Plant or the Steam Supply System. Any
portion of the Steam Supply System placed at the LPI facility by NSP for the
purpose of delivering of steam or condensate shall be and remain the property
of NSP.
4.18 NSP shall have no interest or right in, and agrees to pay over to
LPI, any amounts received by it, as compensation for the condemnation, or
other taking for public use of any part of the LPI facility, or any other
part thereof on which the Steam Supply System is constructed.
4.19 No changes, physical or electronic, which materially affect the
control or operation of the Steam Delivery or Condensate Return Systems shall
be made by LPI or NSP without the prior written consent of the other party.
4.20 Steam supplied to the LPI facility under the terms of this Agreement
shall be solely for the use in operating the LPI facility and shall not be
resold or transported by LPI.
Steam Quantity and Quality
4.21 NSP shall provide steam to the LPI facility meeting the following
specifications when measured at the Delivery Point:
(a) Temperature: 420 degrees with average daily variations of not
more than plus or minus 5 degrees superheat and transient variations of not
more than plus or minus 5 degrees Fahrenheit superheat.
(b) Pressure: 250 pounds per square inch gauge (PSIG) with average
daily variations of not more than plus or minus 10 PSIG and transient
variations of not more than plus or minus 15 PSIG.
(c) Maximum Steam Flow: one hundred and eight (108) thousand pounds
per hour. LPI may take steam at any rate of flow not greater than the
maximum; provided, when LPI takes steam, the minimum flow rate shall be at
least twelve (12) thousand pounds per hour.
4.22 NSP shall make steam Available in the quantities and qualities
stated in Paragraph 4.21 commencing at 12:01 a.m. of September 30, 1994.
From September 30, 1994 to June 1, 1995, LPI shall not be required to take
an annual minimum amount of steam. Provided NSP makes at least three hundred
and seventy-five thousand (375,000) thousand pounds (klbs.) Available per
Fiscal Year, LPI shall be required to take or pay for an annual minimum of
three hundred and seventy-five thousand (375,000) thousand pounds (klbs.) per
Fiscal Year, commencing at 12:01 a.m. of June 1, 1995. Minimum steam usage
for LPI during any Fiscal Year which has less than three hundred and
sixty-five (365) Days shall be the number of pounds otherwise required,
multiplied times a fraction, the denominator of which is three hundred and
sixty-five (365) and the numerator of which is the actual number of Days in
such Fiscal Year.
4.23 From September 30, 1994 to June 1, 1995, NSP will coordinate with
LPI, and will endeavor to deliver steam to LPI in the conditions and amounts
required during the checkout, testing, and start-up of the LPI Facility. NSP
makes no guarantee of the Availability of any steam to be supplied during
this period. Further, the steam supply during this period is subject to
interruption or curtailment at the sole discretion of NSP during periods of
peak electrical demand on the NSP system.
4.24 If the steam flow to LPI is to be temporarily reduced or limited,
NSP will use all reasonable efforts to notify LPI of the extent of such
reduction or limitation at least one (1) hour in advance. Should the steam
supply to LPI be interrupted through no fault of LPI, NSP shall, within four
(4) hours of the start of such interruption, advise LPI of the estimated
duration of the interruption. Any interruption of steam delivery shorter
than fifteen (15) minutes in length shall not result in any remedy to LPI or
be included in calculating Availability of the Steam Supply System. Any
interruption of steam flow longer than fifteen (15) minutes but shorter than
eight (8) hours shall be counted as eight (8) hours in length. Any
interruptions greater than or equal to eight (8) hours in length shall be
included in calculating Availability of the Steam Supply System at their
actual value, rounding to the nearest whole hour.
4.25 LPI acknowledges and agrees that NSP shall not be required to
provide backup steam during periods of when the Steam Supply System is not
Available.
Metering
4.26 Metering of steam and condensate shall be installed in the Steam
Supply System at the Delivery Point. Such metering will consist of:
(a) Temperature and pressure recording instruments and flow meters
for steam;
(b) Temperature compensated flow meters and temperature recording
instruments for condensate; and
(c) Conductivity and Ph monitoring and sampling devices for
condensate.
4.27 Meters and all meter readings and/or documentation shall be
accessible at all reasonable times to inspection and examination by LPI.
Meters shall be calibrated at least once each one hundred and eighty (180)
Days. Reasonable expenses relating to the calibration, repair and maintenance
of the meters shall be shared equally by NSP and LPI.
4.28 LPI may install, operate and maintain, at its own cost, additional
metering equipment, provided any additional meter is installed at the LPI
facility so as not to interfere with the operation of NSP metering equipment.
Billing
4.29 When steam supply commences and twenty (20) Days prior to the
beginning of each Fiscal Year, NSP shall provide LPI with a statement of the
Fixed Facility Charge, the Energy Charge and, in the event LPI chooses the
noninterruptible steam supply, the Contracted Demand
Charge. Indices will be used to adjust the price components for a given
Fiscal Year in January of that year. Price Components will be adjusted by
the difference of the averages of the indices for
each of the two prior years.
4.30 If LPI fails to take the annual minimum requirement specified in
Paragraph 4.22 for any Fiscal Year, LPI shall pay NSP, within thirty (30)
Days of the end of January of the following Fiscal Year, an amount equal to
the value of the total number of pounds of the annual minimum not taken,
multiplied by the Energy Charge, minus the fuel cost of such undertaken
pounds, as adjusted for boiler efficiency, but in no case shall the fuel cost
credit exceed eighty percent (80%) of the current Energy Charge.
4.31 NSP shall issue bills for steam supply service on or before the
tenth (10th) Day of the thirty (30) Day billing period. The bill shall be in
a format mutually acceptable to NSP and LPI.
The bill shall state the following information:
(a) The pounds of steam of the quality specified in Paragraph 4.21
produced and delivered by NSP to LPI during the preceding month;
(b) Previous and current steam flow meter readings;
(c) Credits, if any, due for Availability of steam supply;
(d) The volume, in U.S. gallons, of all condensate of the quality
specified in Paragraph 4.40 returned by LPI during the preceding month.
(e) Previous and current condensate meter readings;
(f) Total volume of condensate that does not meet or exceed the
condensate quality specifications stated in Exhibit C; and
(g) Sales taxes.
4.32 LPI shall pay bills for steam supply service on or before the tenth
Day succeeding the date bill is rendered for steam supply service by NSP in
the preceding billing period.
4.33 Any monthly statement presented by NSP to LPI which is past due as
specified herein shall be subject to a late payment charge at the interest
rate of one and one-half (1-1/2) percent per month (or fraction thereof) on
the amount past due, compounded monthly, until such past due amount is paid
by the party owing thereon. This late payment charge is merely a further
obligation hereunder and shall not be construed to excuse the fact that a
late payment of non-contested portions of a statement by the party owing
thereon is a default; and further, such charge shall not constitute a waiver
of any remedy the non-defaulting party may pursue in the event of default.
The date of payment shall mean the date the letter containing any payment is
postmarked.
4.34 Shall any non-contested past due amount owed by LPI to NSP exceed
sixty (60) Days, NSP, at its sole option, may discontinue supplying steam and
accepting solid waste after giving LPI seven (7) Days written notice by
registered mail until such past due amounts are paid along with the late
payment charge specified in Paragraph 4.33. In the event any portion of the
bill is contested, LPI shall pay all amounts less that portion which is
contested.
4.35 NSP shall prepare accurate periodic bills. NSP and LPI shall both
review such bills and raise any questions or point out any mistakes promptly.
4.36 All bills and payments pursuant to this Agreement shall be sent,
unless otherwise agreed to, by United States Mail, postage thereon prepaid,
addressed to the persons identified in Paragraph 14.4.
Term of Steam Supply
4.37 NSP shall provide steam to the LPI facility in the quantity and
quality specified in Paragraph 4.21 for a period of twenty (20) years.
4.38 LPI shall purchase steam from NSP for the LPI facility in the
quantity and quality specified in Paragraph 4.21 for a period of twenty (20)
years.
4.39 The twenty (20) year term for steam supply begins at 12:01 a.m. on
January 1, 1995.
Condensate Return
4.40 During each Fiscal Year, LPI shall return condensate water at the
Delivery Point equal to a volume of at least eighty percent (80%) of the
condensate from any steam delivered to the LPI Facility. Condensate shall
meet or exceed the condensate quality specifications stated in Exhibit C, as
measured at the Delivery Point. LPI shall install water treatment equipment
upstream of the NSP condensate storage tank as required to assure condensate
meets or exceeds the requirements of Exhibit C. Water treatment equipment
shall be installed at the LPI facility.
4.41 LPI shall dispose of any condensate which does not meet the
specifications stated in Exhibit C. LPI shall dispose of the condensate at
its own cost, and in an environmentally responsible manner.
4.42 From September 30, 1994 to June 1, 1995, LPI will endeavor to return
eighty percent (80%) of the condensate from the steam supplied to NSP during
the checkout, testing and startup of the LPI facility. LPI makes no
guarantee of the amount of condensate to be returned during this period. LPI
agrees to dispose of condensate and/or waste water from the LPI facility
which does not meet or exceed the condensate quality specifications stated
in Exhibit C at its own cost, and in an environmentally responsible manner.
4.43 LPI shall pay NSP three dollars ($3.00) for each one thousand
(1,000) gallons of condensate less than eighty percent (80%) which are not
returned to NSP, as calculated on a monthly basis.
4.44 If the condensate return rate is less than sixty percent (60%) for
fifteen (15) consecutive Days, NSP reserves the right to interrupt steam
supply until such time as the LPI facility is able to return sixty percent
(60%) of the condensate.
4.45 Prior to the end of the fifteen (15) Day period, NSP and LPI shall
meet to discuss LPI's efforts to improve the condensate return rate. NSP
agrees to give LPI due consideration for its efforts to improve condensate
return rate in this situation.
4.46 NSP shall pay LPI three dollars ($3.00) for each one thousand
(1,000) gallons of condensate greater than eighty percent (80%) which are
returned to NSP as calculated on a monthly basis.
Steam Supply Selection
4.47 In the event LPI chooses steam as the form of its
thermal energy supply, LPI shall periodically have the option of changing the
basis of steam supply. Steam supply basis shall be elected for three (3)
year terms beginning in May, 1997 and continuing every third year in the
month of May until the expiration of this Agreement. Prior to the tenth
(10th) Day of May in each third year, NSP will provide LPI with a quotation
for the Contracted Demand Charge for the noninterruptible steam supply for
the upcoming three year term. After receipt of the quotation and prior to
the thirtieth (30th) Day of May, LPI shall notify NSP in writing of its
choice of steam supply service for the three year term, which will begin on
the first (1st) Day of January of the following year. In 1996 and 1997, NSP
will supply steam for a one-year term, on the basis selected in writing by
LPI in May of the previous year. In 1995, NSP will supply steam for a
one-year term, on the basis determined by Paragraph 4.2. Prior to the tenth
(10th) Day of May in 1995 and 1996, respectively, NSP will provide a
quotation for the Contracted Demand Charge for the noninterruptible steam
supply for the following year.
Noninterruptible Steam Supply
4.48 In the event LPI chooses noninterruptible steam supply, the Steam
Supply System will be Available ninety-five percent (95%) of the eight
thousand four hundred and forty-eight (8448) hours the LPI facility is
scheduled to run during a year. Scheduled operation of the LPI facility shall
be three hundred and sixty-five (365) Days at twenty-four (24) hours a Day,
less one (1) scheduled annual maintenance outage of a duration not to exceed
seven (7) Days or one hundred and sixty-eight (168) hours, less one hundred
and forty-four (144) hours for corrective and/or preventative maintenance
outages. Annual scheduled operating hours for the LPI facility will total
eight thousand four hundred and forty-eight (8448) hours. In those years with
three hundred and sixty-six (366) Days, the number of annual scheduled
operating hours shall be increased to eight thousand four hundred and
seventy-two (8472). Insofar as possible, all maintenance outages shall
be taken at times convenient to both NSP and LPI. Regardless of mutual
convenience, LPI shall provide NSP with not less than sixty (60) Days notice
prior to the commencement of its annual maintenance outage. LPI intends that
the one hundred and forty-four (144) hours of corrective and/or preventative
maintenance outages will be conducted in twelve (12) monthly outages of
twelve (12) hours. LPI shall provide NSP with not less than seven (7) Days
notice prior to the start of any such outage.
4.49 LPI shall purchase steam from NSP at a price consisting of three
components: Fixed Facility Charge, Energy Charge and, if LPI selects
noninterruptible steam supply, Contracted Demand Charge.
4.50 LPI shall pay NSP a Fixed Facilities Charge of Four Million Two
Hundred and Sixty Thousand Dollars ($4,260,000.00) in return for use of the
Steam Supply System for the term of this Agreement. The Fixed Facility
Charge shall be payable to NSP in the form of an annuity with the following
terms:
Principal Amount = P: $4,260,000.00
Term = n: 20 years
Interest Rate = i: The annual interest rate for each Fiscal Year
shall be equal to the average of seven percent (7%) and the
annual average rate granted to electric utilities for Return on
Equity (ROE) as reported on or about the tenth (10th) Day of
January of that year by Regulatory Research Associates, Inc.
Compounding: Annually
The value of the Fixed Facilities Charge for each Fiscal Year shall
be calculated in January of that year using the following formula:
n n
Fixed Facility Charge = (i (1 + i) x P)/((1 + i) - 1)
ROE value to be used for calculating the 1995 Fixed Facilities
Charge shall be twelve point zero nine (12.09%). The value of the Fixed
Facilities Charge for 1995 shall be four hundred and eighty-three thousand,
four hundred and ten dollars ($483,410).
4.51 For each one thousand (1,000) pounds of steam delivered by NSP to
the LPI facility, LPI agrees to pay NSP an Energy Charge. The Energy Charge
shall have the following components:
Component Price Adjusted Index
Fuel $1.15 Actual Delivered Coal Cost
to Sherburne County
Generating Plant as Reported
by NSP to U.S. Federal Energy
Regulatory Commission
Replacement Energy $0.27 NSP Marginal Cost of
Replacement Energy
Fixed O & M $0.23 Total Compensation, Civilian
Workers as Reported by U.S.
Department of Commerce
Property Tax $0.10 Actual Property Tax
Variable O & M Costs $0.10 Total Compensation, Civilian
Workers as Reported by U.S.
Department of Commerce
The Energy Charge is equal to the sum of these components as expressed in
dollars per thousand pounds of steam.
4.52 In the event LPI chooses noninterruptible steam supply,
LPI shall pay NSP a Contracted Demand Charge in the amount of one hundred
sixty-five thousand, four hundred eighty dollars ($165,480.00) per year for
the Fiscal Year starting on January 1, 1995. This value will be adjusted in
accordance with the terms stated in Paragraph 4.47.
Interruptible Steam Supply
4.53 In the event LPI chooses interruptible steam supply, the Steam
Supply System will be Available ninety percent (90%) of the total number of
hours in a year, or seven thousand eight hundred and eighty-four (7884) hours
per year. In years with three hundred and sixty-six (366) Days, this value
shall be increased to seven thousand nine hundred and six (7906). Steam
delivery is subject to interruption during NSP system-wide peak electrical
demand periods. The duration and frequency of interruption periods shall be
at the discretion of NSP. Interruption periods will normally occur at such
times when NSP is required to use oil-fired generating equipment or to
purchase power at a price equivalent to production cost using oil-fired
equipment, when NSP expects peak electrical demand, or at such times when,
in NSP's opinion, the reliability of the electrical transmission and/or
delivery systems are endangered.
(a) Within one (1) hour of publication by NSP System Operations,
LPI will be notified of any daily peak load forecast which includes
conditions under which steam supply to LPI could be curtailed. Such
notification shall constitute the start of a "Control Condition." During
such a Control Condition, steam supply to LPI will be subject to interruption
at any time with fifteen (15) minutes notice. NSP accepts no responsibility
for any damages, direct or indirect, resulting from interruption of steam
supply to LPI during a Control Condition.
(b) Peak periods during which steam supply is subject to
interruption shall be defined as follows: The peak period is defined as
those hours between 9 a.m. and 9 p.m. Monday through Friday, except the
following holidays: New Year's Day, Good Friday, Memorial Day, Independence
Day, Labor Day, Thanksgiving Day, and Christmas Day. When a designated
holiday occurs Saturday, the preceding Friday will be a designated holiday.
When a designated holiday occurs on Sunday, the following Monday will be a
designated holiday.
Insofar as possible, any maintenance outages taken during the year shall be
taken at times mutually convenient to both NSP and LPI. Regardless of mutual
convenience, LPI shall provide NSP with not less than sixty (60) Days notice
prior to LPI's annual seven (7) Day maintenance outage. LPI shall make all
reasonable efforts to provide NSP with not less than seven (7) Days notice
prior to the start of any other routine maintenance outages.
4.54 LPI shall purchase steam from NSP at a price consisting of two
components: Fixed Facility Charge and Energy Charge. LPI shall pay the
Fixed Facility Charge as described in Paragraph 4.50. LPI shall pay the
Energy Charge as described in Paragraph 4.51.
Natural Gas Supply
4.55 In the event LPI chooses gas for its thermal energy supply, NSP
agrees to supply, transport, or distribute natural gas to the LPI facility.
LPI shall purchase natural gas supplied and distributed by NSP for a period
of one (1) year from the selection of natural gas for its thermal energy
supply. Terms and conditions of gas supply transportation or distribution
shall be as agreed to between the parties at the time LPI chooses to exercise
this option, and shall be detailed in a specific natural gas service
contract. Natural gas purchased by LPI shall be transported and distributed
over the NSP distribution system. NSP may match the terms of any alternative
gas supplier selected by LPI to supply natural gas to the LPI facility.
4.56 In the event LPI terminates the purchase of steam for its thermal
energy supply, NSP agrees to supply, transport or distribute natural gas to
the LPI facility. LPI shall purchase natural gas supplied and distributed
by NSP for a period of one (1) year from the termination of the steam supply.
Terms and conditions of gas supply, and distribution shall be agreed to
between the parties at the time LPI terminates steam supply, and shall be
detailed in a specific natural gas service contract. Natural gas purchased
by LPI shall be transported and distributed over the NSP distribution system.
NSP may match the terms of any alternative gas supplier selected by LPI to
supply natural gas to the LPI facility. LPI use of natural gas as the
primary source of process thermal energy shall not relieve LPI of its
obligation to take or pay for an annual minimum of three hundred and
seventy-five thousand (375,000) thousand pounds (klbs.) of steam and to pay
the Fixed Facility Charge for the Steam Supply System.
