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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, 1994
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 or any amendment to 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 15, 1995, the aggregate market value of the voting common stock
held by non-affiliates of the Registrant was $2,907,829,319 and there were
outstanding 66,931,937 shares of common stock, $2.50 par value.
Documents Incorporated by Reference
None
Index
Page No.
PART I
Item 1 - Business. .. . . . . . . . . . . . . . . . . . . . . . . . . . .1
UTILITY REGULATION AND REVENUES
General. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2
Rate Programs. . . . . . . . . . . . . . . . . . . . . . . . . . .2
Rate Matters by Jurisdiction . . . . . . . . . . . . . . . . . . .3
Ratemaking Principles in Minnesota and Wisconsin . .. . . . . . . .6
Fuel and Purchased Gas Adjustment Clauses. . . . . . . . . . . . .6
ELECTRIC UTILITY OPERATIONS
Competition. . . . . . . . . . . . . . . . . . . . . . . . . . . .7
Capability and Demand. .. . . . . . . . . . . . . . . . . . . . . .8
Energy Sources . . . . .. . . . . . . . . . . . . . . . . . . . . 10
Fuel Supply and Costs. .. . . . . . . . . . . . . . . . . . . . . 10
Nuclear Power Plants - Licensing, Operation and Waste Disposal. . 12
Electric Operating Statistics . . . . . . . . . . . . . . . . 14
GAS UTILITY OPERATIONS
Competition. . . . . . . . . . . . . . . . . . . . . . . . . . . .14
Capability and Demand . . . . . . . . . . . . . . . . . . . . . 16
Gas Supply and Costs . . . . . . . . . . . . . . . . . . . . . . .16
Gas Operating Statistics . . . . . . . . . . . . . . . . . . . . 18
NRG ENERGY, INC . . . . . . . . . . . . . . . . . . . . . . . . . . .18
OTHER SUBSIDIARIES. . . . . . . . . . . . . . . . . . . . . . . . . .20
ENVIRONMENTAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . .21
CAPITAL SPENDING AND FINANCING. . . . . . . . . . . . . . . . . . . .25
EMPLOYEES AND EMPLOYEE BENEFITS . . . . . . . . . . . . . . . . . . .26
EXECUTIVE OFFICERS. . . . . . . . . . . . . . . . . . . . . . . . . .27
Item 2 - Properties. . . . . . . . . . . . . . . . . . . . . . . . . . .29
Item 3 - Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . .29
Item 4 - Submission of Matters to a Vote of Security Holders . . . . . .30
PART II
Item 5 - Market for Registrant's Common Equity and Related Stockholder
Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30
Item 6 - Selected Financial Data . . . . . . . . . . . . . . . . . . . .31
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . . . .32
Item 8 - Financial Statements and Supplementary Data . . . . . . . . . .44
Item 9 - Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . .70
PART III
Item 10 - Directors and Executive Officers of the Registrant . . . . . .71
Item 11 - Executive Compensation . . . . . . . . . . . . . . . . . . . .74
Item 12 - Security Ownership of Certain Beneficial Owners and
Management 78
Item 13 - Certain Relationships and Related Transactions . . . . . . . .78
PART IV
Item 14 - Exhibits, Financial Statement Schedules, and Reports on
Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . .79
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .85
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 two significant subsidiaries, Northern States Power Company, a
Wisconsin corporation (the Wisconsin Company) and NRG Energy, Inc (NRG), a
Delaware corporation; and several other subsidiaries, including Cenergy, Inc,
a Minnesota corporation, and Viking Gas Transmission Company, a Delaware
corporation (Viking). (See "NRG Energy, Inc." and "Other Subsidiaries" herein
for further discussion of these subsidiaries.) The Company and its
subsidiaries collectively are referred to herein as NSP.
NSP is predominantly an operating public utility engaged in the
generation, transmission and distribution of electricity throughout a 49,000
square mile service area and the transportation and distribution of natural
gas in approximately 148 communities within this area. Viking is a regulated
natural gas transmission company that operates a 500-mile interstate natural
gas pipeline. In addition to utility businesses, NRG manages several of NSP's
non-regulated energy subsidiaries.
The Company serves customers in Minnesota, North Dakota and South Dakota.
The Wisconsin Company serves customers in Wisconsin and Michigan. Of the
approximately 3 million people served by the Company and the Wisconsin
Company, the majority are concentrated in the Minneapolis-St. Paul
metropolitan area. In 1994, about 61% of NSP's electric retail revenue was
derived from sales in the Minneapolis-St. Paul metropolitan area and about 56%
of retail gas revenue came from sales in the St. Paul area. (For business
segment information, see Note 18 of Notes to Financial Statements under Item
8.)
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 pressure to control costs to
operate and construct facilities, uncertainties in regulatory processes,
increasing costs of compliance with environmental laws and regulations, and
uncertainties related to permanent disposal of nuclear fuel. In May 1994, the
Minnesota Legislature approved a plan for temporary storage of used nuclear
fuel, if the Company satisfies certain responsibilities, which should
eliminate for several years the uncertainty surrounding continued operation
of its nuclear plants. (See Management's Discussion and Analysis under Item
7 and Notes 16 and 17 of Notes to Financial Statements under Item 8 for
further discussion of this matter.)
NRG was active in the international energy market through partnership and
joint venture investments in 1994. NRG acquired partial ownership positions
in the MIBRAG mbh coal and power complex and in the 900 megawatt (Mw) Schkopau
power plant both near Leipzig, Germany. NRG is also the operator and 37.5%
owner of the 1,680 Mw Gladstone Power Station in Queensland, Australia. (See
additional discussions of business acquisitions and non-regulated operations
in the "NRG Energy, Inc." and "Other Subsidiaries" sections, herein, and in
Notes 4 and 5 of Notes to Financial Statements under Item 8.)
UTILITY 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" herein.)
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 kilovolts (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 and regulations
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, its ability to control
costs and the success of its non-regulated activities. NSP's 1994 utility
operating revenues, excluding intersystem non-firm electric sales to other
utilities of $89 million and miscellaneous revenues of $58 million, were
subject to regulatory jurisdiction as follows:
Authorized Return on Percent of
Common Equity @ Total
December 31, 1994 Revenues
Electric Gas (Electric & Gas)
Retail:
Minnesota Public Utilities
Commission 11.47% 11.47% 73.3%
Public Service Commission of
Wisconsin 11.4 11.4 14.7
North Dakota Public Service
Commission 11.50 14.0 5.3
South Dakota Public Utilities
Commission * 3.1
Michigan Public Service
Commission 12.25 0.6
Sales for Resale - Wholesale, Viking
Gas and Interstate Transmission:
Federal Energy Regulatory Commission * * 3.0
Total 100.0%
* Settlement proceeding, based upon revenue levels granted with no specified
return.
Rate Programs
Rate increases requested and granted in previous years from various
jurisdictions were as follows (note that 1992, 1993 and 1994 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/(Decrease)
Year Requested Granted
(Millions of dollars)
1990 19.5 11.2
1991 118.7 68.0
1992 ----- -----
1993 166.6 101.5
1994 (1.0) (1.0)
The following table summarizes the status of rate increases for rates
effective in 1994.
Annual Increase/(Decrease)
Updated
Requested Request Granted Status
(Millions of dollars)
Electric
North Dakota-Retail 1.2 1.2 Order Issued 12/29/93
North Dakota-Refund (3.6) (3.6) Order Issued 11/09/94
Gas
Wisconsin-Retail 1.4 1.7 1.4 Order Issued 12/23/93
Total 1994 Rate
Program (1.0) (1.0)
Rate Matters by Jurisdiction
Minnesota Public Utilities Commission (MPUC)
On Jan. 31, 1994, the Minnesota Department of Public Service, the Office
of the Minnesota Attorney General and the Minnesota Energy Consumers
intervenor groups filed an appeal with the Minnesota Court of Appeals of the
MPUC's determination on the allowed return on equity granted to the Company
in final 1993 electric and gas rate orders. On Aug. 2, 1994, the Court
affirmed the final rate orders issued in January 1994 for these rate cases.
This appeal process is now completed. As a result of this decision, no
adjustments or changes are required to rates charged to customers or to
revenues recorded by the Company.
In 1991, the Minnesota legislature passed a law which granted the MPUC
discretionary authority to approve a rate adjustment clause for changes in
certain costs (including property taxes, fees and permits) incurred by
Minnesota public utilities. The MPUC may approve a utility's use of the rate
adjustment clause for billing customers if certain conservation expenditure
levels are met. On Oct. 4, 1994, the Company filed for approval of the use
of the adjustment clause for billing its gas customers, beginning in January
1995, for increases in property taxes. The potential gas revenue increase
from this filing was approximately $2.0 million. At a hearing held on Feb.
23, 1995, the MPUC turned down the Company's request. The Company may ask the
MPUC to reconsider this decision.
On Oct. 28, 1994 the Company filed with the MPUC a petition for a
miscellaneous rate change approving the implementation of an annual recovery
mechanism for deferred electric Conservation Improvement Program (CIP)
expenses. On Feb. 23, 1995, the MPUC voted to approve recovery of $41 million
under a new rate adjustment clause for the period May 1995 through June 1996.
Thereafter, the Company would be required to request a new cost recovery level
annually. The Company estimates it will receive an additional $24 million in
revenues in 1995. This increased recovery results from a corresponding
increase in conservation expenses and avoids a significant delay between the
incurring of costs and recovery in rates.
On Oct. 5, 1994, as part of a response to 1994 legislation related to
fuel storage at the Prairie Island nuclear plant, the Company filed a
miscellaneous rate change proposal with the MPUC which reflects a 50% discount
on the first 300 kilowatt hours (Kwh) consumed each month by qualified low-
income residential customers. The Company proposed that the discount be
effective beginning with the October 1994 billing month for qualifying
customers, and that rate adjustments designed to recover from other customers
the costs of the discount be effective Jan. 4, 1995. The MPUC approved the
filing on Dec. 5, 1994. The ruling also eliminated the Conservation Rate
Break and restructured the rates between customer classes, but does not
significantly change overall revenue levels.
By September 1 of each year, the Company is required by Minnesota statute
to submit to the MPUC an annual report of the Purchased Gas Adjustments (PGA)
for each customer class by month for the previous year commencing July 1 and
ending June 30. The report verifies whether the utility is calculating the
adjustments properly and implementing them in a timely manner. In addition,
the MPUC review includes an analysis of procurement policies, cost-minimizing
efforts, rule variances in effect or requested, retail transportation gas
volumes, independent auditors' reports, and the impact of market forces on gas
costs for the coming year. The MPUC has the authority to disallow certain
costs if it deems the utility was not prudent in its gas procurement
activities. The Department of Public Service (DPS) has recommended a $1.1
million cost recovery disallowance. This filing is pending MPUC action.
Gas utilities in Minnesota are also required to file for a change in
design day demand, to redistribute demand percentages among classes, or
exchange one form of demand for another. The Company filed in October 1994
to increase its demand entitlements due to projected increases in firm
customer count, to decrease the Minnesota jurisdictional allocation of total
demand entitlements and to recover the demand entitlement costs associated
with the increase in transportation and storage levels in its monthly PGA's.
This filing is pending MPUC approval.
No general rate filings are anticipated in Minnesota in 1995.
North Dakota Public Service Commission (NDPSC)
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 previous rate increase granted in
April 1993. The $1.2 million annual increase was implemented Jan. 5, 1994.
On Aug. 9, 1994 the Company applied to the NDPSC for a rate reduction of
$3.6 million in annual electric revenues. The reduction reflects a correction
in cost allocations to the North Dakota jurisdiction. The Company also
requested authority to make refunds to customers to effectively implement the
reduction as of June 1, 1994. On Nov. 9, 1994, the NDPSC approved the
proposed rate reduction. In January 1995, the NDPSC held a hearing on the
possibility of retroactive refunds for the period Jan. 1, 1989, through June
1, 1994, but has not yet reached a decision. The ultimate outcome of this
proceeding is not determinable at this time.
