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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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.
OPERATING STATISTICS
1993 1992 1991 1990 1989
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
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.
Item 6 - Selected Financial Data
1993 1992 1991 1990 1989 1983
(Dollars in millions except per share data)
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.)
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
Consolidated Statements of Income
Year Ended Dec. 31
(Thousands of dollars, except per share data) 1993 1992 1991
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
Consolidated Statements of Cash Flows
Year Ended Dec. 31
(Thousands of dollars) 1993 1992 1991
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
Consolidated Balance Sheets
Dec. 31
(Thousands of dollars) 1993 1992
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
Consolidated Statements of Changes in Common Stockholders' Equity
Number of Retained Shares Held
(Dollar amounts in thousands) Shares Issued Par Value Premium Earnings by ESOP
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
Consolidated Statements of Capitalization
Dec. 31
(Thousands of dollars) 1993 1992
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
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.
17. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended
(Thousands of dollars) March 31, 1993 June 30, 1993 Sept. 30, 1993(1) Dec. 31, 1993
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.
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.
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE V
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1993
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)
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
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE V
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1992
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)
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
NORTHERN STATES POWER COMPANY, MINNESOTA AND SUBSIDIARIES SCHEDULE V
UTILITY PLANT AND NON-REGULATED PROPERTY
FOR THE YEAR ENDED DECEMBER 31, 1991
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)
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
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
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)
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
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
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
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)
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
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
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
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)
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
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
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.