5. ELECTRICITY SUPPLY
5.1 NSP shall provide electric service to the LPI facility in the form
of three (3) Phase, four (4) Wire, Grounded Wye, Alternating Current at a
nominal frequency of sixty (60) Hertz and at a nominal voltage of thirteen
point-eight (13.8) Kv, for LPI's use solely for the operation of electric
equipment to be installed by LPI at the LPI facility.
5.2 NSP shall deliver electric service to the LPI facility at the 13.8
Kv side of the NSP transformer located in the NSP substation to be build
adjacent to the LPI facility. LPI will be responsible for the cost of all
facilities necessary to interconnect at NSP's disconnecting means of the
substation transformer.
Capacity Commitment
5.3 NSP agrees to provide and keep Available throughout the term of
electric service for LPI's use at the LPI facility eight (8) megawatts of
capacity. NSP also agrees to provide additional capacity to an aggregate of
fourteen (14) megawatts capacity upon reasonable written notice from
LPI specifying the additional amount of capacity and the date same will be
required. Reasonable notice shall be construed to mean ample time in which
NSP can provide such additional capacity in its system as may be necessary.
Annual Minimum Charge
5.4 In consideration of the capacity commitment stated in Paragraph 5.3
and its investment in facilities to serve LPI, LPI agrees that if the total
net payments during any Fiscal Year, in accordance with the rate stated in
Paragraph 5.3, amount to less than the minimum charge of $336,000.00 per
Fiscal Year, the difference between the minimum charge and the total net
payment shall be included in the bill for the last month of the Fiscal Year
and LPI agrees to pay same as charge for electric service rendered.
Rate and Billing
5.5 LPI shall qualify for and elects the rate schedule for general
service during construction of the LPI facility. LPI shall pay NSP's
established rate schedule in effect from time to time in this locality for
such electric service, the established rate schedule now in effect being the
one attached to this Agreement as Exhibit D.
5.6 NSP shall issue bills for electric service on or before the tenth
(10th) Day of the thirty (30) Day billing period.
5.7 LPI shall pay bills for electric service on or before the tenth
(10th) Day succeeding the date bill is rendered for electric service by NSP
in the preceding billing period.
5.8 Any monthly statement presented by NSP to LPI which is past due as
specified herein shall be subject to a late payment charge stated in NSP's
tariff with the Minnesota Public Utilities Commission on the amount past due,
compounded monthly, until such past due amount is paid by the party owing
thereon. This late payment charge is merely a further obligation hereunder
and shall not be construed to excuse the fact that a late payment of
non-contested portions of a statement by the party owing thereon is a
default; and further, such charge shall not constitute a waiver of any remedy
the non-defaulting party may pursue in the event of default. The date of
payment shall mean the date the letter containing any payment is postmarked.
Term of Electric Service
5.9 NSP shall provide electric service to the LPI facility for the
purposes of construction of the LPI facility within thirty (30) Days of
NSP's receipt of written request by LPI to provide such service. LPI shall
pay NSP for the electric service for the purposes of construction of the LPI
facility.
5.10 NSP shall provide electric service to the LPI facility for the
purposes of operation of the LPI facility by January 1, 1995 for a period of
twenty (20) years. NSP shall not be required to provide electric service
greater than five (5) megawatts of capacity prior to March 1, 1995.
5.11 LPI shall purchase electric service from NSP for the purposes of
operation of the LPI facility by January 1, 1995 for a period of twenty (20)
years.
Authority of the Minnesota Public Utilities Commission
5.12 The electric service provided under this Agreement is subject to the
General Rules and Regulations of NSP on file with the Minnesota Public
Utilities Commission as they now exist or may hereafter be changed.
6. FIRE PROTECTION WATER SUPPLY
6.1 Beginning September 30, 1994, NSP shall provide access to the fire
protection water supply of the Sherburne County Generating Plant at the
north-south centerline of the west boundary of Tract I, seven point five
(7.5) feet below grade. Access to and reliance on the fire protection
water supply is conditioned on the approval of insurers for both NSP and LPI.
6.2 NSP shall supply fire protection water at one hundred (100) pounds
per square inch gauge (PSIG) and one thousand five hundred (1500) gallons per
minute (GPM) at the point of delivery described in Paragraph 6.1. NSP shall
purchase, install, and test all necessary pipe, valves, fittings, and
appurtenances required to supply fire protection water to the point of
delivery. LPI agrees to pay NSP engineering, material, installation, testing
and administrative costs incurred for purchase, installation and testing of
the fire protection water supply access.
6.3 LPI shall provide at its sole expense all necessary labor,
equipment, and materials including all piping, valves and meters, to deliver
fire protection water from the point of delivery to the LPI facility.
6.4 NSP shall assume or incur no liability for the LPI facility, LPI
property, real or personal, or any person, whether or not employed by LPI,
as a result of providing access to the fire protection water supply of the
Sherburne County Generating Plant.
6.5 In the event an insurer for NSP withdraws approval, NSP may
terminate its agreement to provide access to the fire protection water supply
by giving written notice to LPI a termination date not less than one hundred
and eighty (180) Days after notice. In the event an insurer withdraws
approval, NSP shall assume or incur no liability for the LPI facility, LPI
property, real or personal, or any person, whether or not employed by LPI.
In the event NSP obtains insurance from an insurer which will not approve
LPI's access to the fire protection water system, NSP and LPI shall negotiate
in good faith to reasonably allocate expenses arising out of termination of
access.
6.6 LPI shall use fire protection water only for the purpose of fighting
fires either manually, via hose station , or automatically, via sprinkler
system.
7. SOLID WASTE COMBUSTION
7.1 NSP shall accept solid waste generated from the LPI facility meeting
the requirements stated in Exhibit E at one of its RDF-fueled generating
plants. NSP's acceptance of the solid waste is contingent upon the following
conditions:
(a) Results from material evaluation and classification by the
Minnesota Pollution Control Agency (MPCA) and the United States
Environmental Protection Agency (USEPA), which provides conditions to
determine the acceptability of the combustion of the solid waste at the
RDF-fueled generating plant;
(b) NSP receipt and the continued validity of all necessary
approvals from federal, state, regional, county or local agencies or
authorities having jurisdiction, including permit modifications, to allow
evaluation, classification, testing and combustion of the solid waste at the
RDF-fueled generating plant;
(c) Availability of processing and combustion capacity at the
RDF-fueled generating plant; and
(d) Results from material evaluation, classification, and
pre-qualification testing, including a test burn, of the solid waste which
determine the ability to handle and combust the solid waste at the RDF-fueled
generating plant without adversely affecting plant operations; and
(e) Agreement by NSP and LPI on terms of a capacity commitment.
7.2 In the event of any change in the operation of the LPI facility
which results in a material change in the physical character or composition
of the solid waste, NSP's acceptance of the solid waste is contingent upon
the meeting the conditions stated in Paragraph 7.1(a), (b), and (d).
7.3 LPI shall pay all costs in connection with transportation and
delivery of solid waste from the LPI facility to the RDF-fueled generating
plant. LPI shall weigh the solid waste prior to delivery to the plant. LPI
shall deliver the solid waste to the plant in RDF-type trailers compatible
with plant operation. LPI shall deliver the solid waste to the plant on a
schedule compatible with plant operation.
7.4 LPI shall pay NSP for all solid waste delivered to the RDF-fueled
Generating Plant. For accepting solid waste that meets the specifications
of RDF material stated in Exhibit E, LPI shall pay NSP fifteen dollars ($15)
per ton. Alternatively, LPI shall pay NSP twenty dollars ($20) per wet ton
of material delivered by LPI to the RDF-fueled Generating Plant that meets
all specifications of the RDF material stated in Exhibit E, with the
exception of moisture, which shall not exceed fifty-five percent (55%). All
estimated prices are expressed in 1993 dollars and will be adjusted in
January of each Fiscal Year using the CPI Index.
7.5 NSP and LPI agree to pursue classification and qualification of the
solid waste in a timely fashion.
7.6 NSP and LPI agree to use best efforts to deliver solid waste to an
RDF-fueled generating plant not more than one hundred and fifty (150) miles
from the LPI facility.
7.7 NSP and LPI agree to execute a separate agreement which details the
specifics of solid waste delivery to the RDF-fueled generation.
8. INDEMNITY
8.1 NSP shall pay, indemnify, defend and hold LPI harmless from and
against, any and all costs, liabilities, claims, damages, losses, actions,
suits or judgments (including reasonable attorneys' fees), asserted against
LPI by any other person, firm, corporation, governmental authority
or other entity (including, without limitation, employees of NSP) arising out
of, or resulting from:
(a) NSP's negligence in the construction, operation, maintenance,
modification, replacement or repair of the Steam Supply System to the
Delivery Point; or
(b) Any breach by NSP of any warranty or representation stated in
Section 9 of this Agreement.
8.2 Notwithstanding Paragraph 8.1, NSP shall not be obligated to LPI for
losses solely arising out of, resulting from or relating to:
(a) LPI's negligence, gross negligence or willful misconduct.
8.3 LPI shall pay, indemnify, defend and hold NSP harmless, from and
against any and all costs, liabilities, claims, damages, losses, actions,
suits or judgments (including reasonable attorney's fees) asserted against
NSP by any other person, firm, corporation, governmental authority
or other entity (including, without limitation, employees of LPI) arising out
of, or resulting from:
(a) LPI's negligence in the installation, maintenance, repair or
use of any machinery, boilers or equipment at the LPI facility, other than
the Steam Supply System to the Delivery Point; or
(b) Any breach by LPI of any warranty or representation stated in
Section 9 of this Agreement.
8.4 Notwithstanding Paragraph 8.3, LPI shall not be obligated to NSP
for losses solely arising out of, resulting from or relating to:
(a) NSP's negligence, gross negligence or willful misconduct.
8.5 Any party to whom indemnification is owed pursuant to Paragraphs 8.1
through 8.4 will give the other party prompt notice of any claim for which
indemnification is owed and the indemnifying party will immediately undertake
the defense of or compromise or settle, any such claim; provided, however,
that the party owing such indemnification shall consult with the other
party with respect to any such defense, compromise or settlement and such
other party, may at its own expense, participate in (but not control) any
such defense. In the event that any party obligated to defend and indemnify
fails to defend, compromise or settle any claim, the party to whom
indemnification is owed will have the right to undertake the defense,
compromise or settlement of such claim on behalf of, and for the account of
and at the risk of the other party. Notwithstanding anything in this
Agreement to the contrary, if, in the reasonable estimation of the party to
whom indemnification is owed, there is a reasonable probability that the
claim against it may have a material and adverse effect against such party
other than for money payable, such party shall have the right, upon notice
to the other party to assert and maintain control of efforts to defend,
compromise or settle such claim, at its own cost and expense.
8.6 LPI and NSP shall purchase and maintain the following policies of
insurance during the entire term of this Agreement:
(a) Statutory Workers' Compensation, and Employers Liability with
a limit of not less than $100,000.
(b) Comprehensive General Liability or the equivalent at not less
than $5,000,000 per occurrence and a $5,000,000 annual aggregate. This
coverage shall include, but not be limited to, explosion, collapse,
underground damage, independent contractors, broad form property damage,
personal injury or death, coverage for products and completed operations,
and contractual coverage specifically covering the liability assumed under
this Agreement.
(c) Property insurance. The parties hereto shall purchase and
maintain property insurance covering their own property and equipment,
including coverage providing all risk fire and extended coverage, boiler and
machinery, and transit and installation, or policies providing equivalent
coverage. The parties hereby waive subrogation against each other under these
policies and further agree that any deductibles under these policies will be
absorbed by the insured, it being the specific intent of the parties that
each will insure their own property and will not attempt to seek
reimbursement for any damage to such property which is covered under these
policies, or which would have been covered except for deductibles or an
election to self-insure or not to insure.
8.7 NSP and LPI shall be responsible for assuring that each
of their contractors and their
subcontractors carry insurance in the amounts and types required.
8.8 Copies of all insurance policies provided in Paragraph
8.6 or certification thereof
shall be furnished each party hereto by the other party, together with all
amendments and
replacements.
8.9 The provisions made in Paragraph 8.6 shall not relieve
or excuse either party from
any of its other obligations under this Agreement, including its obligation
to indemnify the other
party hereunder in the manner and to the extent provided in its
indemnification provision above.
8.10 No provision of this Agreement shall in any way inure
to the benefit of any third
person (including the public at large) so as to constitute any such person
a third party beneficiary
of this Agreement or of any one or more of the terms hereof, or otherwise
give rise to any cause of
action in any person not a party hereto.
8.11 The provisions of this Agreement providing for
limitation of or protection against
liability of NSP or LPI and their suppliers or subcontractors shall apply to
the full extent permitted
by law and regardless of fault, and shall survive the expiration or
termination of this Agreement.
9. WARRANTIES AND REPRESENTATIONS
9.1 NSP hereby represents on behalf of itself:
(a) Northern States Power Company (NSP) is a
corporation duly organized,
validly existing and in good standing under the laws of the State
of Minnesota and has
corporate power and authority to execute and deliver this
Agreement and to perform its
obligations hereunder.
(b) The execution, delivery, and performance by
NSP of this Agreement have
been duly authorized by all necessary corporate action on the part
of NSP, do not contravene
any law, or any government rule, regulation, or order applicable
to NSP or its properties,
or the Articles of Incorporation or By-Laws of NSP, and do not and
will not contravene
the provisions of, or constitute a default under, and indenture,
mortgage, contract, or other
instrument to which NSP is a party or by which it is bound, and
this Agreement constitutes
a legal, valid, and binding obligation of NSP enforceable in
accordance with its terms, except
as limited by applicable bankruptcy, insolvency, reorganization,
or similar laws at the time
in effect.
(c) There are no actions, suits, or proceedings
pending or to NSP's knowledge
threatened against or affecting NSP before any court or
administration body or agency which
might materially adversely affect the ability of NSP to perform
its obligations under this
Agreement.
(d) EXCEPT AS EXPRESSLY SET FORTH IN THIS
AGREEMENT NSP
MAKES NO WARRANTY WHATSOEVER, EXPRESS OR IMPLIED, AS TO STEAM,
INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A
PARTICULAR PURPOSE.
(e) NSP has furnished or will furnish within a
reasonable time copies of the
resolutions of its Board of Directors authorizing the execution,
delivery and performance
of this Agreement by NSP certified by the Secretary or an
Assistant Secretary of NSP, and
such resolutions were duly and validly adopted and are, as the
date hereof, true and correct
and in full force and effect.
9.2 LPI hereby represents on behalf of itself:
(a) LPI is a corporation duly organized, validly
existing and in good standing
under the laws of the State of Minnesota and has corporate power
and authority to execute
and deliver this Agreement and to perform its obligations
hereunder.
(b) The execution, delivery and performance by LPI
of this Agreement have been
duly authorized by all necessary corporate action on the part of
LPI, do not contravene any
law, or any governmental rule, regulation, or order applicable to
LPI or its properties, or the
Articles of Incorporation or By-Laws of LPI, and do not and will
not contravene the
provisions of, or constitute a default under, any indenture,
mortgage, contract or other
instrument to which LPI is a party or by which LPI in bound, and
this Agreement constitutes
a legal, valid and binding obligation of LPI enforceable in
accordance with its terms, except
as limited by applicable bankruptcy, insolvency, reorganization,
or similar laws at the time
in effect.
(c) There are no actions, suits or proceedings
pending or to LPI's knowledge
threatened against or affecting LPI before any court or
administrative body or agency which
might materially affect the ability of LPI to perform its
obligations under this Agreement.
(d) EXCEPT AS EXPRESSLY SET FORTH IN THIS
AGREEMENT LPI
MAKES NO WARRANTY WHATSOEVER, EXPRESS OR IMPLIED, AS TO ANY
SOLID WASTE OR CONDENSATE, INCLUDING ANY WARRANTY OF
MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE.
(e) LPI has furnished or will furnish within a
reasonable time copies of the
resolutions of its Executive Committee authorizing the execution,
delivery and performance
of this Agreement by LPI, certified by the Secretary or an
Assistant Secretary of LPI and
such resolutions were duly and validly adopted, and are as of the
date hereof, true and
correct and in full force and effect.
10. ARBITRATION
10.1 Any dispute arising out or relating to this Agreement,
or the breach thereof, shall be
subject to resolution by arbitration, except antitrust claims or any claims
involving a third party and
based upon contribution, indemnification or damages based on tortious conduct
which shall not be
subject to arbitration under this Agreement.
10.2 Prior to initiation of arbitration, any dispute shall
first be referred by initial written
notice to the persons identified in Paragraph 14.4, specifying the nature of
the dispute and stating
that the party is meeting pursuant to this Paragraph for the purpose of
discussing and attempting
to resolve of the dispute. The parties will use their best efforts to
informally resolve any such
dispute as promptly as is reasonable after the date of any such notice.
However, if the dispute
cannot be resolved within twenty-one (21) Days of such initial notice, either
Party may initiate
arbitration. Any failure to initiate arbitration within forty (40) Days of
such initial notice shall be
deemed a waiver of the right to arbitrate. Any waiver shall not prejudice a
Party's right to arbitrate
a dispute which is substantively the same as the waived dispute, except that
they are based on facts
arising subsequently to the facts that give rise to the previous controversy
or claim.
10.3 NSP and LPI shall, within twenty (20) Days of service
of the notice of arbitration,
select and designate a qualified and independent professional arbitrator. The
two arbitrators selected
shall select and designate a third qualified and independent professional
arbitrator within twenty (20)
Days of their appointment. The arbitrators shall be competent by virtue of
education and experience
in the particular matter subject to the arbitration. The foregoing provision
shall not prevent the
Parties from agreeing to proceed with an arbitration with a single
arbitrator.
10.4 The arbitrators shall have jurisdiction and authority
to interpret, apply or determine
compliance with provisions of this Agreement insofar as shall be necessary
to the determination of
issues properly before the arbitrators. In making the decision, the
arbitrators shall issue appropriate
written findings and conclusions regarding the issues.
10.5 Any arbitration conducted under this Agreement shall be
conducted in accordance
with the Commercial Arbitration Rules of the American Arbitration Association
then in effect. The
arbitrators shall not have jurisdiction or authority to add to, detract from
or alter the provisions of
this Agreement or any applicable law or rule of civil procedure. The
arbitrators shall have the
authority to require either Party to specifically perform its obligations
under this Agreement. The
arbitration shall be closed to observation or monitoring by a third party
unless either Party requests
the arbitrators to allow third party presence, provided however that either
Party may call upon third
parties to present evidence at the arbitration hearing. The Parties agree to
be bound by the decision
of the arbitrators with respect to such request.