On Nov. 1, 1994 NSP received approval of its proposed Economic
Development Rider (EDR) by the NDPSC. The rider allows NSP's North Dakota
operations (NSP-ND) to offer discounted rates to new customers, or on load
expansions by existing customers, for a period of five years. The customer's
load must be at least 50 kilowatts (Kw). The rider is closely tied to the
state's Partnership in Assisting Community Expansion (PACE) program, which
offers low interest rates on business development loans. The EDR will enable
NSP-ND to remain competitive with neighboring energy providers, most of which
have rate discount incentives to attract new customers. At this time, the
amount of the discounts is not expected to have a material affect on the
Company's financial results.
No general rate filings are anticipated in North Dakota in 1995.
South Dakota Public Utilities Commission (SDPUC)
There were no general rate filings in South Dakota in 1994 and none are
anticipated in 1995.
Public Service Commission of Wisconsin (PSCW)
In June 1993, the Wisconsin Company filed with the PSCW for a $1.4
million annual increase in gas retail rates to be effective Jan. 1, 1994. In
Aug. 1993, the Wisconsin Company increased its request to $1.7 million to
amortize recovery of a portion of the acquisition premium paid by the Company
for Viking in recognition of reduced delivered gas costs. In Dec. 1993, the
PSCW issued an order approving a $1.4 million increase on an annual basis in
the Wisconsin Company's gas rates, including the amortization. These rate
changes took effect on Jan. 1, 1994.
The Wisconsin Company filed a proposal for a new high load factor rate
with the PSCW in November 1994 to be effective Jan. 1, 1995. Under the
proposal, qualifying customers would receive a credit on their bills of up to
3 percent, depending on load factor. This is expected to reduce 1995 revenues
for the Wisconsin Company by approximately $1.0 million.
The Wisconsin Company will file a general rate case in June 1995, for
rates effective in 1996, as required by the PSCW biennial filing requirement.
Retail Rate Recovery of Viking Acquisition Costs
During 1993, the Company and the Wisconsin Company requested regulatory
approval in Minnesota, North Dakota, Wisconsin and Michigan to recover in
retail gas rates a portion of the acquisition cost paid for Viking in
recognition of reduced retail delivered gas costs made possible by the
acquisition of Viking. The PSCW approved in the Wisconsin Company's gas rates
recovery of a total of $1.8 million over the five-year period 1994-98. On
March 23, 1994, the NDPSC authorized, without any change in rates, the
amortization of $150,000 in annual jurisdictional expense for Viking
acquisition costs over a 15 year period starting in June of 1993. On Nov. 21,
1994 the MPUC rejected PGA recovery of jurisdictional expense for Viking
acquisition costs (amounting to $1.5 million annually), but ruled the Company
could seek recovery in its next gas general rate case. Viking's expenses
will include approximately $2 million in annual acquisition cost amortization
each year until 2008.
Electric Transmission Tariffs and Settlement (FERC)
In 1990, the Company filed a transmission services tariff for certain
transmission customers. New rates were effective under the filing, subject
to refund, for the period Dec. 29, 1990 through Oct. 31, 1994. The Company
has recorded an estimated liability at Dec. 31, 1994 for potential
transmission rate refunds under this tariff based on the FERC order dated
Sept. 21, 1993. Since a rehearing of the order was granted and is currently
pending, transmission rates for this period are not yet final.
The FERC announced a new transmission pricing policy effective Oct. 26,
1994. The new policy introduces greater flexibility in transmission pricing
structure. It established five principles of transmission pricing including
guidelines on coverage of revenue requirements, comparability of transmission
service, balance of efficiency, fairness and practicality.
In March 1994, the Company filed a revised open access transmission
tariff with the FERC. On May 25, 1994, the FERC accepted the filing with the
new rates effective Nov. 1, 1994, subject to refund. The FERC also ruled the
tariff would be subject to the requirement that the Company offer transmission
service using terms and conditions comparable to its own use of the system.
The Company recently reached a settlement in principle with several parties
involved in this proceeding. The settlement agreement includes a transmission
tariff that complies with the FERC transmission pricing policy which calls for
comparability of service and pricing, network service, and unbundling of
ancillary charges such as scheduling and load following. The Company
anticipates acceptance of the settlement offer in 1995. The revenue effect
on the Company is an increase of approximately $200,000 per year. The new
tariff allows the Company to comply with transmission pricing provisions of
open access transmission required by the Energy Policy Act of 1992.
Minnesota Wholesale Rate Proceedings (FERC)
In 1990, 16 of the Company's 19 municipal wholesale customers in
Minnesota began reviewing their long-term power supply options. Eight
customers created a joint action group, the Minnesota Municipal Power Agency
(MMPA), to serve their future power supply needs. An additional wholesale
customer became an associate member of the MMPA. In 1992 these nine municipal
customers 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 $29 million in annual revenues and a maximum
demand load of approximately 155 Mw.
In Oct. 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 some of the
municipalities' supply agreements with the Company expire. On Jan. 26, 1994,
the FERC in a proposed order 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. The
Commission accepted a settlement agreement in 1994. The MMPA customers agreed
to pay the rate then in effect for firm transmission service. Following FERC
acceptance of the pending transmission tariff, the MMPA customers will be
charged the new tariff unit rates.
In 1992 and 1993, the Company signed long-term power supply agreements
with the remaining 10 of its current 19 municipal customers in Minnesota. 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 59 Mw and
provide approximately $10 million in annual revenue. The FERC accepted
formula rates effective Jan. 1, 1994, by order dated Feb. 23, 1994.
Other Wholesale Rate Proceedings (FERC)
In Dec. 1993 the Company, in compliance with a FERC order in the Central
Maine case requiring that the Commission approve all interstate, inter-utility
contracts, filed over 300 such contracts with the FERC for review. The
Commission established 76 separate dockets for review. Absent FERC
acceptance, the contracts could have been declared null and void, possibly
resulting in full refunds for all amounts paid. The FERC has accepted 75
dockets with little or no change. The remaining docket is expected to be
accepted. The Company anticipates full resolution of the Central Maine
compliance filings in 1995.
The Wisconsin Company plans to announce market-based pricing options for
existing and potential wholesale customers in 1995. The wholesale customers
have new opportunities to purchase power from power suppliers other than NSP.
With open transmission access, they have the opportunity to purchase power
from any producer and request that, on a comparable basis, the power be
delivered from the producer to their municipality.
In May, 1994, the Wisconsin Company offered its municipal wholesale
customers a discount of one to two percent off the FERC authorized rate for
a long-term full requirements commitment between five and ten years with
comparable cancellation notices. Five of the ten municipal wholesale
customers signed up for the discounts. The total annual decrease in revenues
is approximately $0.1 million.
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.
To the extent final rates exceed interim rates, the final rates become
effective at the time of the order and retroactive recovery of the difference
is not permitted. 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 in Effect
The Company's retail electric and Wisconsin Company wholesale rate
schedules provide for adjustments to billings and revenues for changes in the
cost of fuel and purchased energy. Although the lag in implementing the
billing adjustment is approximately 60 days, an estimate of the adjustment is
recorded in unbilled revenue in the month costs are incurred. The Company's
wholesale customers remaining with NSP do not have a fuel clause provision in
their contracts. The contracts instead provide a fixed rate with an
escalation factor. 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.
Gas rate schedules for the Company and the Wisconsin Company include a
purchased gas adjustment (PGA) clause that provides for rate adjustments for
changes in the current unit cost of purchased gas compared to the last costs
included in rates.
The 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 station operations is provided in-kind
by transportation service customers.
ELECTRIC UTILITY OPERATIONS
Competition
NSP's electric sales are subject to competition in some areas from
municipally owned systems, rural cooperatives and, in certain respects, other
private utilities and 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
effectively.
NSP has proposed to fill future needs for new generation through
competitive bid solicitations. The use of competitive bidding to select
future generation sources allows the Company to take advantage of the
developing competition in this sector of the industry. The Company's
proposal, which has been approved by the MPUC, allows NRG to bid in response
to Company solicitations for proposals and the Company is seeking permission
to include an NSP regulated alternative in the future.
Management intends to obtain regulatory approval in all retail
jurisdictions to use a single bid process to meet resource needs for the
entire integrated system. The Company's competitive bidding proposal has been
approved by both the MPUC and PSCW.
In Oct. 1992, the President signed into law the Energy Policy Act of 1992
(Energy Act). The Energy Act amends the Public Utility Holding Company Act
of 1935 (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 (as discussed in "Utility 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.
In 1994, the FERC issued proposed rulemaking to address the rate
treatment of potential "stranded investment" costs which may result as the
electric energy market becomes more competitive. The FERC is soliciting
comments on options for recovery of transition costs associated with existing
electric investments for which competitive market pricing might not provide
recovery. NSP is evaluating the FERC proposal to determine the potential
effects on operating results and customer rates and has responded to the FERC
individually and through an industry group. The FERC has not reached a final
decision, and the effects of the proposed rulemaking currently are not known.
Many states are currently considering retail competition. While the
topic of retail competition has been discussed in the Company's jurisdictions,
no legislation or regulatory initiatives have been formally introduced. The
PSCW has asked each utility in the state for comments regarding retail
competition. In response to the request, the Wisconsin Company filed the
following recommendations. Competition should be phased in for retail markets
by customer classes, with all customers having choice of supplier by 2001.
The generation segment of the industry should be deregulated by 2001. Prudent
stranded costs should be recovered prior to the advent of retail wheeling.
Finally, utilities and other competitors should have a level playing field for
issues such as obligation to serve, eminent domain, requirements for demand
side management, funding of social programs, opening of retail markets to
competition and other issues. Also, as an outcome of the responses to the
PSCW, a task force was formed by the PSCW to analyze the industry
restructuring necessary in the state of Wisconsin. A goal of this task force
is to have a list of recommended legislative changes to the Wisconsin
Legislature for the 1996 session.
The Michigan Public Service Commission has determined that Michigan
should recodify statutes governing energy production. They will be working
with the governor's office to initiate that process. Michigan also has a
retail wheeling experiment, limited to its two largest utilities and customers
larger than $50 million, currently underway. The Wisconsin Company's
customers are not included in this experiment which is currently being
challenged in court.
Retail competition represents yet another development of a competitive
electric industry. Management plans to continue its ongoing efforts to be a
low-cost supplier of electricity and an active participant in the more
competitive market for electricity expected as a result of the Energy Act.
Actions the Company is pursuing to position for the competitive environment
include: creative partnership solutions with strategic customers including
communities; focusing on the unique needs of national account customers;
competitive pricing alternatives; improved reliability; implementation of the
first service guarantees in the region; ease of customer access including 24
hour, 7 days/week operation; substantial customer convenience and flexibility
improvements via a new Customer Service System which includes appointment
scheduling upon first contact, improved outage call response, and a wide array
of new billing options; and aggressive cost management.
Capability and Demand
Assuming normal weather, NSP expects its 1995 summer peak demand to be
7,229 Mw. NSP's 1995 summer capability is estimated to be 8,942 Mw, net of
contract sales including 1,153 Mw (including reserves) of contracted purchases
from the Manitoba Hydro-Electric Board, a Canadian Crown Corporation (Manitoba
Hydro) and 868 Mw of other contracted purchases. The estimate assumes 7,682
Mw of thermal generating capability and 1,438 Mw of hydro and wind generating
capability. Of the total summer capability, NSP has committed 178 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 1994 maximum demand of 7,101 Mw occurred on June 14, 1994.
Resources available at that time included 6,859 Mw of Company-owned capability
and 1,860 Mw of purchased capability net of contracted sales. Due to the Mid-
Continent Area Power Pool's (MAPP) penalty for reserve margin shortfalls and
to be prepared for weather uncertainty at the lowest potential cost, NSP
carried a reserve margin for 1994 of 23%. The minimum reserve margin
requirement as determined by the members of the MAPP, of which NSP is a
member, is 15%. (See Note 17 of Notes to Financial Statements under Item 8
for more discussion of power agreement commitments.)
The Company added to its generating facilities in 1994. On Sept. 24,
1994, the Angus Anson 232 Mw gas-fired combustion turbines were placed in
service near Sioux Falls, South Dakota. The total cost of this project was
approximately $72 million.