10.6 NSP and LPI shall pay the fees, costs and expenses of
the arbitrator it selects, and
split the fees, costs and expenses of the third arbitrator retained. In all
other disputes, each party
shall pay one-half the arbitrators' fees, costs and expenses incurred in
connection with any
arbitration of any matter hereunder. Each party shall pay its own employee's
costs, expert witness
and consultants and attorneys fees, as well as its costs of exhibits and
other incidental costs. If the
arbitrators find a party has unreasonably brought, or has unreasonably forced
the other party to
commence, an arbitration proceeding, the arbitrators shall order such party
to pay one-hundred
percent (100%) of fees, costs, and expenses.
10.7 Each party shall have the rights of discovery in the
manner provided under the rules
governing civil actions in the district courts of the State of Minnesota. All
discovery issues shall be
determined by order of the arbitrators upon motion made to them by either
party. when a party is
asked to reveal material which the party considers proprietary information
or trade secrets, the party
shall bring the matter to the attention of the arbitrators who shall make
such protective orders as are
reasonable or necessary or as are otherwise provided by law.
10.8 Pending the final decision of the arbitrators, NSP and
LPI agree to diligently proceed
with the performance of all obligations, including the payment of all sums,
required by this
Agreement.
10.9 Any decision, including orders arising out of disputes
as to the scope or
appropriateness of a request for, or response to discovery, of the
arbitrators may be enforced in a
district court with all costs, including court costs, paid by the party in
default or in error.
10.10 All arbitration proceedings shall take place in the
State of Minnesota. The arbitration
shall be held at a location agreed upon by NSP and LPI. In the event of
failure to agree,
the arbitrators shall determine the most convenient venue based on the
location of the majority of
the documentary evidence and prospective witnesses.
10.11 Except as may be necessary for any review by the
Minnesota Public Utilities
Commission or as otherwise required by law, no communications sent or
documents delivered by
either party because of a proceeding under this Section shall be disclosed
by the other party to a third
party if that communication or document contains the caption "Privileged and
Confidential-
Settlement Proceeding" or similar caption.
10.12 Except as may be necessary for any review by the
Minnesota Public Utilities
Commission or as otherwise required by law, a party who intends to disclose
such documents to a
third party shall provide at least ten (10) Days written notice to the other
party prior to disclosure
of such documents to the third party.
10.13 Except as may be necessary for any review by the
Minnesota Public Utilities
Commission or as otherwise required by law, the arbitrators' decision shall
be deemed to be a
settlement between the Parties and the decision shall be treated as a
settlement for all purposes in
the future.
10.14 This Article shall survive the termination of this
Agreement as necessary to resolve
any disputes.
11. REMEDIES
11.1 LPI acknowledges and agrees that LPI's remedy in the
event the Steam Supply
System is not Available as described in Paragraph 4.48, are liquidated
damages which are
calculated as follows: Damages for failure to meet Availability
requirements on an annual basis
will be calculated on an hourly basis up to seven (7) Days (168 hours) per
year. Damages for time
not Available greater than seven (7) Days (168 hours) will be calculated on
a daily basis. The
number of Days will be calculated by dividing the annual number of hours not
Available in excess
of one hundred and sixty-eight (168) by twenty-four (24), and rounding to the
nearest whole Day.
Damages will be assessed on an hourly basis up to a maximum of seven (7)
Days (168 hours) per
year. The hourly rate for calculating damages will be the Energy Charge per
thousand pounds times
eighty (80) thousand pounds (klbs.) per hour. Availability damages for
hours in excess of one
hundred and sixty-eight (168) hours per year will be assessed on a daily
basis up to a maximum of
thirty (30) Days per year. The daily rate for calculating damages will be
the Fixed Facility Charge
divided by three hundred and sixty-five (365). NSP shall credit LPI, within
thirty (30) Days of the
end of January of the following Fiscal Year, an amount equal to the damages
incurred.
11.2 LPI acknowledges and agrees that LPI's remedy in the
event the Steam Supply
System is not Available as described in Paragraph 4.53 are liquidated damages
which are calculated
as follows: Damages for failure to meet Availability requirements on an
annual basis will be
calculated on an hourly basis up to seven (7) Days (168 hours) per year.
Damages for time not
Available greater than 7 Days (168 hours) will be calculated on a daily
basis. The number of Days
will be calculated by dividing the annual number of not Available hours in
excess of one hundred
and sixty-eight (168) by twenty-four (24), and rounding to the nearest whole
Day. Damages will
be assessed on an hourly basis up to a maximum seven (7) Days (168 hours) per
year. The hourly
rate for calculating penalties is the Energy Charge per thousand pounds less
the fuel component
times eighty (80) thousand pounds (klbs.) per hour. Availability damages for
hours in excess of
one hundred and sixty-eight (168) per year will be assessed on a daily basis
up to a maximum of
fifteen (15) Days per year. The daily rate for calculating damages will be
the Fixed Facility Charge
divided by three hundred and sixty-five (365).
11.3 LPI acknowledges and agrees that LPI's remedy in the
event the Steam System is
not Available as described in Paragraphs 4.48 and 4.53 is suspension of the
Fixed Facility Charge,
calculated as follows: If the Steam Supply System is not Available for a
period of ten (10)
consecutive Days or greater, NSP agrees to credit LPI the value of the Fixed
Facility Charge,
calculated on a daily basis, for the duration of the suspension. If
suspension extends beyond one
hundred eighty (180) Days, LPI shall have the option to terminate the steam
supply portion of the
Agreement. If the interruption extends between two (2) Fiscal Years, the
annual Fixed Facility
Charge for the second year will not be due until the Steam Supply System
becomes Available. The
value of the Fixed Facility Charge owed for the second year will be
calculated by the number of
Days the Steam Supply System was not Available due to suspension multiplied
by the Fixed Facility
Charge, calculated on a daily basis. NSP and LPI agree to extend the term
of this agreement relating
to the purchase of steam by the number of Days the Agreement was suspended.
11.4 If as a result of the actions, omissions or fault of
NSP, NSP fails to comply with the
requirements of Paragraph 4.48 or Paragraph 4.53, as applicable, for two (2)
consecutive Fiscal
Years, LPI may terminate this Agreement as to the provisions relating to the
purchase of steam,
provided NSP has not provided LPI, within one hundred and eighty (180) Days
after receiving
written notice from LPI specifying LPI's intention to terminate, with
reasonable assurance that NSP
will meet the requirements of Paragraph 4.48 or Paragraph 4.53, as
applicable, for the remaining
term of this Agreement. LPI will not be required to pay the termination
charges specified in
Paragraph 13.1 if LPI terminates under this Section, and LPI shall be
entitled to pursue any legal
remedies that may be available to it under Minnesota law for breach of this
Agreement by NSP. In
the event LPI pursues legal remedies that may be available to it under
Minnesota law for breach of
this Agreement by NSP, NSP's liability for damages shall not exceed one
hundred thousand dollars
($100,000). Further, NSP liability for damages is expressly limited by
Paragraph 11.12. During
the 180-day period, representatives of LPI and NSP will meet and discuss
alternatives to termination
of the provisions of this Agreement relating to the purchase of steam.
11.5 If as a result of the actions, omissions or fault of
NSP, NSP fails to comply with
requirements of Paragraph 4.22 by the date specified therein, LPI may
terminate the provisions of
this Agreement relating to the purchase of steam provided NSP has not
achieved compliance within
one hundred and eighty (180) Days after receiving written notice from LPI
specifying LPI's
intention to terminate and identifying the specific failure. LPI will not
be required to pay the
termination charges specified in Paragraph 13.1 if LPI terminates under this
section. LPI will be
required to pay a Contracted Demand Charge for any capacity purchased by NSP
on LPI's behalf.
If NSP cannot establish to the reasonable satisfaction of LPI that it will
be able to comply with the
requirements of 4.22, LPI may upon notification to NSP proceed to install
whatever boiler capacity
it requires to meet its steam needs, at LPI's sole cost and expense.
11.6 If as a result of the actions, omissions or fault of
LPI, NSP fails to comply with
requirements of Paragraph 4.22 by the date specified therein, NSP may
terminate the provisions
of this Agreement relating to the purchase of steam provided LPI has not
allowed NSP to achieve
compliance within one hundred and eighty (180) Days after receiving written
notice from NSP
specifying NSP's intention to terminate and identifying the specific action,
omission or failure. LPI
shall pay the termination charges specified in Paragraph 13.1 if NSP
terminates under this section.
LPI shall pay the Contracted Demand Charge for any capacity purchased by NSP
on LPI's behalf
and any unpaid Energy Charge.
11.7 If as a result of the actions, omissions or fault of
NSP, NSP is unable to deliver the
maximum design steam flow of one hundred and eight (108,000) thousand pounds
per hour or the
maximum flow required by LPI, whichever is less, LPI shall pay the Fixed
Facility Charge and
Contracted Demand Charge reduced in proportion to the amount that the actual
maximum steam
flow, as measured by the NSP flow measurement equipment located upstream of
the Point of
Delivery in or near the LPI facility, as described on Exhibit B, is less than
the maximum design
steam flow or the maximum flow required by LPI, whichever is less, and any
unpaid Energy
Charge.
11.8 If as a result of the actions, omissions or fault of
LPI, NSP fails to comply with
requirements of Paragraph 4.22 by the date specified therein,NSP is unable
to deliver the maximum
design steam flow of one hundred and eight (108,000) thousand pounds per hour
or the maximum
flow required by LPI, whichever is less, LPI shall pay the Fixed Facility
Charge, Contracted
Demand Charge and any unpaid Energy Charge.
11.9 Provided timely written notice is given to LPI, NSP
shall not be liable for delays in
delivery, inability to deliver steam, or periods of when steam is not
Available, due to causes not
reasonably foreseeable by NSP which are beyond NSP's reasonable control, such
as acts of God,
acts of civil or military authorities, Government priorities, fires, strikes,
floods, epidemics, war or
riot.
11.10 If for any reason LPI fails or refuses to pay the
charges specified in this Agreement
for more than sixty (60) Days after they become due, except those portions
reasonably contested,
then in addition to the late payment charges provided in Paragraphs 4.33 and
5.8, NSP may
terminate this Agreement for default if LPI has not corrected such
delinquency within seven (7)
Days after written notice by NSP.
11.11 In the event NSP terminates this Agreement for default,
LPI shall remain liable for
all past due payments and the termination charges set forth in Paragraphs
13.1 and 13.2 , applicable
to the date of such termination.
11.12 In the event of termination of this Agreement by either
party or by expiration of the
term after any extension or renewal thereof, LPI shall, within sixty (60)
Days of such termination
notify NSP whether or not it desires to be granted title to that portion of
the Steam Supply System
located on the LPI facility. If LPI desires to be granted such title, NSP
shall within thirty (30) Days
of receipt of notice from LPI, deliver without cost or charge to LPI a bill
of sale granting and
transferring title to that part of Steam Supply System located on the LPI
facility "as is", free and
clear of any lien or encumbrance derived through NSP or any party other than
LPI. If LPI notifies
NSP that it does not desire to be granted such title, NSP shall within one
hundred eighty (180) Days
of receipt of such notice from LPI complete the removal from the LPI facility
of all parts of the
Steam Supply System located thereon. While removing the Steam Supply System
from the LPI
facility, NSP shall (a) exercise reasonable care and use its best efforts to
avoid damage to any
property of LPI and interference with LPI's operations at LPI's facility and
(b) leave LPI's facility
in at least as good condition, operating and otherwise as it was prior to
such tenancy, reasonable
wear and tear excepted. If NSP fails to remove the Steam Supply System within
the one hundred
eighty (180) Days time period hereunder, LPI may remove the Steam Supply
System at NSP's
cost.
11.13 Except as expressly stated elsewhere in this Agreement,
the remedies specified in
this Section are exclusive, and each party's liability for damages is
expressly limited by this Section.
Neither party will be liable, whether arising under contract, tort (including
negligence), or otherwise,
for loss of anticipated profits, prospective benefits or anticipated savings,
claims of customers, loss
of use of capital or revenue, or for any other special, indirect, incidental
or consequential loss or
damage of any nature arising at any time or from any cause whatsoever.
Notwithstanding this
paragraph the parties shall have the right to bring an action for specific
performance to enforce the
terms of this Agreement.
12. EXTENSION AND RENEWAL
12.1 The terms of this Agreement for the provision of steam,
natural gas or electricity
supply may be extended for a five (5) year period at LPI's option, provided
LPI shall give NSP
written notice of its intention to extend not less than six (6) months prior
to expiration of the terms
of this Agreement for the provision of steam, natural gas or electricity.
In the event LPI has paid
the entire amount of the Fixed Facility Charge, as described in Paragraph
4.50, no Fixed Facility
Charge shall be paid during any extended term.
12.2 LPI shall have the right to negotiate a renewal of the
terms of this Agreement for up
to an additional ten (10) year period beginning upon the expiration of the
terms and any extension
thereof as provided in Paragraph 12.1 by giving written notice to NSP not
less than twenty-four
(24) months prior to such expiration; provided, the Sherburne County
Generating Plant is at such
time and is in good faith projected by NSP to continue for such additional
period to be in existence
and operational to produce steam for the LPI facility.
13. TERMINATION
13.1 LPI may terminate this Agreement, as to those provisions
relating to the purchase
of steam after the Effective Date, by giving written notice to NSP, which
termination shall be
effective sixty (60) Days after receipt by NSP of written notice from LPI.
LPI shall pay NSP, within
ninety (90) Days following the Effective Date of termination, the unpaid
principle amount of the
Fixed Facilities Charge stated in Paragraph 4.50, any unpaid amount of the
Contracted Demand
Charge for the Fiscal Year in which the Agreement is terminated, and any
unpaid Energy Charges.
13.2 In the event LPI terminates those provisions relating
to the purchase of steam, LPI
shall be obligated to purchase natural gas from NSP, pursuant to Paragraph
4.56.
13.3 LPI may terminate this Agreement, as to those
provisions relating to the purchase
of electricity after the Effective Date, by giving written notice to NSP,
which termination shall be
effective sixty (60) Days after receipt by NSP of written notice from LPI.
LPI shall pay NSP, within
ninety (90) Days following the Effective Date of termination, that amount of
termination charge
prescribed in Exhibit F, applicable to the date of such termination and to
the nature of LPI's
termination.
13.4 In the sixty (60) Days after receipt of the written
notice of termination, NSP may
match the price and terms of any alternative electric supplier selected by
LPI to provide electric
service to the LPI facility. In the event NSP matches the price and terms,
the provisions relating to
the purchase of electricity shall not terminate and LPI shall purchase
electricity under the amended
price and terms.
13.5 In the event LPI terminates those provisions relating
to the purchase of electricity,
LPI shall not develop cogeneration or electricity generation capability at
the LPI facility or any
expansion or addition to the LPI facility. Backup generation to support the
LPI facility shall not be
considered electricity generation capability.
13.6 In the event LPI terminates those provisions relating
to the purchase of electricity,
LPI acknowledges and agrees NSP's agreement to provide access to the fire
protection water supply
of the Sherburne County Generating Plant, as described in Section 6, shall
terminate.
13.7 In the event LPI terminates those provisions relating
to the purchase of electricity,
LPI acknowledges and agrees NSP's agreement to provide solid waste disposal,
as described in
Section 7, shall terminate.
13.8 In the sixty (60) Days after receipt of the written
notice of termination of steam
supply, NSP may match the price and terms of any alternative steam supplier
selected by LPI to
provide steam to the LPI facility. In the event NSP matches the price and
terms, the provisions
relating to the purchase of steam shall not terminate and LPI shall purchase
steam under the
amended price and terms.
13.9 In the event LPI terminates those provisions relating
to the purchase of steam and/or
natural gas, LPI shall not develop cogeneration capability at the LPI
facility or any expansion or
addition to the LPI facility. Backup generation to support the LPI facility
shall not be considered
steam and/or natural gas generation capability.
13.10 In the event LPI terminates those provisions relating
to the purchase of steam and/or
natural gas, LPI acknowledges and agrees NSP's agreement to provide access
to the fire protection
water supply of the Sherburne County Generating Plant, as described in
Section 6, shall terminate.
13.11 In the event LPI terminates those provisions relating
to the purchase of steam and/or
natural gas, LPI acknowledges and agrees NSP's agreement to provide solid
waste disposal, as
described in Section 7, shall terminate.
14. MISCELLANEOUS
14.1 Neither NSP nor LPI shall release to the press or to the
general public any
information concerning the execution, existence, contents, performance or
breach of this Agreement,
except as may be required in any legal or regulatory proceeding, without
first obtaining the written
consent of the other party.
14.2 NSP and LPI will do, execute, acknowledge and deliver
all such further acts,
conveyances and instruments as the other reasonably shall require for
accomplishing the purpose
of this Agreement.
14.3 No forbearance on the part of either party in enforcing
its rights under this
Agreement shall constitute a waiver of any terms of this Agreement, or a
forfeiture of any such
rights.
14.4 All notices, requests, demands and other communications
required by or necessary
to this Agreement shall be in writing. Notice shall be deemed to have been
given when delivered
by hand or deposited in the United States mail, certified with return receipt
requested, postage paid,
addressed to the appropriate party at its respective mailing address as set
forth immediately below:
David Lenzen Ronald Elsner, Project Engineer
Ronald Lifson Northern States Power Company
Liberty Paper, Inc. Sherburne County Generating Plant
5600 North County Road 18 13999 Industrial Boulevard
New Hope, MN 55428 Becker, MN 55308
Either party to this Agreement, by notice to the other party as required
above, may change its
address for the purpose of all future communications.
14.5 This Agreement shall be binding upon and inure to the
benefit of the successors and
assigns of the parties hereto. Each party may assign this Agreement,
provided, however, such
assignment shall not relieve the assignor of its obligations hereunder unless
the other party consents
to such assignment. Such consent shall not be unreasonably withheld.
14.6 It is agreed that without regard for the place where
this Agreement was made it shall
be governed by and construed, in all respects, in accordance with the laws
of the State of Minnesota
applicable to sales contracts made and to be performed in said state.