The Company is continuing an extensive reliability program that includes
preventive maintenance on transmission and distribution power lines,
improvements to existing equipment, and testing and implementing new
technology. Reliability to NSP's large customers improved 14% in 1994,
through a focused program to reduce the number of outages caused by lightning,
human errors, animals and trees. In 1994, a service guarantee program was
implemented to ensure on-time service installation and construction site
restoration.
In 1994, NSP signed a long term power purchase contract with LSP-Cottage
Grove for 245 Mw of annual capacity for thirty years. LSP-Cottage Grove was
awarded the contract from a competitive negotiated process ordered by the MPUC
which considered six different vendors and projects. The purchase will be
from a natural gas- fired combined cycle facility that NSP can dispatch as
system requirements dictate. The MPUC requested the Minnesota Department of
Public Service (DPS) to review the reasonableness of the price NSP is paying
LSP-Cottage Grove for the capacity and energy. In December 1994 the DPS
issued its report concluding that the contract prices are appropriate. On
Feb. 2, 1995 the MPUC determined that the contract was at or below NSP's
avoided cost. The pricing considers both capacity and energy. NSP expects
the LSP-Cottage Grove facility to be available in May 1997.
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
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 all existing generating facilities will continue
operating through their license period or useful life.
The MPUC approved the Company's resource plan on July 15, 1994, but
directed the Company to make a compliance filing addressing the MPUC's
proposed modifications. These modifications reflect changes due to the
Prairie Island legislation enacted in 1994 and the inclusion of updated
information that became available after the resource plan was filed. The
Company submitted the compliance filing on Dec. 13, 1994. The revisions
submitted in the compliance filing do not significantly alter the Company's
resource plan filed in 1993.
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
Demand Side Management 500 1,200 1,700 2,000
Total 500-1,000 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 facilities.
- Demand reduction of 2,000 Mw by 2008 through conservation and load
management.
- 425 Mw of wind generation in service by 2002.
- 125 Mw of biomass generation in service by 2002.
- 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.
- Purchase of 245 Mw of natural gas-fired combined cycle generation.
- Competitive bidding to fill additional needs for new generation.
In connection with the approval of fuel storage facilities at the
Company's Prairie Island generation plant, legislation was enacted in 1994
which established certain resource commitments, as discussed in Note 17 to the
Financial Statements under Item 8. The Company has taken steps to comply with
the requirements of these resource commitments. 25 Mw of third party wind
generation has been fully operational since May 1, 1994 and is performing as
expected. All significant permit applications have been filed for another 100
Mw to be in service by November of 1996. The Company filed a proposal with
the MPUC in January 1995 for the first 50 Mw of biomass generation. In
addition, the Company announced its plan to seek significant public input in
its exploration for an alternate interim used nuclear fuel storage site in
Goodhue County, Minnesota. The Company's construction commitments disclosed
in Note 17 to the Financial Statements include the known effects of the 1994
Prairie Island legislation. The impact of the legislation on power purchase
commitments is not yet determinable.
The MPUC has begun a proceeding to establish values representing
environmental costs imposed by electric generation that are not part of the
price of electricity. These values are known as environmental externalities.
The values, expected to be established later in 1995, will be applied by the
MPUC in resource planning proceedings to determine the total social cost of
different generating options to supply the growing demand for electricity.
Depending on the values established and the manner in which they are applied,
externalities could significantly affect resources available to NSP to meet
future demands for electricity.
The Company continues to implement various Demand Side Management (DSM)
programs designed to improve load factor and reduce the Company's power
production cost and system peak demands, thus reducing or delaying the need
for additional investment in new generation and transmission facilities. The
Company currently offers a broad range of DSM programs to all customer
sectors, including information programs, rebate and financing programs, and
rate incentive programs. These programs are designed to respond to customer
needs and focus on increasing value of service that, over the long term, will
help its customer base become more stable, energy efficient and competitive.
During 1994, the Company's programs accomplished approximately 183 Mw of
system peak demand reduction. Since 1986, the Company's DSM programs have
achieved 1,012 Mw of summer peak demand reduction, which is equivalent to 14%
of its 1994 summer peak demand. The Company's operating goals, which go
beyond the resource plan guideline above, are to offset peak electric demand
by 1,100 Mw by 1995 and 1,700 Mw by 2000. The Company continues to focus on
improving the cost-effectiveness of its DSM programs through market research
studies, program evaluations and changes to its program mix.
In 1994, the MPUC improved the Company's cost recovery and incentives for
DSM by allowing recovery of a portion of the lost margins due to DSM impacts
on electric revenues. This lost margin recovery, subject to annual review by
the MPUC, was approximately $3 million in 1994. In addition, the MPUC allowed
the Company to earn another $4 million in DSM investment returns through an
incentive program that rewards the attainment of specified conservation goals.
Energy Sources
For the year ended Dec. 31, 1994, 47% of NSP's Kwh requirements was
obtained from coal generation and 28% was obtained from nuclear generation.
Purchased and interchange energy provided 21%, including 15% from Manitoba
Hydro; NSP's hydro and other fuels provided the remaining 4%. The fuel
resources for NSP's generation based on Kwh were coal (59%), nuclear (36%),
renewable and other fuels (5%).
The following is a summary of NSP's electric power output in millions of
Kwh for the past three years:
1994 1993 1992
Thermal plants 32,710 33,130 30,467
Hydro plants 922 1,001 1,024
Purchased and interchange 9,054 8,541 8,187
Total 42,686 42,672 39,678
Many of NSP's power purchases from other utilities are coordinated
through the regional power organization MAPP, pursuant to an agreement dated
March 31, 1972, with amendments filed in 1994. NSP is one of 49 participants
in MAPP consisting of 10 investor-owned systems, eight generation and
transmission cooperatives, three public power districts, seven municipal
systems, the Department of Energy's Western Area Power Administration and
20 Associate Participants. The MAPP agreement provides for the members to
coordinate the installation and operation of generating plants and
transmission line facilities. The terms and conditions of the MAPP
agreement and transactions between MAPP members are subject to the
jurisdiction of the FERC. The 1972 MAPP agreement, as amended, was accepted
for filing by the FERC on Dec. 15, 1994.
Fuel Supply and Costs
Coal and nuclear fuel will continue to dominate NSP's regulated utility
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 2 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 1994 and the estimated fuel mix
for 1995 and 1996 are as follows:
Fuel Use on Btu Basis
(Est) (Est)
1994 1995 1996
Coal 60.9% 61.1% 63.1%
Nuclear 37.4% 37.1% 35.1%
Other 1.7% 1.8% 1.8%
The Company normally maintains between 20 and 45 days of coal inventory
depending on the plant site. The Company has long-term contracts providing
for the delivery of up to 100 percent of its 1995 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 98% of the coal it burns in 1995 will
have a sulfur content of less than 1 percent. The Company has contracts with
three Montana coal suppliers, Westmoreland Resources, Western Energy, Big Sky
Coal Company and three Wyoming suppliers, Rochelle Coal Company, Antelope Coal
Company and Black Thunder Coal Company, for a maximum total of 60 million tons
of low-sulfur coal for the next 5 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 generating needs. The plants in the Minneapolis-St.
Paul area are about 800 miles from the mines in Montana and 1,000 miles from
the mines in Wyoming. Coal delivered by rail provides the Company with an
economical source of fuel.
The estimated coal requirements of the Company at its major coal-fired
generating plants for the periods indicated and the coal supply for such
requirements are as follows:
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 1,200,000 1,200,000 (1) 0.5 1.3(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
Riverside 1,300,000 1,300,000 (1) 0.7 2.5(4)
Sherco 8,000,000 8,000,000 (1) 0.5 0.9(5)
13,300,000 13,300,000(6)
*MBTU = Million British Thermal Units
Notes:
(1) Contract expiration dates vary between 1995 and 2005 for western coal,
which can provide up to 100% of the required fuel supply for the
designated generating unit. Spot market purchases of other western coal,
and other fuels will provide the remaining fuel requirements when such
purchases would improve fuel economics. The Company is also burning
petroleum coke as a source of fuel.
(2) This percentage represents the average blended sulfur content of the
combination of fuels typically burned at each plant.
(3) The Black Dog Fluidized Bed (Unit 2) SO2 limit is 1.2 lb/MBTU.
(4) The SO2 limitation at Riverside Unit 8 is 2.5 lb/MBTU. The limitation
for units 6 and 7 is currently 0.9 lb SO2 /MBTU.
(5) Compliance with air pollution control permit and applicable air quality
regulations requires use of limestone scrubbers to achieve 70% SO2
removal and a maximum limit of 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
0.60 lb/MBTU.
(6) Annual requirements are expected to range from 11.0 to 13.3 million.
The Company's current fuel oil inventory is adequate to meet anticipated
1995 requirements. Additional oil may be provided through spot purchases from
two local refineries and other domestic sources.
To operate the Company's nuclear generating plants, the Company secures
contracts for uranium concentrates, uranium conversion, uranium enrichment and
fuel fabrication. The contract strategy involves a portfolio of spot, medium
and long-term contracts for uranium, conversion and enrichment. Current
contracts are flexible and cover between 70% and 100% of uranium, conversion
and enrichment requirements through the year 1997. These contracts expire at
varying times between 1997 and 2005. The overlapping nature of contract
commitments will allow the Company to maintain 70% to 100% coverage beyond
1997, if appropriate. The Company expects sufficient uranium, conversion and
enrichment to be available for the total fuel requirements of its nuclear
generating plants. Fuel fabrication is 100% committed through the year 2003.
The Company expects the unit cost of fuel to produce electricity with these
nuclear facilities will be lower than the comparable cost of fuel to produce
electricity with any other currently available fuel sources for the sustained
operation of a generation facility. The cost of nuclear fuel, including
disposal, is recovered in the customer price of the electricity sold by the
Company.
The Company's fuel costs for the past three years are shown below:
Fuel Costs *
Per Million Btu
Year Ended December 31
1992 1993 1994
Coal** $ 1.22 $ 1.17 $1.22
Nuclear*** .43 .41 .47
Composite All Fuels .93 .90 .93
* Fuel adjustment clauses in its electric rate schedules or statutory
provisions enable NSP to adjust for fuel cost changes. (See "Utility
Regulation and Revenues - Fuel and Purchased Gas Adjustment Clauses"
under Item 1.)
** Includes refuse-derived fuel and wood.
*** See Note 1 to the Financial Statements under Item 8 for an explanation
of the Company's nuclear fuel amortization policies.
Nuclear Power Plants - Licensing, Operation and Waste Disposal
The Company operates two nuclear generating plants: the single unit, 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 one of only two utilities 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 in 1990.
Most of the plant's nuclear material, which was contained in the reactor
building and fuel handling building, was removed during 1991. Decommissioning
activities cost approximately $13 million and have been expensed. A few
millicuries of residual contamination remains 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 waste includes used nuclear fuel. Low-level radioactive wastes
are produced from other activities at a nuclear plant. They consist
principally of demineralizer resins, paper, protective clothing, rags, tools
and equipment that have become contaminated through use in the plant.
A 1980 federal law places responsibility on each state for disposal of
its low-level radioactive waste. The law encourages states to form regional
agreements or compacts to dispose of regionally generated waste. Minnesota
is a member of the Midwest Interstate Low-Level Radioactive Waste Compact
Commission. Following the expulsion of Michigan from the Midwest Compact in
1991 for failing to make progress, Ohio was designated the host state. The
State of South Carolina closed its disposal facility to out-of-region waste
on July 1, 1994. Ohio is projecting completion of the low-level radioactive
waste disposal facility in 2005. 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 used
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 used
nuclear fuel from civilian nuclear power reactors and other high-level
radioactive wastes.
The Company has contracted with the DOE for the disposal of used 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. 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 used nuclear fuel storage
facilities at its Monticello Plant by replacement of the racks in the storage
pool. Also, in 1987, the Company completed the shipment of 1,058 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. Storage availability for operation beyond
2008 is not assured at this time.
In 1976 the Company began expanding the used nuclear fuel storage
facilities at its Prairie Island Plant by replacement of the racks in the
storage pool. Total capacity was increased from 210 fuel assemblies to 1,386
fuel assemblies. The used nuclear fuel storage facilities at the Company's
Prairie Island Plant are expected to reach full capacity during 1995. In May
1994 additional on-site dry cask fuel storage facilities were approved by the
Minnesota Legislature which are expected to provide sufficient storage
capacity to operate the plant until at least 2002, provided the Company
satisfies certain responsibilities. Seventeen dry cask containers, each of
which can store approximately one-half year's used fuel, can become available
as follows: five immediately in 1994; four more in 1996 if an application for
an alternative storage site is filed, an effort to locate such a site is made
and 100 MW of wind generation is available or contracted for construction; and
the final eight in 1999 unless the specified alternative site is not
operational or under construction, certain resource commitments are not met
or the Minnesota Legislature revokes its approval.
An updated nuclear decommissioning study and nuclear plant depreciation
capital recovery request was filed with the MPUC in July 1994 for the
Company's nuclear power plants. Although management expects to operate the
Prairie Island plant units through the end of its useful lives, the requested
capital recovery would allow for the plant to be fully depreciated, including
the accrual and recovery of decommissioning costs, about six years earlier
than the end of its useful life. The proposed cost recovery period has been
reduced because of the uncertainty regarding the spent fuel storage situation.
On Jan. 25, 1995 the MPUC issued an order approving this filing. On Feb. 14,
1995 the North American Water Office (NAWO) filed a petition for
reconsideration with the MPUC to change the capital recovery period for
Prairie Island, so that the plant is fully depreciated by 2002. The petition
concerns the issue of used nuclear fuel storage after 2002. A decision by the
MPUC is expected by the end of 1995.
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 $528 million since 1971, and approximately $6 million, $11 million and
$53 million for 1994, 1993 and 1992, respectively. In addition, the Company
expects to expend an additional $2 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 16 to the Financial Statements under Item 8 for further
discussion of nuclear fuel disposal issues and information on decommissioning
of the company's nuclear facilities. Also, see Note 17 to the Financial
Statements under Item 8 for a discussion of the Company's nuclear insurance
and potential liabilities under the Price-Anderson liability provisions of the
Atomic Energy Act of 1954.
Electric Operating Statistics
The following table summarizes the revenues, sales and customers from
NSP's electric transmission and distribution business:
1994 1993 1992 1991 1990
Revenues (thousands)
Residential
With space heating $ 66 962 $ 68 222 $ 63 376 $ 67 878 $ 62 823
Without space heating 616 821 583 371 534 676 568 672 522 580
Small commercial and industrial 351 287 327 888 312 581 315 946 299 392
Large commercial and industrial 824 195 780 444 718 712 713 177 671 621
Street lighting and other 28 936 29 214 29 764 30 720 29 549
Total retail 1 888 201 1 789 139 1 659 109 1 696 393 1 585 965
Sales for resale 146 239 159 498 137 962 145 008 137 965
Miscellaneous 32 204 26 279 26 245 21 837 25 161
Total $ 2 066 644 $1 974 916 $ 1 823 316 $ 1 863 238 $ 1 749 091
Sales (millions of kilowatt-hours)
Residential
With space heating 1 076 1 094 1 041 1 141 1 068
Without space heating 8 227 7 998 7 640 8 226 7 805
Small commercial and industrial 5 585 5 307 5 224 5 330 5 180
Large commercial and industrial 17 874 17 117 16 365 16 286 15 867
Street lighting and other 334 344 372 386 385
Total retail 33 096 31 860 30 642 31 369 30 305
Sales for resale 6 733 8 044 6 530 6 083 6 281
Total 39 829 39 904 37 172 37 452 36 586
Customer accounts (Dec. 31)
Residential
With space heating 76 050 75 644 74 939 74 646 74 623
Without space heating 1 146 578 1 131 928 1 119 354 1 104 772 1 091 291
Small commercial and industrial 142 858 141 446 140 768 139 266 138 066
Large commercial and industrial 8 172 8 114 7 904 7 758 7 442
Street lighting and other 4 836 4 813 4 627 7 662 7 435
Total retail 1 378 494 1 361 945 1 347 592 1 334 104 1 318 857
Sales for resale 70 71 74 72 78
Total 1 378 564 1 362 016 1 347 666 1 334 176 1 318 935
GAS UTILITY OPERATIONS
Competition
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 Natural
Gas Company (Northern), Viking, Williston Basin Interstate Pipeline Company
(Williston) and Great Lakes Transmission Limited Partnership (Great Lakes).
Approximately 90 percent of NSP's retail gas customers are served from the
Northern pipeline system.
During 1992 and 1993, the FERC issued a series of orders (together called
Order 636) that addressed interstate natural gas pipeline restructuring. This
restructuring required all interstate pipelines, including those serving NSP,
to "unbundle" each of the services they provide: sales, transportation,
storage and ancillary services. 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 transportation agreements to be no greater
than the risk faced under the previous long-term full requirements gas supply
contracts with interstate pipelines.
As a result of the changes in the natural gas industry in the last
decade, culminating in Order 636, the natural gas supply network throughout
North America 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 contracts 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 a 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 the new unbundled services under Order 636 have to
date proved to be as reliable and flexible as the traditional sales service.
The implementation of Order 636 applies 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 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 increase
certain of 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, is in the process of determining
the final amount of transition costs to be passed on to customers as a result
of Order 636 restructuring. Northern's restructuring 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 its transportation charges. NSP
estimates that it will be responsible for less than $12 million of Northern's
transition costs, spread over a period of approximately five years, which began
Nov. 1, 1993. To date, NSP's regulatory commissions have approved recovery of
restructuring charges in retail gas rates.
NSP has no significant Order 636 transition cost responsibilities to its
other pipeline suppliers. FERC has ruled that NSP has no transition cost
obligation to Williston for its primary transportation service since it was
never a gas sales customer of that pipeline. Viking incurred no Order 636
transition costs. NSP does not have significant transportation service on ANR
Pipeline and Great Lakes subject to transportation cost charges under pricing
in effect after Order 636.
The gas services available to NSP's customers were enhanced beginning 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.
Viking provides NSP with continued access to competitive interstate natural
gas transportation. Cenergy can provide more customized value-added energy
services to retail gas customers without increasing costs within the regulated
retail gas distribution business. See 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 installed a state-
of-the-art delivery management system in July 1994.
NSP's gas utility took advantage of opportunities to expand into new
service territory during 1994. NSP extended service to 15,300 customers in
13 new communities. In addition to exploring new growth opportunities
available, NSP is also focusing on conversion of potential customers who are
located near NSP's gas mains but are not hooked up to receive the service.
NSP estimates there are approximately 18,000 potential customers that fall
into this category.
The largest 1994 expansion project occurred in Crow Wing and Cass
counties in north central Minnesota. Outside the St Paul-Minneapolis area,
these counties are experiencing the fastest growth of all counties in
Minnesota. The project included laying approximately 550 miles of pipeline
in 10 of the cities in the Brainerd Lakes area. The project's net capitalized
investment cost was approximately $23 million. Construction began in June
1994 and was completed in November 1994. There were 6,300 new customers
signed up under this project as of Dec 31, 1994. The MPUC approved a "new
town" rate surcharge for customers in this area to support NSP's capital
investment in the project. Subject to continued regulatory approval, the
surcharge will be in effect for up to 15 years.
The Company's gas operation has organized a non-utility service offering
individuals service contracts on a variety of home appliances. Working in
partnership with local independent service contractors, NSP Advantage Service
offers 24 hour service. Depending on the level of service contracted,
Advantage Service customers have coverage to help avoid the expense and
inconvenience of unexpected appliance repairs. This service is being offered
to individuals within NSP's service territory.
Capability and Demand
NSP categorizes its gas supply requirements as firm (primarily for space
heating customers) or interruptible (commercial/industrial customers with an
alternate energy supply). NSP's maximum daily sendout (firm and
interruptible) of 686,130 MMBtu for 1994 occurred on Jan. 17, 1994.
NSP's primary gas supply sources are purchases of third-party gas which
are delivered under gas transportation service agreements with interstate
pipelines. 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. These agreements provide for firm
deliverable pipeline capacity of approximately 540,396 MMBtu/day. Using
storage reduces the need for firm gas supplies. These storage agreements
provide NSP storage for approximately 16% of annual and 32% of peak daily firm
requirements. NSP also owns and operates three liquified 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 242,300
Mcf of natural gas per day, or approximately 35% of peak day firm
requirements. NSP's LNG and propane-air plants provide a cost-effective
alternative to annual fixed pipeline transportation charges to meet the
"needle peaks" caused by firm space heating demand on extremely cold winter
days.
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.
Gas Supply and Costs
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
1995 through 2012.
Northern Natural Gas Great Lakes Transmission Limited Partnership
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 $20.4 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, 1994, NSP was committed to
approximately $376.5 million in such obligations under these contracts, over
the remaining contract terms, which range from the years 1995-2013. These
obligations include some of the effects of contract revisions made to comply
with Order 636. NSP has negotiated "market out" clauses in its new supply
agreements, which reduce NSP's purchase obligations if NSP no longer provides
merchant gas service.
NSP purchases firm gas supply from a total of approximately 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.
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. The MPUC has approved all the Company's transportation contracts with
Viking and a spot gas purchase agreement with Cenergy. Requests for approval
between the Company and the Wisconsin Company and between the Company and
NSP's generating plants are pending MPUC approval.
The following table summarizes the average cost per MMBtu of gas
purchased for resale by NSP's gas distribution business which excludes Viking
and Cenergy:
The Company Wisconsin Company
1991 $2.50 $2.73
1992 $2.71 $2.80
1993 $3.11 $3.02
1994 $2.59 $3.13
Gas Operating Statistics
The following table summarizes the revenue, sales and customers from
NSP's gas business:
1994 1993 1992 1991 1990
Revenues (thousands)
Residential
With space heating $ 204 668 $ 220 828 $ 178 164 $ 179 161 $ 164 039
Without space heating 2 838 2 715 2 523 2 614 2 711
Commercial and industrial
Firm 120 912 131 431 105 829 105 703 97 015
Interruptible 49 384 52 216 41 612 40 768 43 779
Interstate transmission (Viking)* 14 075 9 019 0 0 0
Miscellaneous ** 28 026 12 867 8 078 9 674 7 913
Total $ 419 903 $ 429 076 $ 336 206 $ 337 920 $ 315 457
Sales (thousands of mcf)
Residential
With space heating 38 427 40 946 35 136 37 493 33 445
Without space heating 323 331 323 359 370
Commercial and industrial
Firm 27 342 28 622 24 273 25 429 22 793
Commercial and industrial 19 373 18 559 15 823 15 813 16 730
Miscellaneous 212 186 108 325 555
Total 85 677 88 644 75 663 79 419 73 893
Other gas delivered (thousands of mcf)
Interstate transmission (Viking) * 131 074 75 188 0 0 0
Agency, transportation and
off-system sales 13 466 8 128 7 332 7 549 6 298
Total 144 540 83 316 7 332 7 549 6 298
Customer accounts (at Dec. 31)
Residential
With space heating 351 773 337 868 326 439 314 843 303 402
Without space heating 18 961 19 408 19 841 20 294 21 004
Commercial and industrial 37 140 36 185 35 458 34 663 33 749
Total 407 874 393 461 381 738 369 800 358 155
* Excludes $2.2 million of revenues (16,845 thousands of mcfs) for
intercompany sales in 1994.
** Includes NSP revenues for agency and transportation services and off-system
sales.
NRG ENERGY, INC.
NRG Energy, Inc. (NRG) is the Company's subsidiary that develops, builds,
acquires, owns and operates several non-regulated energy-related businesses.
It was incorporated in Delaware on May 29, 1992 and assumed ownership of the
assets of NRG Group, Inc., including its subsidiary companies. The businesses
that NRG currently owns or operates generated 1994 revenues of $81 million and
had assets of $407 million at Dec. 31, 1994.
NRG conducts business through various subsidiaries, including: 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.; NEO Corporation; NRG
Energy Center, Inc.; NRG Sunnyside Inc. and NRG Operating Services, Inc.