14.7 This Agreement is contingent upon approval, as
necessary, by the Minnesota Public
Utilities Commission. NSP and LPI shall use their best efforts to receive
approval of this
Agreement by February 1, 1994. In the event approval is not received by
February 1, 1994, NSP
and LPI shall meet within thirty (30) Days and determine whether to proceed
with the obligations
of this Agreement. After the meeting either party may terminate this
Agreement within thirty (30)
Days of meeting. In the event of termination, LPI will not be obligated to
pay NSP a termination
charge as stated in Paragraphs 13.1 or 13.3; however, as soon as practicable
after such termination
NSP shall submit to LPI a written statement identifying the actual
out-of-pocket costs incurred by
NSP through the termination date in constructing or preparing for
construction of the Steam
Delivery System, and LPI shall pay to NSP fifty percent (50%) of those costs
within sixty (60) Days
after notice of termination.
14.8 In the event that the Minnesota Public Utilities
Commission does not approve the
terms and conditions of this Agreement relating to the purchase and sale of
steam, or if the
Minnesota Public Utilities Commission determines that additional costs must
be allocated by NSP
to the sale of steam hereunder, LPI may terminate this Agreement as to those
provisions relating to
the purchase of steam by giving written notice to NSP which termination shall
be effective
immediately upon receipt by NSP of the written notice from LPI. If LPI so
terminates the provisions
of this Agreement relating to the purchase and sale of steam, LPI will not
be obligated to pay NSP
a termination charge as stated in Paragraphs 13.1 or 13.3; however, as soon
as practicable after such
termination NSP shall submit to LPI a written statement identifying the
actual out-of-pocket costs
incurred by NSP through the termination date in constructing or preparing for
construction of the
Steam Delivery System, and LPI shall pay to NSP fifty percent (50%) of those
costs within sixty
(60) Days after notice of termination.
14.9 If LPI determines not to proceed with construction of
the LPI facility due to its
inability to obtain financing or permits or any other reason reasonably
beyond its control, LPI may
terminate this Agreement by giving written notice to NSP, which termination
shall be effective
immediately upon receipt by NSP of the written notice from LPI; provided,
however, LPI may not
terminate this Agreement pursuant to this paragraph at any time after
February 1, 1994. If LPI so
terminates this Agreement, LPI will not be obligated to pay NSP a termination
charge as stated in
Paragraphs 13.1 or 13.3; however, as soon as practicable after such
termination, NSP shall submit
to LPI a written statement identifying the actual out-of-pocket costs
incurred by NSP through the
termination date in constructing or preparing for construction of the Steam
Delivery System, and
LPI shall pay to NSP fifty percent (50%) of those costs within sixty (60)
Days after notice of
termination.
14.10 This Agreement is contingent upon approval, as
necessary, by the Board of Directors
of NSP.
14.11 This Agreement is contingent upon approval, as
necessary, by the Board of Directors
of LPI.
14.12 This Agreement contains all of the understandings of the
parties hereto and
supersedes and replaces all prior written or oral agreements between them
relating to the subject
matter herein. This Agreement may not be amended or modified except in
writing signed by an
authorized representatives of NSP and LPI.
14.13 It is understood and agreed that NSP and LPI will
exercise good faith in the
performance and enforcement of the contractual obligations contained herein.
NSP and LPI will
attempt to disputes through good faith negotiations. During such
negotiations, NSP and LPI shall
continue to perform their respective contractual obligations.
14.14 As to any proprietary or trade secret information
received or obtained by either NSP
or LPI, or by its agents, employees or representatives from the other party
or such party's agents,
employees or representatives, in connection with the negotiation or
performance of this Agreement
and which is so designated as proprietary or trade secret information, the
party so receiving or
obtaining such information (herein referred to as the "Recipient") shall
maintain the confidentiality
thereof and shall use the same degree of care in so doing as the Recipient
uses in respect of its own
trade secrets and other confidential information, provided that such degree
of care shall in all events
be that reasonably necessary to maintain the confidentiality of such
information. The requirement
hereunder that the Recipient maintain the confidentiality of information
shall extend to all agents.
employees and representatives thereof and the Recipient shall assure that
such agents, employees
and representatives similarly maintain such confidentiality. Notwithstanding
the foregoing, the
following information shall not be subject to the requirement that the
Recipient thereof maintain the
confidentiality thereof:
(a) information that is or becomes part of the
public knowledge or literature
without the fault of the Recipient or any of its agents, employees
or representatives;
(b) information that is or becomes Available to
the Recipient from a source other
than the other party hereto or such other party's agents,
employees or representatives;
(c) information that is independently developed
by the Recipient without access
to information which is required hereunder to be maintained as
confidential;
(d) information that must be disclosed by
Recipient or any of its agents,
employees or representatives pursuant to court order or any law,
rule or regulation imposed
by any governmental instrumentality or agency; or
(e) information disclosed by either or both of the
parties with written
authorization of the other party.
14.15 The purpose of this Agreement is to provide for and
facilitate the sale of steam and
electricity by NSP to LPI and this Agreement is not intended, nor shall it
be deemed to create a
partnership, joint venture or similar relationship between NSP and LPI.
14.16 NSP shall maintain adequate supporting records for
verification of price components,
fire protection water supply installation and construction costs and, in the
event of termination of
steam supply pursuant to Paragraphs 14.7 through 14.9, actual out-of-pocket
costs in constructing
or preparing for construction of the Steam Delivery System. NSP shall
preserve such records for
the term of this Agreement and allow access to them by independent third
party auditors appointed
by LPI.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement
to be executed by
their duly authorized officers as of ___ day of October, 1993.
LIBERTY PAPER, INC.
By:____________________________________
DAVID LENZEN
Senior Vice President of Finance
NORTHERN STATES POWER COMPANY
By:_____________________________________
EDWIN M. THEISEN
President and Chief Operating Officer
By:_____________________________________
LEON R. ELIASON
President, NSP Generation
EXHIBIT A
Exhibit A is a LPI Site Location Drawing. It is a line drawing which shows
the approximate location of the Sherburne County Generating Plant and related
facilities, i.e. Unit 3 dry ash landfill, Unit 3 cooling towers, Unit 1 and
2 cooling towers, substation, recycle basin, bottom ash pond, fly ash pond,
scrubber solids ponds, elk river ash landfill and Becker substation. The
line drawing also shows the proposed location of the LPI facility on Tracts
I and II which are designated in the Agreement and the proposed location of
the steam line and fire protection line. Finally, the line drawing shows the
location of the City of Becker and the City of Becker Industrial Park. The
locations are approximate and the drawing is not to scale.
EXHIBIT B
Exhibit B is a Steam Supply Diagram which identifies the components in the
Steam Supply System which are located at the Sherburne County Generating
Plant and at the LPI facility. The components identified at the Sherburne
County Generating Plant include the Unit 1 and 2 Boiler Buildings and the
main steam and cold reheat lines, and the Unit 1 and 2 Condensers and flow
meters. The components identified at the LPI facility include the control
valves, desuperheater, metering stations, relief valves and manual isolation
valves. In addition, the LPI facility includes the desuperheat spray pumps,
condensate return tanks, condensate return pumps and the condensate quality
monitoring station. The points of delivery are identified as the manual
isolation valve prior to the LPI process and the condensate return tank prior
to the LPI process. The drawing is a schematic and is not an actual
representation.
NSP/LPI
SHERBURNE COUNTY
ENERGY SUPPLY AGREEMENT
EXHIBIT C
Condensate Return Chemistry Requirements
Ph 9.0 to 9.5
Specific Conductivity 5.0 to 11.p uomho/cm
Cation Conductivity 0.30 umho/cm Max.
Dissolved Oxygen 5 ppb Max. if returned to DA Storage Tank
Dissolved Oxygen 25 ppb Max. if returned to Deaerator
Silica 7 ppb as Si02 Max. no condensate polishing
Iron 8 ppb as Fe Max. no condensate polishing
Sodium 3 ppb as Na Max. no condensate polishing
Chloride 2 ppb as C1 Max. no condensate polishing
Sulfate 10 ppb as SO4 Max. no condensate polishing
Total Organic Carbon <200 ppb (ZERO OIL)
Copper <1ppb as Cu
Exhibit D: Page 1 of 2
NSP/LPI Sherburne County Energy Supply Agreement
NORTHERN STATES POWER COMPANY (MINNESOTA)
ELECTRIC RATE BOOK - MPUC NO.1 Sheet No: 5- 19
MINNESOTA Revision: 15th
GENERAL SERVICE
Availability: Available to any non-residential customer for general
service.
Rate:
Customer Charge per Month $21.55
Oct-May June-Sept
Service at Secondary Voltage:
Demand Charge per Month
All Kw - per Kw $ 6.21 $ 8.47
Energy Charge per Kwh 2.91 cents
January - December
Per Kw Per Kwh
Voltage Discounts per Month:
Primary Voltage $ .75 .06 cents
Transmission Transformed Voltage $ 1.50 .10 cents
Transmission Voltage $ 2.00 .13 cents
Interim Rate Adjustment: An interim rate adjustment of 5.36% shall be added
to billings for electric service.
Fuel Clause: Bills subject to the adjustment provided for in Fuel Clause
Rider No. 1
Surcharge: In certain communities bills are subject to a surcharge provided
for in Surcharge Rider.
Late Payment Charge: Any unpaid balance over $10.00 is subject to a 1.5%
late payment charge or $1.00, whichever is greater. The charge may be
assessed four working days after the date due.
Determination of Demand: The adjusted demand in kilowatts for billing
purposes shall be determined by dividing the maximum actual demand in
kilowatts by the power factor expressed in percent but not more than a 90%
power factor and multiplying the quotient so obtained by 90% and rounding
to the nearest whole Kw. In no month shall the demand to be billed be
considered as less than:
1.) Current month's adjusted demand in Kw, or
2.) 50% of the greatest monthly adjusted demand in kW during the preceding
eleven months.
But in no month shall the billing demand be greater than the value in kW
determined by dividing the kWh sales for the billing month by 75 hours per
month.
The greatest monthly adjusted demand in kW during the preceding eleven months
shall not include the additional demand which may result from customer's use
of standby capacity contracted for under the Standby Service Rider.
Maximum Demand: The maximum actual demand in kilowatts shall be the greatest
15-minute load during the month for which bill is rendered.
Rate Code
Transmission
Secondary Primary Transformed Transferred
Small DK004 DK014 DK024 DK034
Large GK004 GK014 GK024 GK034
Filing Date: 11-2-92 By: Keith H. Wietecki Effective: 1-1-93
Vice President, Electric Marketing & Sales
MPUC Docket No. E002/GR-92-1185 Order Date: 12-31-92
Exhibit D: Page 2 of 2
NSP/LPI Sherburne County Energy Supply Agreement
NORTHERN STATES POWER COMPANY (MINNESOTA)
ELECTRIC RATE BOOK - MPUC NO. 1 Sheet No:5-20
MINNESOTA Revision:13th
GENERAL SERVICE (Continued)
Power Factor: For three phase customers with services above 200 amperes or
above 480 V, the power factor for the month shall be determined by
permanently installed metering equipment.
For all single phase customers and three phase customers with services 200
amperes or less, a power factor of 90% will be assumed.
Off-Season Load Service: The optional Off-Season Load Service is available
under this schedule subject to the provision contained in the Off-Season
Load Rider.
Standby Service: Standby Service is available under this schedule subject
to the provisions contained in the Standby Service Rider.
Competitive Service: Competitive Service is available under this schedule
subject to the provisions contained in the Competitive Service Rider.
Minimum Demand to be Billed: The monthly minimum billing demand shall not
be less than provided above.
Split Service: When approved by Company, customer's service may be split
between General Service and General Time of Day Service rates. Only
Company approved storage space cooling and storage space heating equipment
qualifies for the General Time of Day Service portion of a Split Service
installation. The thermal storage equipment shall be permanently wired,
separately served and metered, and at no time connected to the General
Service portion of the Split Service installation. Each portion of
customer's Split Service installation will be considered separately for all
other rate application purposes.
Terms and Conditions of Service:
1. Alternating current service is provided at the following nominal
voltage:
a. Secondary voltage: Single or three phase from 208v up to but not
including 2,400v,
b. Primary voltage: Three phase from 2,400v up to but not include
69,000v,
c. Transmission Transformed Voltage: Three phase from 2400v up to but
not including 69,000v, where service is provided at the Company's
disconnecting means of a distribution substation transformer,
d. Transmission voltage: Three phase at 69,000v or higher.
Service voltage available in any given case is dependent upon
voltage and capacity of Company lines in vicinity of customer's
premises.
2. Transmission Transformed Service is available only to customers
served by an exclusively dedicated distribution feeder. Customer
will be responsible for the cost of all facilities necessary to
interconnect at the Company's disconnecting means of a distribution
substation transformer.
3. Transmission Service is available at transmission voltage, subject
to the terms and conditions contained in the Company's General Rules
and Regulations, Section 5.1.B.
4. Customer selecting General Service will remain on this rate for a
period of not less than twelve months.
5. If a customer has a billing demand of less than 25 kW for twelve
consecutive months, he will be given the option of returning to the
Small General Service schedule.
Filing Date: 1-28-91 By: Keith H. Wietecki Effective: 4-30-92
Vice President, Electric Marketing & Sales
MPUC Docket No: E002/GR-91-001 Order Date: 5-4-92
NSP/LPI
SHERBURNE COUNTY
ENERGY SUPPLY AGREEMENT
EXHIBIT E
SPECIFICATION FOR ACCEPTANCE SOLID WASTE
(Proximate Analysis)
Expected
Average Maximum Minimum
BTU/lb 5,000-5,500 n/a 5,000
Ferrous Metals 1.00%
Glass 3.50%
Moisture 40.00%
Non-Ferrous Metal .75%
Rigid Particle Size 12"x12"
Ash(dry) 15%
95% of all solid Waste delivered to the NSP RDF-Fueled Generating Plants
shall be less than 6 inches in any dimension. LPI shall attempt to the best
of their abilities to avoid delivery of material that includes excessively
long and fibrous material. In the event that such long fibrous material is
delivered, the NSP RDF-Fueled Generating Plants shall accept and process such
materials at the sole discretion of NSP. If NSP determines that it is not
feasible to process such materials, NSP shall reject the materials. LPI
shall be responsible for costs and associated with the disposal of any such
rejected materials, including but not limited to handling, transportation,
and landfill costs.
NSP/LPI
SHERBURNE COUNTY
ENERGY SUPPLY AGREEMENT
EXHIBIT F
Termination Charges for Electricity Supply
AMOUNT
YEAR DUE NSP
1 $1,468,820
2 $1,435,006
3 $1,398,334
4 $1,358,563
5 $1,315,432
6 $1,268,657
7 $1,217,928
8 $1,162,913
9 $1,103,250
10 $1,038,545
11 $968,372
12 $892,270
13 $809,737
14 $720,230
15 $623,159
16 $517,886
17 $403,718
18 $279,903
19 $145,624
20 $0
NSP DEFERRED COMPENSATION PLAN
(Restated As Amended Through January 1, 1992)
TABLE OF CONTENTS
SECTION TITLE PAGE
1 Name of Plan 1
2 Obligations of Participating Employers 1
3 Purpose of the Plan 1
4 Definitions 1
5 Persons Eligible to Participate 3
6 Annual Election 3
7 Deferral Options 5
8 Regular Deferred Compensation Accounting 8
9 Adjustments and Payments for Diminution 9
of Other Benefits
10 Distribution of Accounts 15
A. Normal Distribution 15
B. Hardship Distributions 17
C. Distribution upon Death 18
D. Lifetime Distribution of Certain
Pension-Related Payments
11 Beneficiaries and Alternate Payees 20
A. Beneficiaries 20
B. Alternate Payee's Beneficiary 21
C. Presumptions 22
D. Waiver of Interest 22
E. Benefits Unassignable 23
F. Assignments Pursuant to a QDRO 23
12 Amendment and Termination 23
13 Administrative Provisions 24
A. Committee 24
B. Facility of Payment 24
C. Source of Payment 25
D. Claims Procedure 26
E. Right to Withhold Payment 27
F. Applicable Law 28
G. Number 28
H. Employment Rights 28
ADDENDUM
The Wealth-Op Program and its separate table of contents immediately
follows Section 13.
WEALTH-OP DEFERRED BENEFIT ADDENDUM
TO
NSP DEFERRED COMPENSATION PLAN
TABLE OF CONTENTS
SECTION TITLE PAGE
Introduction W-1
WEALTH-OP PROGRAM W-3
W1 Definitions W-3
W2 Employee Deferrals W-6
W3 Deferred Benefit Accounts W-9
W4 Normal Benefit W-11
W5 Uncompleted Benefit Units W-12
W6 Termination Benefit W-14
W7 Termination of Participation in
Wealth-Op Program W-15
W8 Survivor Benefit W-15
A. Death While in Service
Prior to Age 55 W-15
B. Death While in Service
After Age 55 W-17
C. Death After Retirement W-18
W9 Disability Benefit W-19
W10 Deferral of Payment W-23
W11 Recipients of Payments;
Designation of Beneficiary W-23
W12 Aggregation of Payments W-24
W13 Protective Provisions W-24
W14 Offset W-25
W15 Termination of Wealth-Op W-25
Program
NSP DEFERRED COMPENSATION PLAN
(Restated As Amended Through January 1, 1992)
Section 1. Name of Plan. This is the NSP Deferred Compensation
Plan (the "Plan") of
Northern States Power Company, a Minnesota corporation (the "Company"), and
other Participating
Employers. The Plan was adopted by the Company effective December 18, 1980,
and is set forth herein
as amended through January 1, 1992. This restatement of the Plan is
effective as of January 1, 1992,
unless otherwise specifically provided.
Section 2. Obligations of Participating Employers. Payments shall
be made only by the
Participating Employer which last employed the Participant before payments
commence, but each
Participating Employer agrees to reimburse the paying Participating Employer
for the deferrals and
additions that accrued during the period a payee was in their respective
employment. Elections made
to one Participating Employer are binding on the electing Participant and any
other Participating
Employer who later becomes the Participant's employer.
Section 3. Purpose of the Plan. The purpose of the Plan is to
enable Eligible Employees
of the Participating Employers to defer a portion of the compensation to
become due to them for the
purpose of supplementing their retirement and disability income.
Section 4. Definitions. For the purposes of the Plan, the
following words and phrases
shall have the meanings indicated as follows:
"Alternate Payee" is a person or entity entitled to receive all or
a portion of the
Participant's benefits under the Plan pursuant to a qualified
domestic relations order as
defined in Section 11.
"Beneficiary" means the person, persons, trust or estate designated
by a Participant or
otherwise entitled under Section 11 of the Plan to receive
distribution of the
Participant's benefits under the Plan in the event of the
Participant's death prior to full
receipt thereof.