Operating Businesses
In Dec. 1993, NRG, through a wholly owned foreign subsidiary, agreed to
acquire a 33% interest in the coal mining, power generation and associated
operations of Mitteldeutsche Braunkohlengesellschaft mbh (MIBRAG), located
south of Leipzig, Germany. MIBRAG is a German corporation formed by the
German government to hold two open-cast brown coal (lignite) mining
operations, a lease on an additional mine, the associated mining rights and
rights to future mining reserves, two small industrial power plants and a
circulating fluidized bed power plant, a district heating system and coal
briquetting and dust production facilities. Under the acquisition agreement,
Morrison Knudsen Corporation and PowerGen plc also each acquired a 33%
interest in MIBRAG, while the German government retained a one-percent
interest in MIBRAG. The investor partners began operating MIBRAG effective
Jan. 1, 1994 and the legal closing occurred Aug. 11, 1994. NRG's acquisition
investment in MIBRAG, including capitalized development costs, was
approximately $16 million.
In March of 1994, NRG, through wholly owned foreign subsidiaries, as part
of an unincorporated joint venture with Comalco Limited of Australia (Comalco)
and other parties, acquired a 37.5% interest in the Gladstone Power Station,
a 1680 Mw coal-fired plant in Gladstone, Queensland, Australia from the
Queensland Electricity Commission. A large portion of the electricity
generated by the station is sold to Comalco for use in its aluminum smelter,
pursuant to long-term power purchase agreements. NRG, through an Australian
subsidiary, operates the Gladstone plant. NRG's acquisition investment in the
Gladstone project, including capitalized development costs, was approximately
$70 million.
NRG operates two refuse-derived fuel (RDF) processing plants and an ash
disposal site in Minnesota. The ownership of one plant was transferred by the
Company to NRG at the end of 1993. The legal transfer of ownership of the
Company's 85% share of the other RDF plant and of the ash disposal site was
approved by the serviced counties with transfer to NRG expected in 1995. In
1994, workers at the RDF plants processed more than 730,000 tons of municipal
solid waste into approximately 640,000 tons of RDF that was burned at two NSP
power plants and at a power plant owned by United Power Association.
NRG also owns 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.
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 facilities utilizing
landfill gas. During 1994, the ownership of NEO Corporation was transferred
by the Company to NRG. On Dec. 20, 1994, NEO acquired a 50% ownership in STS
HydroPower Limited, an independent power producer with 21 Mw of hydroelectric
facilities throughout the United States. NEO's acquisition investment in STS
was approximately $4 million.
NRG, through wholly owned subsidiaries, owns 45% of the San Joaquin
Valley Energy partnership, (SJVEP), which owns four power plants located near
Fresno, California with a total capacity of 55 Mw. Through February 1995, the
plants operated under long-term Standard Offer 4 (SO4) power sales contracts
with Pacific Gas & Electric (PG&E) which expire in 2017. On February 28, 1995
PG&E reached basic agreements with SJVEP to acquire the SO4 contracts. The
parties entered into a bridging agreement to cover the period until all
regulatory approvals are received for the transaction. The bridging agreement
required SJVEP to cease power deliveries to PG&E as of February 28, 1995. The
negotiated agreements will result in cost savings for PG&E customers as well
as economic benefits for SJVEP. The final impact of this transaction on the
financial results of NSP will not be known until the agreements have been
approved and all costs associated with the idling of the facilities are known.
It is expected that a one-time gain from the transaction will be recorded in
the first half of 1995. SJVEP will continue to own and maintain the
facilities and will explore all available options.
NRG, through wholly owned subsidiaries, owns 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.
NRG, through a wholly owned subsidiary, purchased the assets of the
Minneapolis Energy Center (MEC), a downtown Minneapolis district heating and
cooling system in August of 1993. The system utilizes steam and chilled water
generating facilities to heat and cool buildings for approximately 90 heating
and 30 cooling customers. The primary assets include the main plant, with
800,000 lbs/hour of steam capacity and 22,000 tons/hour of chilled water
capacity, three satellite plants, two standby plants, six miles of steam lines
and two miles of chilled water distribution lines. Existing long-term
contracts with MEC customers remain in effect under NRG's ownership.
On Dec. 31, 1994 NRG, through a wholly owned subsidiary, purchased a 50%
ownership interest in Sunnyside Cogeneration Associates (SCA), a Utah joint
venture (partnership), which owns and operates a 51 Mw waste coal plant in
Utah. The acquisition investment by NRG was approximately $11 million. The
waste coal plant is currently being operated by a 50% owned NRG partnership.
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, has the ability 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. NRG's net
capitalized investment in the Scoria coal project was written down by $3.5
million in 1994 to reflect reductions in the expected future operating cash
flows from the project. NRG continues to evaluate the recoverability of its
remaining investment in the Scoria project.
New Business Development
NRG is pursuing several energy-related investment opportunities,
including those discussed below, and continues to evaluate other opportunities
as they arise. Potential capital requirements for these opportunities are
discussed in the "Capital Spending and Financing" section.
On Dec. 10, 1993, NRG, through a wholly owned foreign subsidiary,
acquired a 50% interest in a German corporation, Saale Energie GmbH (Saale).
Saale owns a 400 Mw share of a 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
Gelsenkirchen, Germany (VKR), is the builder of the Schkopau plant. VKR owns
the remaining 58.9% interest in the power plant and will operate the plant.
The plant will be fired by brown coal (lignite) mined by MIBRAG under a long-
term contract. Saale has a long-term power sales agreement for its 400 Mw
share of the Schkopau facility with VEAG of Berlin, Germany, the company that
controls the high-voltage transmission of electricity in the former East
Germany. The first 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. Through Dec. 31,
1994 NRG had invested $20 million to acquire its interest in Saale including
capitalized development costs. NRG's future equity commitment to Saale
through 1996 is expected to be no more than $50 million.
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
(Scudder), 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 four 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. As
of Dec. 31, 1994, NRG has invested $4 million in Scudder. Scudder has reached
agreements to purchase shares of two power plant projects in Latin America.
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. Because of
the uncertainty surrounding the ultimate successful operation of this plant,
NRG wrote off its $1.5 million investment in Graystone during 1994.
Other
In July 1994, Michigan Congeneration Partners Limited Partnership (MCP),
a partnership between subsidiaries of NRG and Cogentrix Energy, Inc., reached
an agreement with Consumers Power Company (Consumers), an electric utility
headquartered in Jackson, Michigan, to terminate the power sales contract
related to a 65 megawatt congeneration facility being developed by MCP in
Parchment, Michigan. The agreement to terminate the contract required
Consumers to make a payment to MCP of $29.8 million. As a result, NRG has
recorded a net pretax gain from the termination of this contract of $9.7
million, which increased NSP's earnings by approximately nine cents per share
in the third quarter of 1994.
OTHER SUBSIDIARIES
Viking Gas Transmission Company
In June 1993, the Company acquired 100 percent of the stock of Viking Gas
Transmission Company (Viking) from Tenneco Gas, a unit of Tenneco Inc., in
Houston, Texas. Viking, which is now a wholly owned subsidiary of the
Company, owns and operates a 500-mile interstate natural gas pipeline serving
portions of Minnesota, Wisconsin and North Dakota with a capacity of
approximately 400 million cubic feet per day. The Viking pipeline currently
serves 10 percent of NSP's gas distribution system needs. Viking currently
operates exclusively as a transporter of natural gas for third-party shippers
under authority granted by the FERC. Rates for Viking's transportation
services are regulated by FERC. See "Rate Matters by Jurisdiction" herein
regarding rate recovery requested for a portion of the acquisition cost paid
by NSP to acquire Viking.
Cenergy, Inc.
NSP's non-regulated wholly owned subsidiary, Cenergy, Inc., commenced
operations in October 1993 through the acquisition from bankruptcy of selected
assets of Centran Corporation, a natural gas marketing company. Cenergy, in
addition to marketing natural gas, provides customized value-added energy
services to retail customers, both inside NSP service territory and on a
national basis through its offices in Houston, TX; Louisville, KY; Chesapeake,
VA; Dallas, TX; Corpus Christi, TX; Chicago, IL; and Pittsburgh, PA. Cenergy
offers customers many energy products and services including: utility billing
analysis, end-use gas marketing, risk management, construction, energy
services consulting and administrative services. The MPUC has approved an
affiliate transaction contract, whereby Cenergy may make natural gas sales at
market based rates (determined by competitive bids) to NSP for resale to
retail gas customers.
On Dec. 1, 1994 the FERC approved Cenergy's application to sell electric
power (except electricity generated by NSP) in the United States, giving NSP
an opportunity to enter the increasingly deregulated and competitive electric
market. Cenergy is one of the first utility affiliates to obtain this
approval from FERC. NSP is allowing open access to its electric transmission
lines by other electric power providers throughout North America. Cenergy's
initiative to buy and sell deregulated electricity is consistent with NSP's
objective to embrace competition, which will benefit NSP customers and
shareholders.
On January 19, 1995 Cenergy and Atlantic Energy Enterprises signed a
memorandum of understanding to establish Atlantic CNRG Services LLC, a new
subsidiary of both companies. Each company will own 50% of the new venture
that will develop new and expanded natural gas and electric energy products
and services, primarily in the Northeast region.
Eloigne Company
In 1993, the Company established Eloigne Company (Eloigne), to identify
and develop affordable housing investment opportunities. Eloigne's principal
business is the acquisition of a broadly diversified portfolio of rental
housing projects which qualify for low income housing tax credits under
federal tax law. As of Dec. 31, 1994, approximately $19 million had been
invested in Eloigne projects. Tax credits recognized in 1994 as a result of
these investments were approximately $2.0 million.
ENVIRONMENTAL MATTERS
NSP's policy is to proactively prevent adverse environmental impacts by
regularly monitoring 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 strives to
maintain compliance with all applicable environmental laws.
In general, the Company has been experiencing a trend toward increasing
environmental monitoring and compliance costs, which has caused and may
continue to cause slightly higher operating expenses and capital expenditures.
The Company has spent approximately $700 million on capitalized environmental
improvements to new and existing facilities since 1968. The Company expects
to incur approximately $15 million in capital expenditures and approximately
$9 million in operating expenses for compliance with environmental regulations
in 1995. The precise timing and amount of future environmental costs are
currently unknown. (For further discussion of environmental costs, see
"Environmental Matters" under Management's Discussion and Analysis of
Financial Condition and Results of Operations under Item 7, and Note 17 to the
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 onsite storage pool for used nuclear fuel at the Company's Monticello
Nuclear Generating Plant is expected to provide sufficient storage capacity
to operate the plant until 2008.
The onsite storage pool for used nuclear fuel at the Company's Prairie
Island Nuclear Generating Plant (Prairie Island) was filled during refueling
in June 1994, so adequate space for a subsequent refueling was no longer
available. In anticipation of this, the Company, in 1989, proposed
construction of a temporary onsite dry cask storage facility for used nuclear
fuel at Prairie Island. The Minnesota Legislature (Legislature) considered
the dry cask storage issue during its 1994 legislative session as required by
a Minnesota Court of Appeals ruling in June 1993.
On May 10, 1994, the Governor of the State of Minnesota (Governor) signed
into law a bill passed by the Legislature on May 6, 1994. The law authorizes
the Company to install 17 dry casks at Prairie Island, which should provide
storage capacity to allow operation until at least 2002 and 2003 for units 1
and 2 respectively, if the Company satisfies certain responsibilities. The
Company executed an agreement with the governor concerning the renewable
energy and alternative siting commitments contained in the new law and is now
authorized to install the first increment of five casks. The second increment
of four casks would be available if the Minnesota Environmental Quality Board
finds that by Dec. 31, 1996, the Company has applied to the Nuclear Regulatory
Commission for an alternative site license for the temporary used nuclear fuel
storage facility, used good faith in locating an alternative site and has
committed to build or purchase 100 megawatts of wind generation. The final
increment of eight casks would be available unless prior to June 1, 1999, the
Legislature specifically revokes the authorization for the final eight casks.
The Legislature can revoke the authorization if an alternative storage site
is not operational or under construction, or the Company fails to meet certain
renewable energy commitments, including the increased use of wind power and
biomass generation facilities by Dec. 31, 1998. (See Notes 16 and 17 of Notes
to Financial Statements under Item 8 for further discussion of this matter.)
During 1994, NSP and a group of 30 other utilities and two private firms
formed a consortium to establish a temporary used nuclear waste storage site.