"Code" refers to the Internal Revenue Code of 1986, as amended.
"Committee" means the committee of at least three persons appointed
by the Chief Executive
Officer or President of the Company to administer the Plan as
provided in Section 13(A).
"Company" means Northern States Power Company, a Minnesota
corporation.
"Eligible Employees" are employees described in Section 5.
"ERISA" refers to the Employee Retirement Income Security Act of
1974, as amended.
"ESOP" means the Northern States Power Company Employee Stock
Ownership Plan, as from time
to time amended.
"Executive Leadership Group" means those employees of Participating
Employers who have been
designated by the Company as members of the Executive Leadership
Group.
"Fixed Income Option" means the method for crediting a Regular
Deferred Compensation
Account described in Section 7(C)(1).
"NSP Phantom Stock Option" means the method for crediting a Regular
Deferred Compensation
Account described in Section 7(C)(2).
"Officer" means an officer of a Participating Employer who has been
determined by the
Company to be a "principal officer."
"Participant" means an Eligible Employee who participates in the
Plan as described in
Section 6.
"Participating Employer" means the Company; Northern States Power
Company, a Wisconsin
corporation; NRG Energy Inc., a Delaware corporation; and any other
subsidiary or
affiliated corporation of the Company which elects to participate
in the Plan with the
consent of the Company.
"Pension Plan" means the Northern States Power Company Pension
Plan, as from time to time
amended.
"Plan" means the NSP Deferred Compensation Plan.
"Plan Year" means January 1 through December 31.
"Regular Deferred Compensation Account" means an account created
for a Participant under
Section 8 of the Plan.
"Retirement Savings Plan" means the Northern States Power Company
Retirement Savings Plan -
- Nonunion, as from time to time amended.
"Wealth-Op Program" refers to all the provisions of the Wealth-Op
Deferred Benefit Addendum
to the Plan which provides for a deferral option under the Plan.
Section 5. Persons Eligible to Participate. An "Eligible
Employee" is a full-time benefit
employee of a Participating Employer who is, or by January 1 of the next year
will be, an Officer or
a member of the Executive Leadership Group. Notwithstanding the foregoing,
an employee is not eligible
to participate in the Plan for any calendar year during which the employee
is not included within a
"select group of management or highly compensated employees" as determined
under final or temporary
regulations promulgated by the U.S. Department of Labor for the purposes of
Section 301(a)(3) of ERISA.
Section 6. Annual Election.
(A) On or before November 15, 1988, and on or before November 15
of each year thereafter,
each Eligible Employee desiring to participate in the Plan for the ensuing
year shall file a written
election with respect thereto with the Secretary of the Company or a designee
appointed by such
Secretary. (The Company may permit an Eligible Employee to make this
election after November 15, but
in no event later than December 31, of any year if the Company, in its sole
and absolute discretion,
determines that the Eligible Employee was unable to make a timely election
for reasons beyond the
Eligible Employee's control.) Upon such an election, the Eligible Employee
shall be classified as a
"Participant." However, any Eligible Employee who becomes entitled to a
benefit under Section 9 shall
automatically thereupon become a "Participant."
(B) An election may be made for only the ensuing year, except as
otherwise provided
beyond the ensuing year, and shall designate the amount of compensation,
expressed in a dollar amount
of not less than $100 per month, to be earned by such Participant which shall
be deferred and paid to
the Participant as provided in this Plan. Such amount may not reduce regular
compensation to an amount
below the contribution and benefit base in effect for the applicable future
year under Section 230 of
the Social Security Act; provided, that the Company, in its sole discretion,
may waive this restriction
for any year. The restriction in the preceding sentence shall be applied pro
rata if employment during
a year is less than 12 months. In addition, or alternatively, the
Participant may elect to defer any
increase in the Participant's regular compensation from a Participating
Employer which becomes
effective during such ensuing year. For elections made in 1989, no
Participant may defer more than
a cumulative amount equal to ten percent per annum of annual base pay
projected for 1990 plus the
aggregate regular base pay received from the Participating Employers for all
years during which the
Participant was eligible to participate in this Plan, less the amount
actually deferred by the
Participant in prior years. No incentive pay, severance pay, or other
compensation which is not part
of regular compensation may be deferred.
(C) All deferrals shall be credited to the Regular Deferred
Compensation Account under
Section 8 of the Plan or the Wealth-Op Deferred Benefit Account under the
Wealth-Op Deferred Benefit
Addendum in the month it would otherwise have been paid to the Participant.
Amounts credited to
Regular Deferred Compensation Accounts shall be governed by Sections 7, 8,
9 and 10 of this Plan.
Amounts credited to Wealth-Op Deferred Benefit Accounts shall not be subject
to Sections 7, 8, 9 and
10 except as may be specifically provided by the provisions of the Wealth-Op
Deferred Benefit Addendum
to the NSP Deferred Compensation Plan.
(D) An election made prior to November 15 for an ensuing year can
be changed at any time
before November 15 of that calendar year to be effective for such ensuing
year. After November 15 of
any year, elections in effect for the following year are irrevocable and the
Participant shall have
no right to receive any amount elected for deferral, except pursuant to this
Plan.
Section 7. Deferral Options.
(A) As further deferred earnings, a Participant's Regular Deferred
Compensation Account
shall be credited as of the end of each month with a sum certain based on the
options set forth in this
Section 7 in accordance with the provisions of Sections 8(B) and 8(C).
(B) A Participant may elect an option for all or a portion of the
deferments at the time
of the annual election under Section 6; provided that effective for elections
made for years after
1990, the amounts deferred pursuant to Section 6 for which a Participant may
elect the NSP Phantom
Stock Option shall be limited to a cumulative amount equal to:
(1) 10% per annum of:
(a) the Participant's current annual base pay projected for
the applicable year;
plus
(b) the Participant's aggregate regular base pay for all such
years during which the
Participant was eligible to participate in this Plan; less
(2) the amounts previously deferred for which the NSP Phantom Stock
Option was actually
elected by the Participant in all such years.
No change in the option may be effective for the calendar year in which the
change is made.
Prospective changes may be made as provided in Section 8(C). In the event
the Participant fails to
designate an option for any deferred amounts, the Company shall credit the
account as though the Fixed
Income Option had been designated.
(C) The options available for a Participant's Regular Deferred
Compensation Account are
as follows:
(1) Fixed Income Option. Upon the election of the "Fixed Income
Option", the
Participant's deferred compensation account, or the designated
portion thereof, will
be treated as though an amount equal to the monthly amount of
deferred compensation
were placed in the fixed income option (guaranteed interest
contract) of the
Retirement Savings Plan at the same time as employee
contributions to that Plan are
credited thereto. The deferred compensation account will be
credited with additions
equal to the amount of income which would have been earned if
such account were
invested in the Fixed Income Account of the Retirement Savings
Plan. If the election
is not changed, the deferred compensation account will be
credited in succeeding
years in the same manner.
(2) NSP Phantom Stock Option. Upon the election of the "NSP
Phantom Stock Option" the
Participant's deferred compensation account, or the designated
portion thereof, will
be treated as though deferred amounts were received by the
Company as an optional
cash payment in the Company's Dividend Reinvestment and Stock
Purchase Plan, (the
"DIR Plan"). The current monthly deferrals if any, of the
Participant shall be
credited at the same time they would have been if they were
contributed by payroll
deduction as an optional cash payment to the DIR Plan. Such
deferred compensation
account will reflect the number of whole and fractional shares
of NSP common stock
which would have been acquired with such cash at the time of
such assumed optional
cash payments to the DIR Plan. Such deferred compensation
account will be credited
with additions equal to the amount of shares of common stock
which would have been
acquired if cash dividends equal to those paid on the amount
of common stock credited
to the account had been automatically invested under the DIR
Plan. If the election
is not changed, the deferred compensation account, or the
designated portion thereof,
will be credited in the succeeding year with additions as
provided above. The value
of the sum so deferred, at the time of any payment, shall be
equal to the number of
dollars represented by the "Investment Price" of the shares
of common stock credited
to the account as of the "Investment Date." "Investment
Price" shall be a price
equal to the reported closing price of the NSP common stock
on the New York Stock
Exchange as reported in the Wall Street Journal for the New
York Stock Exchange-
Composite Transactions as of the Investment Date preceding the
payment. "Investment
Date" is the twentieth day of each month if that date is a New
York Stock Exchange
trading day and a closing price is reported, or the first
succeeding date for which
a closing price is reported in said Composite Transactions.
(D) Notwithstanding the foregoing, amounts credited to a
Participant's Regular Deferred
Compensation Account pursuant to Sections 9(D) or 9(E) shall be credited in
accordance with the Fixed
Income Option, and no other options will be available.
(E) Notwithstanding anything in the Plan to the contrary, the
Company reserves the right
to take any action with respect to transactions involving the NSP Phantom
Stock Option that the
Company, in its sole discretion, deems necessary or advisable to prevent any
violation of federal or
state securities laws.
Section 8. Regular Deferred Compensation Accounts.
(A) The Company shall establish and maintain, in the name of each
Participant, an
individual account, to be known as a Participant's Regular Deferred
Compensation Account, to which the
deferred earnings under Sections 6, 7, and 9 (other than earnings credited
to the Wealth-Op Deferred
Benefit Accounts) shall be credited. Separate subaccounts shall be created
if part of the account is
being deferred under Section 7(C)(1) and part is being deferred under Section
7(C)(2), or if amounts
are credited to the account pursuant to Section 9(D).
(B) Until the entire balance of a Participant's Regular Deferred
Compensation Account
is distributed, the account will be adjusted at least annually, as of the end
of each month, to reflect
amounts accruing to the account balance under Section 7, provided that
effective as of the first day
of the year following termination of employment, Section 7(C)(1) will be
applied even if
Section 7(C)(2) previously applied in whole or in part.
(C) Subject to the limitations set forth in Section 7(B), a
Participant may elect to have
all or a portion of the Participant's account or subaccount balance,
determined as of the end of the
year, accrue deferred earnings under another Section 7 option for the ensuing
year. Such adjustments
will be effective as of the first day of the year following the requested
adjustment. Any adjustments
which accrue under Section 7(C)(1) of any amount previously accrued under
Section 7(C)(2) shall be
based on the Investment Price of the common stock allocated to such Section
7(C)(2) account as of the
Investment Date (see Section 7(C)(2)) preceding the effective date of such
account adjustment. In the
event the valuation of the Section 7(C)(2) account is necessary before the
end of a year due to a
distribution of the account, the Investment Date will be the 20th day of the
month preceding the month
distribution commences.
Section 9. Adjustments and Payments for Diminution of Other
Benefits.
(A) Amounts deferred by Participants shall not be deemed to be
compensation for the
purpose of allocations to the qualified retirement plans of the Company. In
addition, amounts paid
to a Participant as incentive pay are not taken into account in determining
a Participant's benefits
under certain of the Company's qualified retirement plans, and the Code
places limitations on the
amount of a Participant's compensation that may be taken into account in
determining the Participant's
benefits under said plans. To avoid any significant reduction in the value
of a Participant's overall
retirement benefits because of an election to defer compensation, because of
the payment of
compensation in the form of incentive pay, or because of limitations on
compensation imposed by the
Code, the Company shall increase deferred earnings by increasing a
Participant's Regular Deferred
Compensation Account and providing monthly payments as provided in this
Section.
(B) As of the end of each year, the Company shall adjust the
Regular Deferred
Compensation Account of a Participant to reflect the approximate dollar
amount, if any, such
Participant would have been allocated under the ESOP if compensation had not
been deferred. No
adjustments will be made to reflect any reduction in the amount of
contributions which but for the
deferral the Participant could have elected to make or directed the Company
to make on behalf of the
Participant to the ESOP or the Retirement Savings Plan, such as a voluntary,
matching, or pay
conversion contribution.
(C) Participants shall receive a monthly payment under the Plan
equal to the difference,
if any, between the monthly annuities payable to the Participant under the
Pension Plan and the NSP
Excess Benefit Plan, and the monthly annuities that would have been payable
under the Pension Plan and
the NSP Excess Benefit Plan if deferred compensation was taken into account
in determining the
Participant's benefits under said plans. If a Participant dies while
receiving such payments, the
Participant's surviving spouse, if any, shall be entitled to continued
payments as provided in Section
10(D). If a Participant's surviving spouse receives a "Spouse's Benefit"
under the Pension Plan as
a result of the Participant's death prior to retirement, the Company shall
pay to the surviving spouse
a monthly amount equal to the difference, if any, between the monthly annuity
payable to such surviving
spouse under the Pension Plan and the NSP Excess Benefit Plan, and the
monthly annuities that would
have been payable under the Pension Plan and the NSP Excess Benefit Plan if
deferred compensation was
taken into account in determining the Participant's benefits under said
plans. If benefits are paid
to any Participant (or spouse) from Supplemental Benefits under the NSP
Optional Disability Plan, the
Company will make similar payments each month to reflect the reduction, if
any, in the amount of
benefits payable because deferred compensation did not qualify as "monthly
basic compensation."
(D) For each Plan Year commencing on or after January 1, 1989, the
Regular Deferred
Compensation Account of a Participant who is a member of the Executive
Leadership Group shall be
increased by a percentage of the amounts paid to the Participant in such Plan
Year pursuant to a
Participating Employer's annual incentive compensation plan. For each Plan
Year commencing on or after
January 1, 1990, the Regular Deferred Compensation Account of a Participant
who is an Officer shall
be increased by a percentage of the amounts paid to the Participant in such
Plan Year pursuant to a
Participating Employer's annual incentive compensation plan. (Amounts paid
to Participants pursuant
to a Participating Employer's annual incentive compensation plans are
referred to herein as "Incentive
Pay.") Such increases shall be determined by the Company in its sole
discretion for each Plan Year,
and shall be for the purpose of providing benefits that will approximate the
additional benefits the
Participants would have received from the Pension Plan if the Participants'
Incentive Pay for such Plan
Year had been taken into account in calculating the Participants' Pension
Plan benefits. Increases
under this Section 9(D) shall be credited to the Participant's Regular
Deferred Compensation Account
as of the dates on which the Participant receives payment of the Incentive
Pay to which the increases
relate.
(E) An additional amount shall be credited to the Regular Deferred
Compensation Account
of a Participant listed on Schedule A if, on the date the Participant's
employment terminates with all
Participating Employers, the Company determines that the increases credited
to the Participant pursuant
to Section 9(D) do not adequately replace the additional benefits the
Participant would have received
from the Pension Plan and the NSP Excess Benefit Plan if the Participant's
Incentive Pay had been taken
into account in calculating the Participant's benefits under said plans.
Such additional amount shall
be equal to the excess of:
(1) the then present value (determined as provided in Section 9(H))
of the additional
benefits the Participant would have received from the Pension Plan and
the NSP Excess Benefit
Plan if the Participant's Incentive Pay had been taken into account in
calculating the
Participant's benefits under said plans; over
(2) the balance of the subaccount established to record the amounts
credited to the
Participant's Regular Deferred Compensation Account pursuant to Section
9(D) on the date the
Participant's employment terminates with all Participating Employers.
(F) Effective January 1, 1989, any reduction in the monthly
annuity payable to the
Participant (or spouse) under the Pension Plan caused by the maximum annual
benefit limitations imposed
by Section 415 of the Internal Revenue Code of 1986, as amended, will be
taken into account in
determining benefits provided under the NSP Excess Benefit Plan. In
addition, Officers of the Company,
of Northern States Power Company, a Wisconsin corporation, and of NRG Energy
Inc. shall receive a
monthly payment under this Plan equal to the amount, if any, of the reduction
in the monthly annuity
payable to such Officer (or to such Officer's spouse) under the Pension Plan
and the NSP Excess Benefit
Plan because compensation taken into account in determining the Participant's
benefits under said plans
did not include compensation which would have been taken into account, but
for a limitation imposed
by the Code on the maximum amount of compensation which can be used for
determining an individual's
benefits under a qualified defined benefit pension plan.
(G) The Committee has the sole discretion to establish the method
of determining the amount
of adjustments to Regular Deferred Compensation Accounts, and the amount of
payments to Participants
and their surviving spouses, pursuant to this Section 9. Such methods may
vary from year to year as
long as all similarly situated Participants are adjusted or paid under the
same method throughout a
particular year. Notwithstanding anything in this Section 9 to the contrary,
no adjustments to the
Regular Deferred Compensation Account of a Participant are required under
Sections 9(D) or 9(E), and
no payments to a Participant or surviving spouse shall be required under
Sections 9(C) or 9(F), if the
Participant's employment terminates (for any reason other than death) prior
to the date the Participant
becomes eligible for Normal, Early, Late, or Disability Retirement under the
Pension Plan, but the
Company may make adjustments or payments at its discretion on an individual
basis.
(H) A Participant may elect to receive in a lump sum the present
value of all payments
attributable to Sections 9(C), 9(D), 9(E) and 9(F). Any such election will
apply only to payments
based on compensation earned in Plan Years beginning after the Plan Year in
which the election is made,
it will be irrevocable as to payments based on compensation earned in the
Plan Years during which it
remains in effect, and it will remain in effect until revoked by a new
election. If the same election
has not been made for every year, the portion of the payments attributable
to Sections 9(C), 9(E) and
9(F) that will be paid in a lump sum will be determined by the Company in a
consistent manner which
reasonably reflects the period during which the lump sum election was in
effect. The initial election
by a Participant shall be irrevocable until the Participant attains age 50.
(For purposes of the
preceding sentence, a Participant who has not filed a written distribution
election will not be deemed
to have made an initial election.) The present value shall be determined at
the sole discretion of
the Committee applying an interest rate based on the interest rate being
applied by the Pension Benefit
Guaranty Corporation for valuing immediate annuities at January 1 of the year
in which such
determination is being made, as further referenced in the Pension Plan. No
election under this Section
9(H) changes the payments provided in Section 10(D) to the extent the
adjustments or payments under
Sections 9(C), 9(D), 9(E) and 9(F) relate to service prior to 1989. Payment
of a lump sum elected
pursuant to this Section 9(H) shall be made on the date as of which payments
to the Participant would
have begun under Section 10(A).
Section 10. Distribution of Accounts.
(A) Normal Distribution.