On March 9, 1995 the Mescalero Apache tribal members, in a second referendum,
voted in favor of proceeding with a temporary used nuclear fuel storage site
on reservation lands in New Mexico. The consortium is preparing to invest
$135 million to prepare a license application, conduct environmental studies,
pay host fees to the Mescalero tribe and construct a storage facility that
could open in 2002.
The Company and NRG have contractual commitments to convert municipal
solid waste to boiler fuel and burn the fuel to generate electricity. NRG
owns and/or operates two 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 nearly all known PCB capacitors from its
distribution system. NSP also has removed nearly all known network PCB
transformers and equipment in power plants containing PCBs. NSP continues to
test and dispose of PCB-contaminated mineral oil and equipment in accordance
with regulations. PCB-contaminated mineral oil is detoxified and reused or
burned for energy recovery at permitted facilities. Any future cleanup or
remediation costs associated with past PCB disposal practices is unknown at
this time.
Air Emissions Control And Monitoring
In September 1994, the U.S Environmental Protection Agency (EPA) proposed
new air emission guidelines for municipal waste combustors. These proposed
guidelines are expected to be finalized in September 1995. Once the federal
guidelines are finalized, the MPUC will update Minnesota state waste combustor
rules to meet or be more restrictive than the final federal guidelines. The
deadline for complying with these rules is June 1997. To meet the new federal
and state requirement, the Company must install additional pollution control
and monitoring equipment at the Red Wing plant and additional monitoring
equipment at the Wilmarth plant. The Company is evaluating equipment to meet
the requirements. Equipment may cost between $6 million and $10 million.
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. These limits will be phased in
beginning in 1995. The majority of the rules implementing this complex
legislation are finalized. No capital expenditures are anticipated to comply
with the sulfur dioxide emission limits of the Clean Air Act. Based on
revisions to the sulfur dioxide portion of the program, NSP's emission
allowance allocations for the years 1995-1999 were dramatically reduced from
prior rulemaking. In 1994, $5 million was spent and it is expected that
approximately $7 million will be spent on equipment at generation facilities
to reduce emissions of nitrogen oxides for compliance with the Clean Air Act
over the next 4 years. The Sherburne County Generating Plant's (Sherco) unit
2 Low Nox Burner Technology was upgraded in 1994 to further reduce its
emissions of nitrogen oxides. The same upgrade is scheduled for Sherco unit
1 in 1998. Other expenditures may be necessary upon EPA's finalization of
remaining rules. Capital expenditures will be required for opacity compliance
in 1995-1999 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 Sherco generating plant. The equipment will be installed in 1995
inside one of the existing acid gas scrubber modules. Testing, anticipated
to be completed in 1996, 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 approximately
$300 million for other technology options.
In December 1994, the Wisconsin Company completed installation of a
control center monitoring system at the Bay Front generating plant in Ashland,
Wisconsin. The control center which will monitor emission from the four
generating units, was mandated by the Clean Air Act. The total cost of the
project was approximately $1.3 million.
The Company has conducted testing for air toxics at its major facilities
and shared these results with state and federal agencies. The Company also
conducted research on ways to reduce mercury emissions. This information has
also been shared with state and federal agencies. The Clean Air Act requires
the EPA to look at issuing rules for air toxic emissions from electric
utilities. A report on this is due from the EPA to Congress in 1995. There
is continued interest at the Minnesota Legislature to pass legislation
restricting emissions of air toxics in the state. The Company cannot predict
what impact these rules will have if 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 the 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
Through the end of 1994, the Company had been designated by the EPA or
state environmental agencies as a "potentially responsible party" (PRP) for
10 waste disposal sites to which the Company allegedly sent hazardous
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 $122 million for all 10 PRP sites. In the event
additional remediation is necessary or unexpected costs are incurred, the
amount could be in excess of $122 million. The Company is not aware of the
other parties inability to pay, nor does it know if responsibility for any of
the sites is disputed by any party.
Settlement with the EPA, state environmental agencies and other PRPs has
been reached for six of these waste disposal sites for reimbursement of the
past costs and expected future costs of remedial action. 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.
For the remaining four 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 four sites is approximately $1.0 million, which was
recorded as a liability at Dec. 31, 1994.
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.
In February 1995 a settlement was reached regarding one of the four sites
for which the Company had been designated a PRP. The Company's allocation of
costs approximated the liability accrued at Dec. 31, 1994.
Both the Company and the Wisconsin Company have received notices for
requests for information concerning groundwater contamination at a landfill
site in Wisconsin. While neither the Company nor the Wisconsin Company have
been named PRP's, both companies voluntarily joined a group of other parties
to address the contamination at this site. A preliminary estimate of total
remediation costs at the site is approximately $6 million. The Company's and
Wisconsin Company's share of this cost is currently estimated to be
approximately 1%. In addition, the administrator of a group of PRP's has
notified the Wisconsin Company that it might be responsible 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 PRP's has been determined, it
is not feasible to predict the outcome of the matter at this time.
On March 2, 1995, the Wisconsin Department of Natural Resources (WDNR)
notified the Wisconsin Company that it is a PRP at a creosote/coal tar
contamination site in Ashland, WI. The Wisconsin Company has informed the
WDNR of its belief that two sites exist. The first site, formerly a coal gas
plant site, is NSP property. The second site is adjacent to the NSP site and
is not owned by the Wisconsin Company. An existing condition report has been
completed on an adjacent site. An estimate of site remediation costs, and the
extent of the Wisconsin Company's responsibility, if any, for sharing such
costs, is not known at this time. Investigations are underway to determine
the Wisconsin Company's responsibility as well as that of predecessor
companies contributing to the contamination on the adjacent site. The current
estimate of the Wisconsin Company's share of future remediation costs at the
NSP site is less than $750,000. This estimate is not based upon a formal
remediation investigation and feasibility study. To the Wisconsin Company's
knowledge, no study has been completed for the adjacent site, that describes
remedial alternatives and clean-up cost estimates. The Wisconsin Company
intends to seek rate recovery of significant costs it incurs associated with
the clean-up of either Ashland Site.
On March 13, 1995, the Minnesota Pollution Control Agency (MPCA) notified
the Company that it intends to seek reimbursement from the Company for costs
incurred at a disposal site in Rosemount, Minnesota. The Company has
commenced an investigation to determine its involvement with the site. The
MPCA has sought reimbursement of $139,000 from all parties. The extent of the
Company's responsibility, if any, for sharing such costs, is not known at this
time.
The Company is continuing to investigate 15 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 $14 million to
approximately $18 million, including $5.3 million which has been paid to date.
The Company has commenced remediation efforts at five of the 15 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.
In addition, the Company has been notified that two other sites will require
remediation, and a study will be conducted to determine the cost of clean up.
No agreement or consent order has been negotiated to perform any extensive
site investigations or clean-up at the other eight sites. 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. In 1994 the Company
received approval of deferred accounting for certain investigation and
remediation expenses. The ultimate rate treatment of any costs deferred will
be determined in the Company's next general gas rate case. (See Note 17 of
Notes to the Financial Statements under Item 8 for further discussion of this
matter.)
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 in utility plant and include them in depreciation accruals.
Removal cost estimates used to record depreciation expense are designed to
recover the future cost to remove existing plant assets. Factors used to
develop these estimates include historical expenses as well as engineering
estimates.
Contingencies
In October 1992, the Company disclosed to the 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. The Company and the MPCA are
currently negotiating a Stipulation Agreement to address monitoring procedures
used at Prairie Island between January and September 1992 that allegedly did
not comply with the permits. The MPCA is alleging noncompliance with permit
terms and conditions and is proposing a civil penalty of $105,436.
Electric and magnetic fields (sometimes referred to as EMF) surround
electric wires and conductors of electricity such as electrical tools,
household wiring, appliances, electric distribution lines, electric
substations and high-voltage electric transmission lines. NSP owns and
operates many of these types of facilities. Some studies have found
statistical associations between surrogates of EMF and some forms of cancer.
The nation's electric utilities, including NSP, have participated in the
sponsorship of more than $50 million in research to determine the possible
health effects of EMF. 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 $409 million in
1994, compared to $362 million in 1993 and $428 million in 1992 These capital
expenditures include gross additions to utility property of $387 million, $357
million (excluding Viking property acquired) and $423 million for years ended
1994, 1993 and 1992, respectively. Internally generated funds could have
provided approximately 69% of all capital expenditures for 1994, 99% for 1993
and 49% for 1992.
NSP's utility capital expenditures (including allowance for funds used
during construction) are estimated to be $383 million for 1995 and $1.9
billion for the five years ended Dec. 31, 1999. Included in NSP's projected
utility capital expenditures is $51 million in 1995 and $267 million during
the five years ended Dec. 31, 1999, for nuclear fuel for NSP's three existing
nuclear units. The remaining capital expenditures through 1999 are for many
utility projects, none of which are extraordinarily large relative to the
total capital expenditure program. Internally generated funds from utility
operations are expected to equal approximately 85% of the 1995 utility capital
expenditures and approximately 95% of the 1995-1999 utility capital
expenditures. Internally generated funds from all operations are expected to
equal approximately 60% and 80% respectively, of the total capital
expenditures anticipated for 1995 and the five-year period 1995-1999. 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.
In addition to capital expenditures, NSP invested $137 million in 1994
and $184 million in 1993 to acquire interests in non-regulated businesses and
Viking. Investments in 1993 included business acquisitions of $159 million.
(See "NRG Energy, Inc." and "Other Subsidiaries" herein.) NSP continues to
evaluate opportunities to enhance its competitive position and shareholder
returns through strategic acquisitions of existing businesses. Long-term
financing may be required for acquisitions that NSP consummates.
Although they may vary depending on the success, timing, and level of
involvement in planned and future projects, potential capital requirements for
investments in existing and additional non-regulated projects are estimated
to be $153 million in 1995 and $623 million for the five-year period 1995-
1999. The majority of these non-regulated capital requirements relate to
equity investments (excluding costs financed by project debt) in NRG's
projects, as discussed previously. The remainder consists mainly of
affordable housing investments by Eloigne Company. Equity investments by NRG
and Eloigne would be funded through their own internally generated funds,
equity investments by NSP, or long-term debt issued by the subsidiary. 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.
EMPLOYEES AND EMPLOYEE BENEFITS
At year end 1994 the total number of full- and part-time employees of NSP
was approximately 7,670. NSP is represented by five local IBEW labor unions.
On May 2, 1994 the IBEW members voted to ratify a three year labor agreement
retroactive to Jan. 1, 1994. Labor and employee benefit costs are not
expected to be materially affected by the terms of the new agreement.
NSP recently reviewed employee and retiree benefits and implemented the
following changes effective in 1994. These changes support NSP's goal of
providing market-based benefits.
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
implemented with retirees paying 15 percent of the total cost of health care
in 1994, increasing to a total of 40% in 1999.
Nonbargaining pension plan lump sum option changes: Prior to 1994,
nonbargaining employees had the option to receive their pension in either a
lump sum or in monthly installments. Beginning in 1994, nonbargaining
employees can 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. At the end of
1994, this benefit was modified to allow a lump sum option only on the portion
of pension benefit earned through Dec. 31, 1994.
401(k) changes: NSP currently offers eligible employees a 401(k)
Retirement Savings Plan. In 1994, NSP matched employees' pre-tax 401(k)
contribution up to $500 per year for nonbargaining employees and up to $400
per year for bargaining employees. In 1994, NSP's matching contribution was
$2.6 million. In 1995, NSP's annual match will increase to $700 for
nonbargaining employees. Under the terms of the bargaining agreement
implemented in 1994, NSP's annual match for bargaining employees will increase
to $500 in 1995 and $600 in 1996.
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 salary surveys that
indicate how local and regional companies pay their employees for comparable
positions. In January 1995, nonbargaining employees received an average wage
scale increase of 3.5%, while bargaining employees received a 2% base wage
increase and 1.5% lump sum payment. As part of the new labor agreement,
bargaining employees are no longer included in the Company's incentive
compensation plan.
EXECUTIVE OFFICERS *
Present Positions and Business Experience
Name Age During the Past Five Years
James J Howard 59 Chairman of the Board, President and Chief
Executive Officer since 12/1/94; Chairman of the
Board and Chief Executive Officer from 7/01/90 to
11/30/94; and prior thereto Chairman of the
Board, President and Chief Executive Officer.