(1) Except as otherwise provided in Section 9(H) and this Section
10, a Participant's
Regular Deferred Compensation Account will be distributed to the Participant
in 180 substantially equal
monthly installments commencing on the last day of January following the
calendar year in which the
Participant's employment terminates with all Participating Employers. The
amount of each monthly
installment paid during a particular Plan Year shall be the monthly amount
the Company, in its
discretion, determines is necessary to pay the Participant's Regular Deferred
Compensation Account
balance as of the end of the immediately preceding Plan Year, plus projected
adjustments pursuant to
Section 8(B), in substantially equal installments over the remainder of the
payment period. The
Company may at any time adjust the monthly payments to conform to a new
estimate of a Participant's
account additions. The Company may also increase the monthly payment amount
and reduce the number of
installment payments to the extent necessary to ensure that each installment
(when added to any other
periodic payments due under the Plan, including Wealth-Op) will equal at
least $500 per month. (For
payments to a surviving spouse, the minimum monthly payment shall be $250
instead of $500.)
(2) Without regard to the foregoing, if so designated by the
Participant in the deferral
election, the Participant may irrevocably elect to have payments relating to
such deferral election
begin the last day of January following the later of (1) the date the
Participant attains age 65 or
(2) the date on which the Participant's employment terminates with all
Participating Employers;
provided, that such an election shall not be effective if the Participant's
employment terminates
before the Participant is eligible for Normal, Late, Early or Disability
Retirement under the Pension
Plan.
(3) If a Participant's termination of employment entitles the
Participant to receive cash
payments under the NSP Severance Plan, and the Participant's Eligible Benefit
Date (as defined in
Section W1 of the Wealth-Op Deferred Benefit Addendum) occurs during the
period for which such payments
are being made, the Participant will not be considered to have terminated
employment with all
Participating Employers for purposes of this Section 10(A) until such
Eligible Benefit Date.
(B) Hardship Distributions.
(1) Prior to termination of employment or at any time after
distribution commences, a
Participant may make a written request to the Company to distribute the
Participant's Regular Deferred
Compensation Account (exclusive of any payments attributable to Section 9(C)
or Section 9(F)) at a
different time or in a different manner, including in a lump sum payment or
by installments which vary
from those set forth in Section 10(A) above. Such request may be directed
to the Company's President
or to the Vice President in charge of the Human Resources Department.
(2) The request shall be reviewed by a committee of at least three
active employees of
the Participating Employers (Committee), which Committee shall be the
Committee as provided in Section
13, or by another committee delegated by such Committee to act on requests
for special distribution
of Regular Deferred Compensation Accounts. No employee appointed to such
Committee shall act on a
request by such employee as a Participant.
(3) The Committee shall review each request, which may be
supplemented by further oral
or written communication with the Participant and, in its sole discretion,
shall determine whether
to grant the request in whole or in part and direct distribution accordingly.
The request should be
granted if the Committee believes the Participant will suffer a financial
hardship if the request is
not granted, but the Participant shall have no right to appeal or dispute the
Committee's absolute
discretion in deciding the matter. The foregoing shall not exclude the
Participant from renewing a
denied request in a subsequent calendar year, or resubmitting a denied
request setting forth new or
additional justification for the same. No person in the employ of a
Participating Employer shall be
eligible for a financial hardship distribution and no person may receive a
financial hardship
distribution after retirement, except to meet a financial hardship caused by
casualty loss or by
illness, injury or death of the Participant, spouse or dependent as described
below for a former
employee. No former employee may obtain a distribution for financial
hardship for at least six months
after termination of employment. Financial hardship shall be the inability
of the former employee to
meet financial obligations originally incurred while employed or to meet a
financial emergency caused
by an extraordinary and unforeseeable casualty loss or brought about by the
death or the sudden and
unexpected illness or injury of the former employee, spouse or dependent (as
defined in Section 152(a)
of the Code) which the former employee (or spouse) cannot meet with current
income or by liquidation
of assets to the extent the liquidation of assets would not in itself cause
severe financial hardship.
Payments shall not be made in excess of the amount needed to satisfy the
financial hardship.
(C) Distribution upon Death. Upon the death of a Participant, the
Participant's Regular
Deferred Compensation Account shall be distributed to the Participant's
Beneficiary. If the
Beneficiary is the Participant's spouse, the distribution shall be paid to
such spouse in the same
manner as it was being paid, or would have been paid, to the Participant
including a right of such
spouse to request a special distribution under Section 10(B). In all other
cases, the distribution
of the account shall be made in a lump sum to the Beneficiary within 30 days
after the Company receives
acceptable proof of Beneficiary status and receives necessary proof of
address and identity.
(D) Lifetime Distribution of Certain Pension-Related Payments.
If no lump sum payment
as provided in Section 9(H) was elected, the monthly payments, if any,
required by Sections 9(C) and
9(F) shall be made to the Participant for life and, if survived by a spouse
receiving a monthly benefit
from the Pension Plan, such surviving spouse shall receive one-half of the
Participant's monthly
payment for as long as payments continue to the spouse under the Pension
Plan. The monthly payments
may be added directly to monthly payments, if any, being made under the prior
provisions of this
Section 10. If the monthly benefit payment payable under the preceding
sentence should at any time
be in an amount less than $500 per month, the benefit payments can be
adjusted so as to be payable
every other month or other periodic interval, but not less than annually,
which will result in each
payment (other than an annual payment) being in an amount of $500 or more.
For payments to a surviving
spouse, the minimum monthly payment will be $250 instead of $500. Section
7 additions will not be
applied to any payments generated by Section 9(C) or 9(F). If no other
monthly payments are being
made, or to be made, under this Plan, and if the present value of any benefit
payable under this
Section 10(D) is less than $5,000, the Participating Employer shall pay the
present value of such
benefit to the Participant (or spouse) in a single lump sum in lieu of any
further benefit payments
hereunder. Present value will be calculated as provided in Section 9(H).
Section 11. Beneficiaries and Alternate Payees.
(A) Beneficiaries. Except when a death benefit is payable only
to a surviving spouse,
a Participant may designate a Beneficiary (which may be more than one person
or entity) to whom
distribution of such Participant's Regular Deferred Compensation Account
and/or Wealth-Op Deferred
Benefit Account shall be made in the event of the Participant's death prior
to the full receipt
thereof. Such a designation may be changed or revoked by the Participant at
any time without notice
to the Beneficiary. The designation of any Beneficiary and any change or
revocation thereof shall be
made in writing and delivered to the Company prior to the death of the
Participant. If no Beneficiary
is designated, if a designation is revoked in whole or in part, or if a
designated Beneficiary shall
not survive to receive all payments due hereunder, all or such part of the
Participant's accounts as
have not been distributed shall be payable to the first class of the
following classes of automatic
Beneficiaries then surviving and (except in the case of surviving issue) in
equal shares if there are
then more than one in each class: (1) Participant's widow or widower; (2)
Participant's surviving issue
per stirpes; (3) Participant's surviving parents; (4) Participant's surviving
brothers and sisters;
(5) executor or administrator of Participant's estate. For the purpose of
the foregoing, "per stirpes"
means in equal shares among living children and the issue of deceased
children, the latter taking by
right of representation. "Issue" means all persons who are descended from
the person referred to,
either by legitimate birth to or legal adoption by such person, or any of
such person's legitimately
born or legally adopted descendants. A Beneficiary or surviving spouse who
intentionally causes the
death of the Participant shall be deemed to have not survived the Participant
for purposes of all
distributions. The foregoing provisions of this Section shall not preclude
the designation of a
Beneficiary's estate or other contingent Beneficiaries in the event the first
designated Beneficiary
does not survive to receive full payment. (If the Beneficiary is the spouse,
and the spouse dies
before full distribution, the account balance shall be distributed to the
next then surviving
contingent Beneficiary of the deceased Participant; provided that if the
Participant by will or other
written designation gave the spouse by power of appointment or otherwise the
power to select the
Beneficiary upon death of the spouse, the distribution shall be to the
Beneficiary designated in
writing by the spouse if the spouse files such designation with the Company
before the death of the
spouse.)
(B) Alternate Payee's Beneficiary. In regard to the account of
an Alternate Payee, the
Alternate Payee may designate a Beneficiary, or, in lieu thereof, shall have
a Beneficiary determined
by the Plan, in the same manner as though the term "Alternate Payee" were
substituted for the term
"Participant" in Section 11(A) above.
(C) Presumptions. If a Beneficiary, including a surviving spouse,
and the Participant
die under circumstances where it is not known who died first, it will be
presumed, for the purpose of
this Section 11, that the Participant survived the Beneficiary. If the
Company is unable to locate
an automatic or designated Beneficiary (other than a surviving spouse) within
six months after death,
or within 60 days prior to the contemplated initial distribution of the
decedent's account, whichever
date shall last occur, the Beneficiary as of that date shall be deemed to
have waived the Beneficiary's
right to receive a distribution from the Plan. The distribution which would
otherwise have been made
to such Beneficiary shall then be made from the Plan to the contingent
Beneficiary(ies) then surviving
as though such Beneficiary did not survive the decedent. A surviving spouse
who cannot be located
within two years of the decedent's death shall be presumed to have not
survived the decedent, and
distribution of the decedent's account shall be made to the contingent
Beneficiary(ies) surviving at
the time of distribution.
(D) Waiver of Interest. If a Beneficiary, including a surviving
spouse, waives all right
to receive distribution from the Plan in writing delivered to the Company,
the distribution shall be
made to the contingent Beneficiary(ies) surviving at the time of
distribution. In addition, if the
Beneficiary's Social Security number or other information required for
distribution is not delivered
to the Company within the time designated (not less than 30 days) in a
written notice sent by the
Company to the last known address of the Beneficiary, the Beneficiary shall
be deemed to have waived
the Beneficiary's right to receive distribution from the Plan.
(E) Benefits Unassignable. Except for assignment to an Alternate
Payee as hereafter
permitted, to the extent permitted by law, no Participant or Beneficiary
shall have any transferrable
interest in a Regular Deferred Compensation Account or a Wealth-Op Deferred
Benefit Account before or
after such an account is being distributed; the right of any such Participant
or Beneficiary to any
payment before the actual receipt thereof hereunder shall not be subject in
any manner to attachment
or other legal process or debts or other legal obligations of such
Participant or Beneficiary; and any
such interest in the account or payment therefrom shall not be subject to
anticipation, alienation,
sale, transfer, assignment or encumbrance.
(F) Assignments Pursuant to a QDRO. Section 11(E) shall not apply
to amounts payable
to an Alternate Payee pursuant to a qualified domestic relations order
satisfying the requirements of
Section 206(d) of ERISA. The Company shall establish reasonable procedures
to determine the qualified
status of domestic relations orders and to administer distributions under
such orders.
Section 12. Amendment and Termination. The Company reserves the
right to amend or
terminate this Plan without notice to or consent of Participants. Any such
amendment or termination
shall be set forth in writing and executed by the President or any Vice
President and attested by the
Secretary or any Assistant Secretary of the Company. It shall transmit any
such amendments to other
Participating Employers. Each other Participating Employer reserves the
right to withdraw from
participation in this Plan, but until such withdrawal occurs, they shall be
bound by the Plan as
originally established and as amended from time to time. The Company
expressly reserves the right to
retroactively amend the Plan if the Company determines that such amendment
is necessary to maintain
the tax qualified status of any other retirement plan maintained by a
Participating Employer, or if
the amendment is not adverse to the Participants.
Section 13. Administrative Provisions.
(A) Committee. This Plan shall be administered by the Company.
The Company may act
through a committee of at least three persons appointed by the Company's
Chief Executive Officer or
President, which committee shall be designated and known as the "Deferred
Compensation Committee."
The appointment of the Committee shall be by written designation on file in
the office of the Secretary
for the Company. The Committee may delegate any or all of its administrative
authority. The Committee
shall have the power to interpret and resolve all questions arising under the
Plan and to adopt such
rules and policies as it deems necessary for the administration of the Plan.
(B) Facility of Payment. In case of incompetency of a Participant
or Beneficiary
entitled to receive any distributions under the Plan, and if the Committee
shall be advised of the
existence of such condition, the Committee shall direct distribution to occur
to any of the following:
(1) To the duly appointed guardian or other legal representative
of such Participant or
Beneficiary;
(2) To any person designated as a Beneficiary by the Participant
if such Beneficiary
resides in the same household as the Participant;
(3) To a person or institution entrusted with the care and
maintenance of the incompetent
Participant or Beneficiary, provided such person or
distributed interest will be used
for the best interest and assist in the care of such
Participant or Beneficiary, and
provided further, that no prior claim for said payment has
been made by a legal
representative of such Participant or Beneficiary.
Any distribution made in accordance with the foregoing provisions of this
Section shall constitute a
complete discharge of any liability or obligation on the part of the
Participating Employers or the
Committee under the Plan.
(C) Source of Payment. Any payments pursuant to this Plan shall
be payable out of
operating funds of the Participating Employers. Nothing contained herein
shall be deemed to create
a trust of any kind or create any fiduciary relationship. Funds credited
hereunder shall for all
purposes be part of the general funds of the Participating Employers, and no
person other than
Participating Employers shall, by virtue of this Plan, have any interest in
such funds; provided that
the Company may, in its sole and absolute discretion, create a trust of the
type commonly known as a
"rabbi trust" and may transfer funds or property to such trust for the
purpose of facilitating the
Participating Employers' obligation to make payments pursuant to the Plan.
Any funds or property so
transferred shall be subject at all times to the claims of the Participating
Employers' general
creditors. To the extent that any person acquires a right to receive payment
from the Participating
Employers under this Plan, such right shall be no greater than the right of
any unsecured general
creditor of the Participating Employers.
(D) Claims Procedure.
(1) If a Participant or other person with a claim for payments
under the Plan makes a
written request for a payment or a claim for a greater payment, the
Participating Employer responsible
for such payment shall treat it as a claim for benefits. All claims for
benefits shall be directed
to the officer in charge of the Human Resources Department or equivalent
department of the
Participating Employer. If the Participating Employer determines that any
individual who has claimed
a right to receive benefits under the Plan is not entitled to receive all or
any part of the benefits
claimed, it will inform the claimant in writing of its determination and the
reasons therefor in terms
calculated to be understood by the claimant. The notice shall make specific
reference to the pertinent
Plan provisions on which the denial is based, and describe any additional
material or information, if
any, necessary for the claimant to perfect the claim and the reason any such
additional material or
information is necessary. Such notice shall, in addition, inform the
claimant what procedure the
claimant should follow to take advantage of the review procedures set forth
below in the event the
claimant desires to contest the denial of the claim.
(2) The claimant may within 90 days thereafter submit, in writing
to the officer in
charge of the Participating Employer's Human Resources Department, a notice
that the claimant contests
the Participating Employer's denial of the claim and desires a further
review. The Participating
Employer shall review the claim within 60 days thereafter, and authorize the
claimant to appear
personally and review pertinent documents and submit issues and comments
relating to the claim to the
persons responsible for making the determination on behalf of the
Participating Employer. The
Participating Employer will render its final decision with the specific
reasons therefor in writing
and will transmit it to the claimant within 60 days of the written request
for review, unless the
claimant and the Participating Employer have agreed to an extension of time.
(E) Right to Withhold Payment. Each Participating Employer
reserves the right to
withhold authorization of any distribution of a Regular Deferred Compensation
Account or a Wealth-
Op Deferred Benefit Account until it receives any information reasonably
required of it for the
administration of the Plan from the person to whom the distribution is
apparently payable. Each
Participating Employer further reserves the right to suspend distribution of
a Regular Deferred
Compensation Account or a Wealth-Op Deferred Benefit Account to a Participant
or Beneficiary until any
monetary claims of the Participating Employers against the Participant have
been resolved by judicial
action or by written agreement with the Participant. Any such action or
agreement may forfeit all or
a portion of such deferred accounts in settlement of such claim.
(F) Applicable Law. This Plan shall be governed by and construed
in accordance with the
laws of the State of Minnesota, except to the extent the same are superseded
or preempted by applicable
federal law.
(G) Number. Except when otherwise indicated by the context, the
definition of any term
herein in the singular may also include the plural.
(H) Employment Rights. The establishment of the Plan shall not
be construed as
conferring any legal rights upon any employee or any other person for a
continuation of employment,
nor shall it interfere with the rights of any Participating Employer to
discharge any employee and/or
to treat such employee without regard to the effect which such treatment
might have upon such employee
as a Participant.
* * * * *
SCHEDULE A
PARTICIPANTS ENTITLED TO INCREASES
UNDER SECTION 9(E)
Craig Blair Arland Brusven Tony Schuster
Ron Clough Jim Cox Vince Beacom
Jim Doudiet Jim Howard Glenn Thorsen
Rollie Jensen Gary Johnson Pat Watkins
Bill Lynch Jim McIntyre James Tacheny
Hazel O'Leary Dave Peterson Chuck Larson
Roger Sandeen Larry Taylor Edwin Theisen
Keith Wietecki John Noer
WEALTH-OP DEFERRED BENEFIT ADDENDUM
TO
NSP DEFERRED COMPENSATION PLAN
INTRODUCTION
This WEALTH-OP DEFERRED BENEFIT ADDENDUM (hereinafter the
"Wealth-Op Program") is part of
the NSP DEFERRED COMPENSATION PLAN (the "Plan"), and constitutes a deferral
option available to
Participants under the Plan. Participants in the Plan may elect, to the
extent permitted hereunder,
to have future deferrals invested in the Wealth-Op Program and/or to
"rollover" or transfer a lump sum
amount from the Participant's other deferred compensation accounts maintained
under the Plan which are
invested in the Fixed Income Option and/or the NSP Phantom Stock Option to
the Wealth-Op Program.
The Wealth-Op Program was first adopted in 1984 and was
significantly changed in
1987. The Wealth-Op Program, as amended, consists of two separate parts to
allow the accumulation
of deferrals under the elections made before 1987 and to allow new elections
for deferrals after 1987.
For convenience, the original Wealth-Op Program (relating to Wealth-Op
deferral elections filed before
1987) will sometimes be referred to as "Wealth-Op I Program" and the amended
Wealth-Op Program
(relating to Wealth-Op deferral elections filed after January 1, 1987) as the
"Wealth-Op II Program."
Unless the context otherwise clearly implies, references to "the Wealth-Op
Program" will relate to
elections under either the original or amended program, provided that in
every event, the Wealth-Op
I Program shall not apply to any deferral elections filed after January 1,
1987.
Any amount which is invested by the Participant in a completed
Benefit Unit under
the Wealth-Op Program may not thereafter be transferred to be held for
investment under any other
deferred compensation account or deferral option which is available under the
Plan, unless the
Participant elects to terminate the Participant's entire participation in the
Wealth-Op Program. All
amounts which are invested in the Wealth-Op I Program shall be paid to the
Participant and/or the
Participant's Beneficiary pursuant to the Wealth-Op I Program and all amounts
which are invested in
the Wealth-Op II Program shall be paid to the Participant and/or the
Participant's Beneficiary pursuant
to the Wealth-Op II Program.
The terms of the Wealth-Op Program option under the Plan are
set forth herein.
Except as specifically provided herein, the provisions of Sections 7, 8, 9
and 10 of the Plan shall
not apply to the Wealth-Op Program. In the event of any inconsistency
relating to the Wealth-Op
Program between the provisions of the Plan and this Addendum establishing the
Wealth-Op Program, the
provisions of this Addendum shall govern. Section 9 adjustments and payments
will be made whether a
Participant elects a Section 7 option or the Wealth-Op Program, but increases
to a Participant's
Regular Deferred Compensation Account pursuant to Sections 9(D) and 9(E) of
the Plan cannot be deferred
to the Wealth-Op Program, and other adjustments pursuant to Section 9 of the
Plan to a Participant's
Regular Deferred Compensation Account cannot be deferred to the Wealth-Op
Program except as a
"rollover" election as provided in Section W2.
WEALTH-OP PROGRAM
Section W1. Definitions.
The definitions contained in the Plan shall also apply for the
purposes of this
Addendum which shall govern the Wealth-Op Program. In addition, for the
purposes of the Wealth-Op
Program, the following words and phrases shall have the meanings indicated
and, unless the context
clearly implies otherwise, the singular includes the plural:
Benefit Unit. "Benefit Unit" means each separate unit of
investment by a Participant
under the Wealth-Op Program. A separate Benefit Unit shall
exist with respect to
the Total Deferral Amount associated with each separate annual
election or special
"rollover" election. An "Uncompleted Benefit Unit" means a
Benefit Unit for which
the Participant has not completed deferrals of the "Total
Deferral Amount" upon
attainment of the Participant's Retirement Date.
Committee. "Committee" means the Deferred Compensation
Committee appointed to
administer the Plan pursuant to Section 13 of the Plan.
Company's Declared Rate. The "Company's Declared Rate" is a
rate established
annually for each year by the Company based on its calculation
of its overall
weighted average after-tax rate of return on rate base allowed
in its most recent
Minnesota rate case.
Determination Date. "Determination Date" means the date on
which the amount of a
Participant's Wealth-Op Deferred Benefit Account is determined
as provided in Section
W3(A) hereof. The last day of each Plan Year shall be a
Determination Date.
Disability. "Disability" means any termination of service
which the Committee, in
its complete and sole discretion, determines is by reason of
a Participant's total
and permanent inability due to sickness or injury, to engage
in any gainful
occupation for which the Participant is reasonably qualified
in consideration of the
Participant's training, education, experience and/or prior
average earnings. It
shall be the duty of the Participant to submit medical and
other evidence to support
a claim for Disability, but the Committee may require the
Participant to submit to
an examination by a competent physician or medical clinic
selected by the Committee.
On the basis of such medical evidence, the determination of
the Committee as to
whether or not a condition of total and permanent disability
exists shall be
conclusive. To constitute Disability, the same must be
continuous for at least six
months and must commence while the Participant is in the
active service of a
Participating Employer and a Participant in the Wealth-Op
Program.
Eligible Benefit Date. "Eligible Benefit Date" means the date
upon which the
Participant becomes eligible for normal or early retirement
under the Pension Plan
(or would have become eligible for early retirement in the
case of an earlier
disability retirement under the Pension Plan).
Fixed Rate. The "Fixed Rate" refers to the Interest Yield
based on 120% of the ten-
year rolling average of ten year United States Treasury Notes
yield determined as
of the last day of December preceding each Plan Year as
published by the Federal
Reserve Board.
Interest Yield. "Interest Yield" for the purposes of the
Wealth-Op II Program means
an effective annual rate equal to either (i) 120% of the
ten-year rolling average
of ten-year United States Treasury Notes yield determined for
each Plan Year as of
the prior December 31, as published by the Federal Reserve
Board (the Fixed Rate),
or (ii) as if invested in one or more funds selected by the
Company in the
proportions elected by the Participants, less an annual
administrative fee, if any,
provided that the election is in at least 20% increments (the
Variable Rate);
provided, however, after the death of the Participant, the
Interest Yield for
purposes of the Wealth-Op II Program shall be annually
adjusted to be equal to the
Company's Declared Rate.
"Interest Yield" in regard to the Wealth-Op I Program means
an effective annual rate
equal to the published monthly average for each month of
Moody's Seasoned Corporate
Bond Yield Index as determined from Moody's Bond Record
published by Moody's
Investor's Service, Inc. (or any successor thereto), or if
such index is no longer
published, a substantially similar average selected by the
Committee, plus 3% per
annum, or such higher annual interest yield as the Committee
may determine.
Retirement Date. For purposes of the Wealth-Op Program,
"Retirement Date" means the
date of Termination of Service of the Participant subsequent
to the Participant's
Eligible Benefit Date.
Survivor Benefits. "Survivor Benefits" refers to the benefits
payable under Section
W8 upon the death of a Participant.
Termination of Service. "Termination of Service" means the
Participant's ceasing
service with the Participating Employers for any reason
whatsoever, whether voluntary
or involuntary, except death; provided, however, that if a
Participant's termination
of employment entitles the Participant to receive cash
payments under the NSP
Severance Plan and the Participant's Eligible Benefit Date
occurs during the period
for which such payments are being made, the Participant's
Termination of Service
shall not be deemed to have occurred until the earlier of the
Participant's Eligible
Benefit Date or the Participant's death.
Total Deferral Amount. "Total Deferral Amount" means the
total aggregate deferral
amount which the Participant has agreed to invest with respect
to a particular
Benefit Unit under the Wealth-Op Program.
Variable Rate. The "Variable Rate" refers to the Interest
Yield that would have been
produced if invested in one or more funds selected by the
Company in the proportions
elected by the applicable Participant, less an annual
administrative fee, provided
that the election is in at least 20% increments.
Wealth-Op Deferred Benefit Account. "Wealth-Op Deferred
Benefit Account" means one
of the accounts maintained on the books of account of the
Company for each
Participant with respect to each Benefit Unit under the
Wealth-Op Program. A
Participant's Wealth-Op Deferred Benefit Account shall be
calculated pursuant to
Section W3 and shall be utilized solely as a device for the
measurement and
determination of the amounts to be paid to the Participant
pursuant to the Wealth-
Op Program. A Participant's Wealth-Op Deferred Benefit
Account shall not constitute
or be treated as a trust fund of any kind. Accounts with
respect to the Wealth-
Op I and Wealth-Op II Programs shall be maintained separately
and for convenience
may be referred to as the "Wealth-Op I Deferred Benefit
Account" and "Wealth-Op II
Deferred Benefit Account."
Section W2. Employee Deferrals.
(A) All elections for the Wealth-Op Program filed before 1987
relate to the Wealth-
Op I Program and all elections filed after January 1, 1987, relate to the
Wealth-Op II Program.
Subject to the limitations set forth in this Section W2, each Participant may
elect the Wealth-Op
Program as an option for all or a portion of the Participant's deferments
under the Plan either in (i)
an annual election made under Section 6 of the Plan or (ii) a special
"rollover" election made at such
time or times and in such manner as the Committee may permit. Each election
constitutes an agreement
by the Participant to make the entire deferral indicated on the election
form.
(B) The annual election shall permit a Participant to elect
to defer for investment
in the Wealth-Op Program a specified annual dollar amount for a period of
either four or eight years
or such other period as the Committee may permit. A Participant may not
elect to defer for a period
of time extending beyond the date on which the Participant plans to retire,
but may elect to defer a
specified amount for a number of months lasting until the Participant's
planned retirement date if it
is less than four or eight years from the beginning of such deferrals. The
annual dollar amount shall
be deferred in equal amounts on a monthly basis or as otherwise may be
determined by the Committee.
For elections after January 1, 1987, the minimum annual deferral amount which
may be invested in any
Benefit Unit under the Wealth-Op II Program shall be as follows:
Age 40 and under: $2,700
Age 41-50: $3,900
Age 51-60: $5,500
Age 61-65: $6,400
("Age" is determined as of January 1 following the election using nearest
birthday.) The Committee
may modify the minimum Total Deferral Amount for all Participants relating
to a particular election
without amending the Plan. A Participant who has previously made an election
to invest deferrals in
the Wealth-Op Program will be permitted to complete such deferrals on an
accelerated basis over a
shorter period at such times and in such manner as may be permitted by the
Committee. Each election
to defer for investment in a Wealth-Op Program Benefit Unit must be paid in
full by a Participant who
remains an employee of any Participating Employer. If a Participant who
remains an employee fails to
complete deferrals for any Benefit Unit, then the Participant will receive
only the Termination Benefit
described in Section W6 with respect to such deferrals.
(C) The maximum deferral amounts for a Participant electing
an Interest Yield based
on the Fixed Rate shall be $20,000 per year for a four-year election and
$10,000 per year for an eight-
year election, or such other amount as may be specified from time to time by
the Committee. For
Participants electing an Interest Yield based on the Variable Rate, no
maximum shall apply unless
otherwise determined by the Committee and as communicated by the Company
before elections are made in
any particular calendar year.
(D) The special "rollover" election shall permit a
Participant to transfer a lump-
sum amount from one or more other deferred compensation accounts or
subaccounts maintained for the
Participant under Section 8 of the Plan to the Wealth-Op II Program, except
that a subaccount
established to record amounts credited to a Participant pursuant to Sections
9(D) or 9(E) cannot be
rolled over to the Wealth-Op Program. The minimum "rollover" amount which
may be invested in any
Benefit Unit shall be as follows:
Age 40 and under: $11,000
Age 41-50: $15,000
Age 51-60: $22,000
Age 61-70: $29,000
("Age is determined as of January 1 following the election using nearest
birthday.) The Committee may
from time to time modify the above dollar limitations for all prospective
"rollover" elections. The
Committee may refuse to allow a "rollover" in excess of the amount a
Participant contemplating
retirement needs to meet deferral commitments on any Uncompleted Benefit
Unit.
(E)Every
annual election and special "rollover" election shall specify the "Total
Deferral Amount" covered by
the election, which shall mean the total aggregate deferral amount which the
Participant has agreed
to invest in the Wealth-Op Program pursuant to that election, i.e., in the
case of an election of a
four year deferral the aggregate amount to be deferred for all four years.
A separate "Benefit Unit"
shall exist with respect to the "Total Deferral Amount" associated with each
separate annual election
or special "rollover" election.
(F) Amounts deferred by a Participant under the Wealth-Op
Program during a Plan
Year shall be credited to the Participant's Wealth-Op Deferred Benefit
Account not later than the last
day of the applicable Plan Year or at such earlier time as the Committee may
determine.
(G) All deferral elections under the Wealth-Op II Program
must designate the
elected Interest Yield. The designation of the Variable Rate or the Fixed
Rate is irrevocable and the
Participant cannot later switch from one to the other. In the Variable Rate,
the Participant may elect
one or more of the "mirrored" investment funds as long as each election is
for an increment of at least
twenty percent. In addition, the Participant may prospectively elect in
writing, as to each Benefit
Unit for which the Variable Rate was elected, to change the previously
elected "mirrored" investments,
subject to the 20% minimum for each increment. Such a re-election by the
Participant cannot be made
more than four times in a Plan Year. In addition such a re-election must be
on a form provided by the
Company and the changes requested will be effective as soon as possible, but
within ten business days
after receipt by the Company's Human Resources Department.
Section W3. Deferred Benefit Accounts.
(A) As of each Determination Date, a Participant's Wealth-Op
Deferred Benefit
Account shall consist of the balance of such Wealth-Op Deferred Benefit
Account as of the immediately
preceding Determination Date plus any amounts contributed to such Wealth-Op
Deferred Benefit Account
since the immediately preceding Determination Date minus all distributions,
if any, made from such
Wealth-Op Deferred Benefit Account since the preceding Determination Date.
As of each Determination
Date, a Participant's Wealth-Op Deferred Benefit Account shall be increased
by the amount of interest
earned since the preceding Determination Date based upon the Interest Yield
as provided in Section W1
and as elected by the Participant as provided in Section W2(G). Interest
based on the elected Interest
Yield shall be credited to the Wealth-Op Deferred Benefit Account at least
annually, in a manner to
be determined by the Committee in its sole discretion, based on the Interest
Yield applicable to the
particular Wealth-Op Deferred Benefit Account since the last preceding
Determination Date. The
Committee, in its sole discretion, shall also determine what interest, if
any, to credit on amounts
deferred by the Participant during the applicable Plan Year. The Committee
may, but shall not be
required to, (i) credit such amounts to the Participant's Wealth-Op Deferred
Benefit Account prior to
the last day of the applicable Plan Year or (ii) credit such amounts with
interest for any period
during the applicable Plan Year.
(B) The Company shall submit to each Participant, within 90
days after the close
of the Plan Year, a statement in such form as the Company deems desirable
setting forth the Wealth-
Op Deferred Benefit Account balances maintained for such Participant as of
the applicable date.
Participants shall receive separate information for each separate Benefit
Unit.
Section W4. Normal Benefit.
(A) The Normal Benefit shall be payable, if the Participant
continues in service
with a Participating Employer until the Participant's Eligible Benefit Date,
for each Benefit Unit for
which the Participant has completed deferrals of the "Total Deferral Amount."
The Normal Benefit shall
be payable monthly for 15 years commencing on the last day of January of the
calendar year following
the calendar year in which the Participant's Retirement Date occurs. If so
designated by the
Participant in the deferral election, the Participant may irrevocably
designate that payments relating
to such deferral election begin the last day of the January following the
later of (1) the date the
Participant attains age 65 or (2) the Participant's Retirement Date; this
election is irrevocable.
The Normal Benefit for each Benefit Unit shall be computed based on the
Participant's Wealth-Op
Deferred Benefit Account as defined in Section W1. Prior to the first
payment the Committee will
establish approximately equal monthly payments which it estimates will
amortize the Participant's
Wealth-Op Deferred Benefit Account over the payment period. The remaining
balance of the Participant's
Wealth-Op Deferred Benefit Account at the end of each Plan Year shall
continue to be credited with the
Interest Yield during the payment period for payment of the Normal Benefit,
and a separate adjustment
of the Interest Yield earned during each year subsequent to the Participant's
Retirement Date will be
made annually, or more frequently at the sole discretion of the Committee.
If the adjustment is
negative, the difference shall be deducted either (i) ratably from the
amounts payable in the following
Plan Year, or (ii) from the first amounts payable in the next Plan Year, as
the Committee, in its sole
and absolute discretion, shall determine.
(B) The Committee may determine, following the procedures and
standards of Section
10(B) of the Plan relating to financial hardship, to accelerate payment of
a Participant's Normal
Benefit not exceeding the balance of the Participant's Wealth-Op Deferred
Benefit Account. As a
condition of any such acceleration, the Participant shall be required to
terminate participation in
Wealth-Op, as provided in Section W7.
Section W5. Uncompleted Benefit Units.
(A) The following provisions shall apply to any Benefit Unit
for which the
Participant has not completed deferrals of the "Total Deferral Amount" upon
attainment of the
Participant's Retirement Date, which shall be referred to as an "Uncompleted
Benefit Unit." If the
Participant has not completed deferrals of the Total Deferral Amount for any
Uncompleted Benefit Unit
upon attainment of the Participant's Retirement Date, the Participant may
elect to receive either a
Modified Normal Benefit or a Reduced Benefit Unit as described below, or a
Termination Benefit as
described in Section W6, with respect to such Uncompleted Benefit Unit.
(B) If the Participant elects to receive a Modified Normal
Benefit, the Normal
Benefit shall be modified in the following manner. The Participating
Employers shall deduct from the
Normal Benefit payments which would otherwise be made on account of all
Benefit Units of the
Participant amounts equal to the remaining deferrals which were to be made
on the Participant's
Uncompleted Benefit Units and credit such amounts to be applied as deferrals
against the Total Deferral
Amounts for such Uncompleted Benefit Units. The amounts which are deducted
from Normal Benefit
payments shall reduce the balances of the Wealth-Op Deferred Benefit Accounts
for the Benefit Units
from which such Normal Benefit payments would have been made and shall
increase the balances of the
Wealth-Op Deferred Benefit Accounts for the Uncompleted Benefit Units which
are credited with such
amounts. Alternatively or in addition, a Participating Employer may complete
the Participant's
Uncompleted Benefit Units by transferring funds from the Participant's
Regular Deferred Compensation
Account. For any Uncompleted Benefit Unit for which the deferrals are
completed in the manner
described above, the Normal Benefit payments shall commence after the
deferrals associated with such
Benefit Unit are completed. The manner of modifying the Normal Benefit
payments on account of
Uncompleted Benefit Units shall be established, and may be modified from time
to time, by the Committee
in its sole discretion. The Participant may elect to receive a Modified
Normal Benefit only if the
Normal Benefit payments which would otherwise be made on account of all
Benefit Units of the
Participant will be sufficient to make the required deferrals associated with
an Uncompleted Benefit
Unit on a timely basis.
(C) A Participant may elect a Reduced Benefit Unit if the
account balance for that
deferral election is sufficient, as determined by the Company based on
calculations at that time, to
support a smaller Wealth-Op Benefit Unit. If the Participant elects to
receive a Reduced Benefit Unit,
the Company shall change the Uncompleted Benefit Unit to a completed Benefit
Unit of a smaller size
and a Total Deferral Amount equal to the deferrals which had been completed
on the Uncompleted Benefit
Unit. Benefits related to a Reduced Benefit Unit shall be based on such
Total Deferred Amount.
(D) If the Participant does not or cannot elect either a
Modified Normal Benefit
or a Reduced Benefit Unit, the Participant shall receive the Termination
Benefit, described in Section
W6, with respect to such Uncompleted Benefit Unit.
Section W6. Termination Benefit.
Except as provided in Sections W8 or W9, upon a Participant's
Termination of Service
before the Participant's Eligible Benefit Date, the Participant shall be
entitled to the "Termination
Benefit" described in this Section W6. The Termination Benefit for each
Benefit Unit shall be the
balance of the Participant's Wealth-Op Deferred Benefit Account, adjusted to
reflect any earnings or
losses credited before distribution in accordance with Section 10 of the
Plan. Upon any Termination
of Service of the Participant before the Participant's Eligible Benefit Date,
the balances of the
Participant's Wealth-Op Deferred Benefit Account shall be transferred to the
Participant's Regular
Deferred Compensation Account under the Fixed Income Option of Section 7(C)
of the Plan (the "Fixed
Income Option") and shall be distributed to the Participant in accordance
with Section 10 of the Plan.