Douglas D Antony 52 President - NSP Generation since 9/07/94; Vice
President - Nuclear Generation from 1/01/93 to
9/06/94; General Manager - Monticello Nuclear
Sitefrom 9/01/90 to 12/31/92; and prior thereto Plant
Manager - Monticello.
Loren L Taylor 48 President - NSP Electric since 10/27/94; Vice
President - Customer Operations from 1/01/93 to
10/26/94; Vice President - Transmission and
Inter-Utility Services from 11/01/89 to 12/31/92:
and prior thereto Vice-President Human Resources.
Keith H Wietecki 45 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.
Arland D Brusven 62 Vice President - Finance since 7/01/94; Vice
President - Finance and Treasurer from 1/01/93 to
6/30/94; Vice President and Treasurer from
9/01/90 to 12/31/92; and prior thereto Secretary
and Financial Counsel.
Jackie A Currier 43 Vice President and Treasurer since 7/01/94; Vice
President - Corporate Strategy from 1/11/93 to
6/30/94; 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; and prior thereto General Manager -
Budget & Control.
Gary R Johnson 48 Vice President & General Counsel since 11/01/91;
and prior thereto Vice President - Law.
Cynthia L Lesher 46 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; and prior thereto
Manager -Metro Credit.
Edward J McIntyre 44 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; and prior
thereto Vice President - Gas Utility.
Thomas A Micheletti 48 Vice President - Public and Government Affairs
since 10/27/94; Vice President - General Counsel
and Secretary of NRG Energy, Inc. a wholly owned
subsidiary of the Company from 5/11/94 to
10/26/94; Vice President-General Counsel, NRG
from 9/15/93 to 5/10/94; and prior thereto Group
Vice President for Minnesota Power and Light
Company, a public utility located in Duluth, MN.
Roger D Sandeen 49 Vice President, Controller and Chief Information
Officer since 4/22/92; and prior thereto Vice
President and Controller.
Robert H Schulte 42 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.
Edward L Watzl 55 Vice President - Nuclear Generation since
9/07/94; Prairie Island Site General Manager from
9/01/90 to 9/07/94; and prior thereto Plant
Manager - Prairie Island.
* As of 3/01/95
Item 2 - Properties
The Company's major electric generating facilities consist of the
following:
1994 1994
Capability Output
Station and Unit Fuel Installed (Mw) (Millions of Kwh)
Sherburne
Unit 1 Coal 1976 712 3 988.2
Unit 2 Coal 1977 712 3 981.4
Unit 3 Coal 1987 514 4 139.6
Prairie Island
Unit 1 Nuclear 1973 513 3 715.5
Unit 2 Nuclear 1974 512 4 552.9
Monticello Nuclear 1971 539 3 956.3
King Coal 1968 567 3 561.7
Black Dog
4 Units Coal 1952-1960 463 1 371.4
High Bridge
2 Units Coal 1956-1959 262 1 056.6
Riverside
2 Units Coal 1964-1987 366 1 745.9
Other Various Various 1,921 1 562.3
NSP's electric generating facilities provided 79% of its Kwh
requirements in 1994. The current generating facilities are expected to be
adequate base load sources of electric energy until 2004-2008, as detailed in
the Company's electric resource plan filed with the MPUC in 1993. All of
NSP's major generating stations are located in Minnesota on land owned by the
Company.
At Dec. 31, 1994, NSP had transmission and distribution lines as follows:
Voltage Length (Pole Miles)
500Kv 265
345Kv 730
230Kv 285
161Kv 340
115Kv 1,560
Less than 115 Kv 31,530
NSP also has approximately 300 transmission and distribution substations
with capacities greater than 10,000 kilovoltamperes (Kva) and approximately
270 with capacities less than 10,000 Kva.
Manitoba Hydro, Minnesota Power Company and the Company completed the
construction of a 500-Kv transmission interconnection between Winnipeg,
Manitoba, Canada, and the Minneapolis-St Paul, Minnesota, area in May 1980.
NSP has a contract with Manitoba Hydro-Electric Board for 500 Mw of firm power
utilizing this transmission line. In addition, the Company is interconnected
with Manitoba Hydro through a 230 Kv transmission line completed in 1970.
(Also see Note 17 of Notes to Financial Statements under Item 8.)
The gas properties of NSP include about 7,756 miles of natural gas
transmission and distribution mains. NSP natural gas mains include
approximately 102 miles with a capacity in excess of 275 pounds per square
inch (psi) and approximately 7,654 miles with a capacity of less than 275 psi.
In addition, Viking owns a 500-mile interstate natural gas pipeline serving
portions of Minnesota, Wisconsin and North Dakota.
Virtually all of the utility plant of the Company and the Wisconsin
Company are subject to the lien of their first mortgage bond indentures
pursuant to which they have issued first mortgage bonds.
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. While 12 lawsuits have been filed,
including one proposed class action suit, the litigation following this
incident is in a preliminary stage pending a report from the National
Transportation Safety Board and the ultimate costs to the Company are unknown
at this time.
On July 14, 1993, the Company filed a lawsuit in U.S. 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.
On June 20, 1994, the Company and 13 other major utilities filed a
lawsuit against the Department of Energy (DOE) in an attempt to clarify the
DOE's obligation to accept spent nuclear fuel beginning in 1998. The suit was
filed in the U.S. Court of Appeals, Washington, D.C. The primary purpose of
the lawsuit is to insure the Company and its customers receive timely storage
of used nuclear fuel.
For a discussion of other environmental proceedings, see "Environmental
Matters" under Item 1, incorporated herein by reference. For a discussion of
proceedings involving NSP's utility rates, see "Utility Regulation and
Revenues" 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 1994 and 1993 and the dividends
declared per share during those quarters:
1994 1993
High Low Dividends High Low Dividends
First Quarter $43 7/8 $40 1/8 $.645 $47 $42 1/4 $.630
Second Quarter 43 5/8 38 3/4 .660 46 7/8 42 7/8 .645
Third Quarter 43 7/8 40 3/8 .660 47 7/8 44 3/4 .645
Fourth Quarter 47 41 7/8 .660 46 3/8 40 1/8 .645
Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters
The Company's Restated Articles of Incorporation and First Mortgage Bond
Trust Indenture provide for certain restrictions on the payment of cash
dividends on common stock. At Dec. 31, 1994, the payment of cash dividends
on common stock was not restricted.
1994 1993 1992 1991 1990
Shareholders of record
at year-end 85 263 86 404 72 525 72 704 73 867
Book value per share
at year-end $28.35 $27.32 $25.91 $25.21 $24.42
Shareholders of record as of March 15, 1995 were 85,256.
Item 6 - Selected Financial Data
1994 1993 1992 1991 1990 1984
(Dollars in millions except per share data)
Utility operating revenues $2 486.5 $2 404.0 $2 159.5 $2 201.1 $2 064.5 $1 775.6
Utility operating expenses $2 178.2 $2 100.1 $1 903.5 $1 895.6 $1 775.7 $1 532.4
Income from continuing operations
before accounting change $243.5 $211.7 $160.9 $207.0 $193.0 $189.8
Net income $243.5 $211.7 $206.4 $224.1 $195.5 $192.1
Earnings available for common stock $231.1 $197.2 $190.3 $206.1 $177.3 $178.8
Average number of common and
equivalent shares outstanding (000's) 66 845 65 211 62 641 62 566 62 541 61,663
Earnings per average common share:
Continuing operations
before accounting change $3.46 $3.02 $2.31 $3.02 $2.79 $2.86
Total $3.46 $3.02 $3.04 $3.29 $2.83 $2.90
Dividends declared per share $2.625 $2.565 $2.495 $2.395 $2.295 $1.585
Total assets $5 953.6 $5 587.7 $5 142.5 $4 918.8 $4 931.6 $3 741.7
Long-term debt $1 463.4 $1 291.9 $1 299.9 $1 233.9 $1 239.5 $1 142.5
Ratio of earnings (from continuing
operations before accounting change,
excluding undistributed equity income 4.0 4.0 3.2 3.9 3.7 5.0
and including AFC) to fixed charges
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 to begin recording unbilled revenue.
Item 7 - Management's Discussion and Analysis of Financial Condition and
Results of Operations
Northern States Power Company, a Minnesota corporation (the Company), has two
significant subsidiaries, Northern States Power Company, a Wisconsin
corporation (the Wisconsin Company), and NRG Energy, Inc., a Delaware
corporation (NRG). The Company also has several other subsidiaries, including
Viking Gas Transmission Company (Viking) and Cenergy, Inc., (Cenergy). The
Company and its subsidiaries collectively are referred to herein as NSP.
FINANCIAL RESULTS AND OBJECTIVES
1994 Financial Results
NSP's 1994 earnings per share were $3.46, an increase of 44 cents, or
14.6 percent, over the $3.02 earned in 1993. Sales growth in the core electric
and gas utility businesses offset continuing unfavorable weather and higher
operating costs, for a modest increase in utility earnings. In 1994, non-
regulated businesses contributed a material portion of NSP's earnings for the
first time, with 14.2 percent of NSP's earnings per share being derived from
non-regulated operations. Most of this non-regulated earnings growth was
generated from investments in energy projects in Germany and Australia.
Investor returns also were enhanced in 1994 by an increase in the dividend
rate, as discussed below.
NSP remained financially strong in 1994, as evidenced by continued high
operating cash flows and interest coverage. NSP maintained its double A first
mortgage bond ratings with all rating agencies during 1994 except Moody's
Investors Services (Moody's). Moody's downgraded NSP's first mortgage bond
ratings to A1 based on its interpretation of provisions of a Minnesota law
enacted in 1994 regarding the Prairie Island nuclear generating plant used
fuel storage project. (See discussion of this legislation in Notes 16 and 17
to the Financial Statements.)
Total Return
Dividend increases plus stock price appreciation comprise total return
to NSP's investors. NSP increased its common dividend rate by more than 2
percent in 1994 and maintained a steady stock price despite a general industry
decline in utility stock prices. Since the beginning of 1985, the total return
on NSP's common stock has averaged 14.3 percent per year. The total return for
the Standard & Poor's (S&P) composite stock index for 500 industrial companies
has averaged 14.4 percent per year for the same period.
Financial Objectives
NSP's financial objectives are:
- To provide investor returns in the top one-fourth of the utility
industry as measured by a three-year average return on equity. NSP's
average return on equity (including the cumulative effect of the 1992
accounting change for unbilled revenues) for the three years ending in
1994 was 11.9 percent. Due largely to unusually mild weather in 1992,
this return was below the three-year average of the top one-fourth of
the industry (approximately 12.8 percent).
- To increase dividends on a regular basis and maintain a long-term
average payout ratio in the range of 65 to 75 percent. The objective
payout ratio is based on long-term earnings expectations. In June 1994,
NSP's annualized common dividend rate was increased by 6 cents per
share, or 2.3 percent, from $2.58 to $2.64. The dividend payout ratio
was 76 percent in 1994. NSP's goal is to return to the objective range
through growth in earnings.
- To maintain continued financial strength with a double A bond rating.
The Company's first mortgage bonds continued to be rated AA- by S&P,
AA- by Duff & Phelps, Inc., and AA by Fitch Investors Service, Inc.
In 1994, Moody's downgraded NSP's first mortgage bond ratings from
Aa2 to A1 based on its interpretations of a Minnesota law enacted in
1994 regarding the Prairie Island nuclear generating plant used fuel
storage project. First mortgage bonds issued by the Wisconsin Company
carry comparable ratings. NSP's pretax interest coverage ratio, based
on income without Allowance for Funds Used During Construction (AFC),
was 3.9 in 1994. A capital structure consisting of 47.5 percent common
equity at year-end 1994, including both regulated and non-regulated
operations, contributes to NSP's financial flexibility and strength.
- To provide 20 percent of NSP earnings from non-regulated businesses by
the year 2000. NSP expects to meet this goal through growing
profitability of existing non-regulated businesses and through the
addition of new non-regulated businesses. Non-regulated businesses
provided 14.2 percent of NSP's earnings in 1994.