Upon such transfer the Participant shall have no further right to any further
deferrals, survivor,
disability or other benefits under the Wealth-Op Program. Where the
Wealth-Op Program provides for
treatment under this Section of a specific Benefit Unit for which all
deferrals have not been
completed, then only balances related to that Benefit Unit shall be
transferred and only Wealth-Op
Program benefits related to that Benefit Unit shall be terminated.
Section W7. Termination of Participation in Wealth-Op
Program.
A Participant may elect to terminate participation in the
Wealth-Op Program prior
to the Participant's Retirement Date at such time or times as the Committee
may permit. Any
termination of participation in the Wealth-Op Program must apply to all of
the Participant's Benefit
Units under the Wealth-Op Program. In such event the Participant shall
transfer an amount equal to
the Termination Benefit which would be payable pursuant to Section W6 above
to be invested under one
or more of the other deferral options which are available under Section 7 of
the Plan. Upon such
transfer the Participant shall have no further right to any survivor,
disability or other benefits
under the Wealth-Op Program.
Section W8. Survivor Benefit.
(A) Death While in Service Prior to Age 55. If the
Participant dies while in the
service of a Participating Employer prior to attaining age 55, the
Participating Employer shall pay
an annual Survivor Benefit to the Participant's Beneficiary, until the
Participant would have attained
age 65, in an amount equal to 50% of the Participant's Total Deferral Amount
with respect to each
Benefit Unit, up to a maximum annual Survivor Benefit for all Benefit Units
equal to 100% of the
Participant's annual base salary from a Participating Employer at the time
of the Participant's death,
or 100% of the Participant's highest four year average annual base salary,
whichever is greater. The
payments will be made in equal monthly installments commencing the end of the
month following the month
in which the Participant's death occurred. In lieu of the Survivor Benefit
payable under this
subsection, the Participating Employer shall pay to the Beneficiary the
Normal Benefit payments which
would have been paid to the Participant pursuant to Section W4 (except that
the Interest Yield after
death shall be adjusted to the Company's Declared Rate for Wealth-Op II
Benefit Units) if the
Participant's Retirement Date had been the day preceding the Participant's
death if those Normal
Benefit payments (ignoring the time value of money but including current
Interest Yield) are a larger
total amount than the Survivor Benefit, as estimated at the time payments
commence, and if the
Beneficiary gives written consent. Payments will commence the end of the
month following the
Participant's death if the Beneficiary's written consent is obtained and no
payments will be made under
this Normal Benefit option if such consent is not obtained within 90 days of
the Participant's death.
No Survivor Benefit shall be payable with respect to a Participant who was
not in the service of a
Participating Employer at the time of the Participant's death (except for a
Participant who is treated
under Section W9 as having continued in service during the period of
Disability) if the Participant's
Termination of Service occurred prior to the Participant's attaining age 55.
(B) Death While in Service After Age 55. If the Participant
dies while in the
service of a Participating Employer after attaining age 55, the Participant's
Beneficiary shall be
entitled to receive the Normal Benefit payments which would have been paid
to the Participant pursuant
to Section W4 if the Participant's Retirement Date had been the day preceding
the Participant's death,
except that the account will be credited after death at the Company's
Declared Rate in the case of
Wealth-Op II Benefit Units. Monthly payments will commence the end of the
month following the month
in which the Participant's death occurred. In addition, the Participant's
surviving spouse, if any,
shall be entitled to receive as a Spouse's Benefit 50% of the average monthly
Normal Benefit payment
previously paid to the Participant or Beneficiary under Section W4 during
each month for the remainder
of the spouse's lifetime commencing with the month subsequent to completion
of the Normal Benefit
payments; provided, however, that in the event the surviving spouse is more
than five years younger
than the Participant at the time of the Participant's death, this payment
shall be reduced by 0.5% for
each month that the surviving spouse is more than 60 months younger than the
Participant, up to a
maximum reduction of 33% of the Spouse's Benefit. The Participating Employer
will pay the benefits
described in Section W8(A) for a period of ten years, in lieu of the benefits
described in the
foregoing provisions of this Section W8(B), if such adjusted benefits under
Section W8(A) would be a
larger total amount, payable to the Beneficiary, as estimated at the time
payments commence (ignoring
the time value of money but including current Interest Yield), and if the
Beneficiary and any surviving
spouse give their written consent. Payments will commence under this
alternative at the end of the
month following the month in which the Participant's death occurred if
written consent is obtained.
Payments of the Normal Benefit to a Beneficiary who is not a surviving spouse
may be deferred for a
period, not exceeding 90 days, until a written consent or rejection in regard
to a ten-year payment
is obtained from the surviving spouse.
(C) Death After Retirement. If the Participant retires after
the Participant's
Eligible Benefit Date and thereafter dies, and does not receive a lump sum
payment of the Normal
Benefit, the Participating Employer shall pay to the Participant's
Beneficiary the remaining Normal
Benefit payments which would have been paid to the Participant pursuant to
Section W4, except that the
account shall be credited after death at the Company's Declared Rate in the
case of Wealth-Op II
Benefit Units. In addition, the Participant's surviving spouse, if any,
shall be entitled to receive
50% of the average monthly Normal Benefit payment previously paid to the
Participant or Beneficiary
under Section W4 during each month for the remainder of the spouse's lifetime
commencing with the month
subsequent to the death of the Participant or completion of the Normal
Benefit payments, whichever is
later; provided, however, that in the event the surviving spouse is more than
five years younger than
the Participant at the time of the Participant's death, this payment shall
be reduced by 0.5% for each
month that the surviving spouse is more than 60 months younger than the
Participant, up to a maximum
reduction of 33% of the Survivor Benefit. The foregoing payment for the
surviving spouse shall not
be paid unless the Participant was married to such surviving spouse at least
one year before the
Participant retired. No Survivor Benefit will be payable if the Participant
receives a lump sum
payment of the Normal Benefit.
Section W9. Disability Benefit.
(A) There is no disability benefit available to a Participant
based on amounts
credited to the Wealth-Op II Deferred Benefit Account, but such an account
may be completed by a
disabled Participant in accordance with Section W9(D). However, if a
Participant with a Wealth-Op I
Deferred Benefit Account suffers a Disability while the Participant is in the
active service of a
Participating Employer, and applies to the Committee for benefits under this
Section, the Participating
Employer shall pay to the Participant the annual Disability Benefit described
in this subparagraph (A).
Such payments shall be made in monthly installments, commencing at the end
of the month following the
month in which the Committee determines that the Participant has suffered a
Disability or the last day
of the sixth full calendar month following the onset of such Disability,
whichever is later. Such
payments shall continue throughout the period that such Disability continues
until the Participant
attains age 65, except that:
(i) if the Participant suffers such a Disability on or after
the Participant's 60th
birthday but before the Participant's 65th birthday, the
Participating Employer will pay
the monthly installments for 60 months, and
(ii) if the Participant suffers such a Disability on or after
the Participant's 65th
birthday, the Participating Employer will pay the monthly
installments until the
Participant attains the age of 70.
After payment of all Disability Benefits is completed, due to the attainment
of age 65 (or other
subsequent applicable date), the Participant shall be entitled to receive the
Participant's Normal
Benefits described in Section W4. The annual Disability benefit for each
Benefit Unit under the
Wealth-Op I Program shall be an amount equal to 25% of the Total Deferral
Amount for such Benefit
Unit (determined as if all such amounts were deferred by the Participant) up
to a maximum annual
Disability benefit for all Benefit Units under the Wealth-Op I Program equal
to 50% of the
Participant's base salary from the Participating Employer being earned on the
last day of the
Participant's regular active employment, or 50% of the Participant's highest
average annual base
salary, whichever is greater. The Disability benefit shall be prorated for
any period of less than
one year. Disability benefit payments, including amounts deducted to
complete any Uncompleted Benefit
Unit under Section W9(C) below, shall not reduce the balances of the
Participant's Wealth-Op Deferred
Benefit Accounts. Disability benefits will cease if the Participant dies
while still receiving such
Benefits.
(B) If a Participant makes application for disability
benefits under the Social
Security Act, as now in effect or as hereafter amended, and qualifies for
such benefits, the
Participant shall be presumed to qualify as disabled under this Section, but
no retroactive Disability
benefits shall be granted hereunder. However, the Committee may still deny
the Disability Benefit if
it determines that the Participant did not meet the requirements for
Disability at the time the
Participant's active service terminated. If, after payments under this
Section have been made for two
years, the Participant has not qualified for disability benefits under the
Social Security Act, the
Participant will not qualify for further benefits under this Section. If a
Participant's Social
Security disability benefits are granted and later discontinued, it will be
presumed that the
Participant no longer qualifies for benefits under this Section, and benefits
hereunder will be
terminated until, if ever, the Participant successfully rebuts the
presumption to the Committee's
satisfaction. The Committee may from time to time require the Participant
to submit medical and other
evidence, and/or submit to an examination by a physician selected by the
Committee, that the
Participant continues to be disabled under the Wealth-Op Addendum.
(C) During the period while the Participant remains disabled,
the Participant shall
be treated as if the Participant continues in the service of the
Participating Employer for purposes
of determining the Normal Benefit pursuant to Section W4 and the Survivor
Benefit pursuant to Section
W8, but no compensation will be "adjusted" or "assumed" while the Participant
is disabled. During the
period while the Participant remains disabled, the Participant shall continue
the Participant's
deferrals with respect to any Uncompleted Benefit Units. Such deferral
amounts shall be deducted from
the Disability benefit payments which are made to the Participant and
credited to the balances of the
Wealth-Op Deferred Benefit Accounts for the Uncompleted Benefit Units.
Alternatively or in addition,
a Participating Employer may complete the Participant's Uncompleted Benefit
Units by transferring funds
from the Participant's Regular Deferred Compensation Account.
(D) If a Participant is considered to be disabled under the
provisions of the
Pension Plan, but is not entitled to a Disability Benefit under this Section
W9, the Participating
Employer will complete the Participant's deferrals with respect to any
Uncompleted Benefit Units.
Normal and Survivor Benefits will continue to accrue with respect to the
Participant's Benefit Units
while the Participant remains so disabled, but, in no event shall the
Participant be entitled to any
Disability Benefits based on changes in the Participant's physical or mental
condition occurring after
leaving the active service of a Participating Employer. Such Participant's
Normal Benefit payments
shall commence on the last day of January of the calendar year following the
calendar year in which
the Participant's Eligible Benefit Date would have occurred if the
Participant had not been disabled.
Repayment of these deferrals without interest will be made to the
Participating Employer as soon as
possible from any Normal or Survivor Benefits which are paid to the extent
repayment was not collected
from the Participant's Regular Deferred Compensation Account or from any
Disability Benefits under the
Wealth-Op I Program. However, the Wealth-Op Program will not provide the
Participant with any annual
Disability Benefit in the event of such a disability which does not
constitute a Disability within the
meaning of Section W1 of the Wealth-Op Program and in no event shall the
Wealth-Op II Program provide
a Participant with any Disability benefit. A Participant retired on
disability may request an earlier
distribution of some or all of the Participant's completed Benefit Units
under Section 10(B) of the
Plan based on the financial hardship caused by the disability.
Section W10. Deferral of Payment.
No payment shall be deferred to a period later than the
payment period elected by
the Participant at the time of the election to defer the specific Benefit
Unit was made by the
Participant.
Section W11. Recipients of Payments; Designation of
Beneficiary.
All payments to be made under the Wealth-Op Program shall be
made to the Participant
during the Participant's lifetime, provided, that if the Participant dies
prior to the completion of
such payments, then all subsequent payments under the Wealth-Op Program shall
be made to the
Beneficiary or Beneficiaries designated pursuant to Section 11 of the Plan,
or to a spouse under
Section W8 of this Addendum.
Section W12. Aggregation of Payments.
The number of monthly payments may be reduced to the extent
necessary to insure that
each installment will equal at least $500 per month or, in lieu of monthly
payments of benefits under
the Wealth-Op Program, such benefits may be paid bimonthly, quarterly or at
another interval when
necessary to insure that each payment is at least $500. Wealth-Op Benefit
payments may be paid in one
check along with payments from the Participant's Regular Deferred
Compensation Account.
Section W13. Protective Provisions.
Each time a Participant elects a new Benefit Unit, the
Participant will cooperate
with the Participating Employers by furnishing any and all information
requested by the Participating
Employers in order to facilitate the payment of benefits hereunder, taking
such physical examinations
as the Company may deem necessary and taking such other actions as may be
requested by the Company.
If the Participant refuses to cooperate, the Participating Employers shall
have no further obligation
to the Participant under the Wealth-Op Program. If the Participant is not
in good health, the
Committee may refuse to allow the Participant to obtain the requested Benefit
Unit or may offer a
Benefit Unit under different terms. If no Benefit Unit is acquired, the
Participant's first year
deferral shall be placed in the Fixed Income Option, and later year deferrals
will not be required.
In the event of the Participant's suicide during the first two years after
commencement of deferrals
with respect to any Benefit Unit, or if the Participant makes any material
misstatement of information
or nondisclosure of medical history, then no benefits will be payable to the
Participant under the
Wealth-Op Program for any Benefit Unit, or in the Company's sole discretion,
benefits may be payable
in a reduced amount.
Section W14. Offset.
If at the time payments or installments of payments are to be
made hereunder the
Participant or the Beneficiary or both are indebted or obligated to a
Participating Employer, then the
payments remaining to be made to the Participant or the Beneficiary or both
may, at the discretion of
the Participating Employer, be reduced by the amount of such indebtedness or
obligation; provided,
however, that an election by a Participating Employer not to reduce any such
payment or payments shall
not constitute a waiver of its claim for such indebtedness or obligation.
Section W15. Termination of Wealth-Op Program. The Company
in its sole discretion
reserves the right to terminate the Wealth-Op Program at any time for any
reason. In the event that
the Company terminates the Wealth-Op Program, the balance of each
Participant's Wealth-Op Deferred
Benefit Account shall be transferred to or used to create Regular Deferred
Compensation Accounts for
each Participant under Section 7(C)(1) of the Plan (the "Fixed Income
Option") and shall be distributed
to each Participant in accordance with Section 10 of the Plan; and,
thereafter, the Participants shall
have no further rights to any survivor, Disability or other Benefits under
this Wealth-Op Program,
except for survivor benefits which commenced prior to such termination of the
Wealth-Op Program.
* * * * *
IN WITNESS WHEREOF, and to evidence the Company's adoption of
this amended and
restated Plan (including the Wealth-Op Deferred Benefit Addendum), the
undersigned has executed this
Plan document for and on behalf of the Company, this day of December,
1992.
NORTHERN STATES POWER COMPANY
By________________________________
As its____________________________
ATTEST:
_______________________________
As its_________________________
AMENDMENT TO THE
NSP DEFERRED COMPENSATION PLAN
(Effective January 1, 1993)
Northern States Power Company (the "Company"), acting pursuant to the
power reserved to it under Section 12 of the NSP Deferred Compensation Plan
(the "Plan"), hereby amends Section 10 of the Plan, effective as of January
1, 1993, by adding the following new subsection (E):
(E) Government Service. Notwithstanding anything in this section to
the contrary, a Participant whose employment terminates due to election
or appointment to a position in the federal government shall receive
an immediate lump sum distribution of the Participant's Regular
Deferred Compensation Account if such a distribution must be made to
satisfy the requirements of federal law or to avoid the appearance of
a conflict of interest.
IN WITNESS WHEREOF,the undersigned has executed this amendment for and
on behalf of the Company, this ______ day of January, 1993.
NORTHERN STATES POWER COMPANY
By__________________________________
As its______________________________
ATTEST:
_____________________________
As its_______________________
<TABLE>
Exhibit 12.01
NORTHERN STATES POWER COMPANY AND SUBSIDIARY COMPANIES
STATEMENT OF COMPUTATION OF
RATIO OF EARNINGS TO FIXED CHARGES
Earnings 1993 1992 1991 1990 1989
(Thousands of dollars)
<S> <C> <C> <C> <C> <C>
Income from continuing
operations before accounting
change $211,740 $160,928 $207,012 $192,971 $219,165
Add
Taxes based on income
Federal income taxes (1) 99,952 71,549 75,905 120,686 92,638
State income taxes (1) 28,076 19,148 22,209 34,442 25,566
Deferred income taxes-net 12,256 5,185 26,506 (31,794) 7,541
Investment tax credit
adjustment - net (9,544) (9,708) (9,189) (10,048) (10,906)
Fixed charges 113,562 109,888 110,146 111,826 109,466
Earnings $456,042 $356,990 $432,589 $418,083 $443,470
Fixed charges
Interest charges per
statement of income $113,562 $109,888 $110,146 $111,826 $109,466
Ratio of earnings to fixed
charges 4.0 3.2 3.9 3.7 4.1
(1) Includes income taxes included in Miscellaneous Income Deductions and Non-operating Taxes.
</TABLE>
Exhibit 21.01
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES
Subsidiaries of Registrant
Name State of Incorporation Purpose
Northern States Power
Company (Wisconsin) Wisconsin Electric and gas utility
First Midwest Auto
Park, Inc. Minnesota Own and manage a parking
ramp
United Power and Land
Company Minnesota Real estate holding
company
Cormorant Corporation Montana Holds interest in coal and
lignite properties
NRG Energy, Inc. Delaware Own and manage non-
regulated energy
subsidiaries of the
Company
Cenergy, Inc. Minnesota Natural gas marketing and
energy services
Viking Gas Transmission Delaware Natural gas
Company transmission
Eloigne Company Minnesota Own and operate affordable
housing units
NEO Corporation Minnesota Development of small
scale waste to energy
opportunities utilizing
landfill gas
Exhibit 23.01
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement
No. 2-74630 on Form S-16 and Registration Statement Nos. 33-43812 and 33-
54534 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 in Registration Statement No. 33-51593 on Form S-3 (relating
to the Northern States Power Company $600,000,000 Principal Amount of First
Mortgage Bonds) of our report dated February 7, 1994, which expresses an
unqualified opinion and includes an explanatory paragraph relating to the
change in method of accounting for postretirement health care costs in 1993
and for unbilled revenues in 1992 appearing in this Annual Report on Form 10-
K of Northern States Power Company for the year ended December 31, 1993.
(Deloitte & Touche)
DELOITTE & TOUCHE
Minneapolis, Minnesota
March 23, 1994