- To maintain long-term average annual earnings growth of 5 percent. Non-
regulated operations are expected to provide a significant portion of
NSP's earnings growth in the foreseeable future. In 1994, total
earnings increased 14.6 percent over 1993, with non-regulated earnings
contributing most of that earnings growth.
Business Strategies
NSP's management is proactive in shaping the new business environment in
which it will be operating. Management's business strategies include:
- Focusing on the core energy business. The electric utility industry is
becoming more complex as customers, as well as utilities and federal
and state regulators, promote competition. To remain successful in this
more complex environment, NSP will maintain its focus on its core
energy-related activities.
- Providing reliable, low-cost, environmentally responsible energy.
Whether energy is produced through NSP's regulated utility or through
its non-regulated businesses, three general concepts provide a focus
for its energy businesses: reliable energy, low-cost energy and
environmentally responsible energy.
- Responding to customer needs. Customers will have an increasing number
of options for meeting their energy needs, and there will be
competition among energy companies for the privilege of serving those
customers. NSP will work with its customers to develop innovative
products and services that benefit both the customer and NSP.
- Increasing non-regulated investments and earnings. As evidenced by the
financial objectives for earnings growth, non-regulated businesses will
be an important part of NSP's future. Deregulation in the utility
industry is expected to provide new investment opportunities in non-
regulated businesses. Participation in these opportunities is expected
to improve the profitability of NSP.
RESULTS OF OPERATIONS AND LIQUIDITY AND CAPITAL RESOURCES
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 1994 and 1993. It should be read in conjunction with the
accompanying Financial Statements and Notes thereto. Trends and contingencies
of a material nature are discussed to the extent known and considered
relevant.
RESULTS OF OPERATIONS
1994 Compared with 1993 and 1992
NSP's 1994 earnings per share were $3.46, up 44 cents from the $3.02 earned
in 1993 and up $1.15 from the $2.31 earned before accounting changes in 1992.
Regulated utility businesses generated earnings per share of $2.97 in 1994,
$2.93 in 1993, and $2.33 (before accounting changes) in 1992. Non-regulated
businesses generated earnings per share of 49 cents in 1994 and 9 cents in
1993, and a loss per share of 2 cents in 1992. The results of the regulated
utility businesses and the non-regulated businesses are discussed in more
detail below. In addition to the revenue and expense changes, 1994 earnings
per share were impacted by a higher average number of common and equivalent
shares outstanding. Common and equivalent shares increased in 1994 and 1993
due to stock issuances, including a general offering of 2.6 million shares in
May 1993.
Utility Operating Results
Electric Revenues - Sales to retail customers, which account for more than 90
percent of NSP's electric revenue, increased 3.9 percent in 1994 and 4.0
percent in 1993. Cool summer weather reduced sales in 1992 and, to a lesser
extent, in 1994 and 1993. During 1994, NSP added 16,549 retail electric
customers, a 1.2-percent increase. Total sales of electricity decreased 0.2
percent in 1994. The decrease is due to lower sales to other utilities (as
discussed later), mostly offset by increases in sales to retail customers and
municipal utilities.
On a weather-adjusted basis, sales to retail customers increased an
estimated 3.4 percent in 1994 and 2.1 percent in 1993. Retail sales growth for
1995 is estimated to be 3.0 percent over 1994, or 2.2 percent on a weather-
adjusted basis.
Sales to other utilities decreased 21.6 percent in 1994 after increasing
30.5 percent in 1993 when there was higher demand from utilities in flood-
stricken Midwestern states. The 1993 increase also reflected the impact of ice
damage to transmission lines in Iowa, which limited sales in 1992.
The table below summarizes the principal reasons for the electric revenue
changes during the past two years.
1994 vs 1993 1993 vs 1992
(Millions of dollars)
Retail sales growth (excluding weather impacts) $56 $32
Estimated impact of weather on retail sales volume 8 34
Rate changes 17 74
Sales to other utilities (20) 20
Fuel adjustment clause 23 (2)
Other 8 (6)
Total revenue increase $92 $152
NSP's electric revenues are adjusted for changes in 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 in which 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.
Electric Production Expenses - Fuel expense for electric generation increased
$5.6 million, or 1.8 percent, in 1994 compared with an increase of $19.4
million, or 6.6 percent, in 1993. Total output from NSP's generating plants
decreased 1.5 percent in 1994 and increased 8.4 percent in 1993. Fuel expenses
were higher in 1994 because of the higher cost of nuclear fuel per megawatt-
hour (MWH) due to increased payments to the U.S. Department of Energy (DOE)
for decommissioning and decontamination of the DOE's uranium enrichment
facilities and nuclear fuel disposal costs. In addition, fossil fuel costs
were higher as a result of fewer purchases of coal at the lowest contractual
prices due to lower fossil plant output in 1994. These increases were somewhat
offset by cost decreases from lower output due to more scheduled fossil plant
maintenance outages. The fuel expense increase in 1993 was due to higher
output to meet sales demand, partially offset by lower cost of fuel per MWH,
which reflects increased use of low-cost purchases, as discussed below.
Purchased power costs increased $41.1 million, or 19.7 percent, in 1994
and $53.0 million, or 34.1 percent, in 1993. The increase in 1994 primarily
was due to additional demand expenses of $21 million for the full-year impact
of capacity charges from the power purchase agreements with Manitoba Hydro-
Electric Board (MH), which went into effect in May 1993, as discussed in Note
17 to the Financial Statements. In addition to demand expenses, purchased
power costs increased from more energy purchases and higher prices. Energy
purchases increased due to more scheduled plant maintenance outages in 1994.
The market pricing of energy purchases increased in 1994 compared to more
favorable market pricing in 1993. The increase in purchased power costs in
1993 over 1992 was largely due to a demand expense increase of $42 million for
the capacity charges under power purchase agreements with MH. Energy purchased
from other utilities increased in 1993 due to economically priced energy
available to meet growing retail demand and resale opportunities to other
utilities.
Gas Revenues - The majority of NSP's gas sales are categorized as firm
(primarily space heating customers) and interruptible (commercial/industrial
customers with an alternate energy supply). Firm sales in 1994 decreased 5.4
percent compared with 1993 sales, while firm sales in 1993 increased 17.0
percent over 1992 sales. The 1994 decrease is due largely to warm weather in
the last quarter of 1994. Warm weather in the first quarter of 1992 is the
main cause for the increase in 1993. NSP added 14,402 firm gas customers in
1994, a 3.7-percent increase.
On a weather-adjusted basis, firm sales are estimated to have decreased
0.7 percent in 1994 and increased 0.9 percent in 1993 (excluding a one-time
unbilled revenue adjustment). Firm gas sales in 1995 are estimated to increase
by 7.2 percent relative to 1994, with a 5.9-percent increase on a weather-
adjusted basis. The 1995 increase includes the impact of additional revenues
of approximately $6 million due to a 1994 gas expansion project in north
central Minnesota, where 6,300 new customers were signed up for new service
as of Dec. 31, 1994.
Interruptible sales of gas increased 4.4 percent in 1994 and 17.3 percent
in 1993. Other gas deliveries, including Viking's transmission volumes,
increased 73.5 percent in 1994 due to a full year of Viking activity and to
sales of gas to off-system customers. Other gas deliveries increased
dramatically in 1993 due to the acquisition of Viking.
The table below summarizes the principal reasons for the gas revenue
changes during the past two years.
1994 vs 1993 1993 vs 1992
(Millions of dollars)
Sales growth (excluding weather impacts) $0 $ 17
Estimated impact of weather on firm sales volume (8) 28
Viking Gas (acquired in June 1993) 5 9
Rate changes 3 9
Sales to off-system customers 14
Purchased gas adjustment
and other (23) 30
Total revenue increase (decrease) $(9) $ 93
NSP's gas revenues are adjusted for changes in purchased gas costs from
amounts currently included in approved base rates through purchased gas
adjustment clauses in all jurisdictions.
Cost of Gas Sold - The cost of gas purchased and transported decreased $18.6
million, or 6.6 percent, in 1994. The decrease reflects lower gas prices and
cost recovery adjustments, partially offset by higher sendout volumes
primarily for sales of gas to off-system customers. The cost of gas associated
with 1994 off-system sales was $12.7 million. In 1993, the cost of gas
purchased and transported increased $61.7 million, or 28.0 percent, due to
higher sendout volumes and higher purchased gas prices. The average cost per
thousand cubic feet (mcf) of NSP-owned gas sold in 1994 was 8.4 percent lower
than it was in 1993, when the cost was 8.7 percent higher than it was in 1992.
The decrease in 1994 is due mainly to lower market pricing of gas. NSP views
most of the increases in 1993 and 1992 as a recovery from unsustainably low
wellhead gas prices in 1990 and 1991.
Other Operation, Maintenance and Administrative and General - These expenses,
in total, increased by $26.5 million, or 4.1 percent, in 1994 compared with
a decrease of $27.2 million, or 4.0 percent, in 1993. The 1994 increase is
primarily due to higher postretirement health care costs, including amounts
deferred from 1993, and higher postemployment costs, as discussed in Note 3
to the Financial Statements. The 1993 decrease was the result of fewer
scheduled plant maintenance outages, reduced employee levels and lower
administrative costs. The 1993 decrease is net of a $14 million cost increase
because wages in 1992 did not include accruals for incentive compensation.
(See Note 14 to the Financial Statements for a summary of administrative and
general expenses.)
Conservation and Energy Management - Costs in 1994 remained comparable with
1993. Costs in 1993 were higher than in 1992 because NSP's regulators approved
higher expense levels for conservation and demand-side management efforts.
Depreciation and Amortization - The increases in depreciation in 1994 and 1993
reflect higher levels of depreciable plant for all periods and changes in the
depreciable lives of certain property in 1994 and 1993. (See Note 1 to the
Financial Statements for discussion of depreciation changes and rate filings.)
Property and General Taxes - Property and general taxes increased in 1994 and
1993 primarily as a result of higher property tax rates and property
additions. In addition, the increase in 1994 partially is due to higher gross
earnings taxes, which are a result of higher sales levels.
Utility Income Taxes - The variations in income taxes primarily are 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 11 to
the Financial Statements for a detailed reconciliation of the statutory tax
rate to the effective tax rate.)
Non-operating Items Related to Utility Businesses
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 lower-cost,
short-term borrowings to fund construction.
Other Income and Expense - Note 14 to the Financial Statements lists the
components of Other Income and Deductions-Net reported on the Consolidated
Statements of Income. Other than the operating revenues, expenses and income
taxes of non-regulated businesses, as discussed in the next section, non-
operating income and expense items related to utility businesses decreased
$2.5 million in 1994 and increased $0.8 million in 1993, net of associated
income taxes. The 1994 decrease primarily is due to higher expenses for
environmental and regulatory contingencies and higher public and government
affairs expenses associated with the Prairie Island fuel storage issue,
partially offset by interest income associated with the Company's settlement
of a federal income tax dispute. The increase in 1993 was due to higher
investment income and lower expenses for regulatory contingencies.
Interest Charges (Before AFC) - Interest costs recognized for NSP's utility
businesses, including amounts capitalized to reflect the financing costs of
construction activities, were $107.8 million in 1994, $111.2 million in 1993
and $109.1 million in 1992. The decrease in 1994 reflects the impact of
refinancing several higher-rate long-term debt issues in 1993 and 1994. These
interest savings were partially offset by interest on higher short-term debt
balances and new Viking debt (issued late in 1993). The average short-term
debt balance was $204.5 million in 1994, $77.0 million in 1993 and $81.0
million in 1992. The increase in 1993 is due to amortization of refinancing
costs, partially offset by interest savings from refinancing long-term debt
at lower rates.
Accounting Change - Earnings in 1992 included a net-of-tax income item of $45.5
million for the cumulative effect (related to prior years) of changing the
Company's revenue recognition method to begin recording estimated unbilled
revenues for utility service.
Preferred Dividends - Dividends on NSP's preferred stock decreased in 1994 and
1993 primarily due to redemptions of the $7.84 Series Cumulative Preferred
Stock in October 1993 and the $8.80 Series Cumulative Preferred Stock in April
1992.
Non-regulated Business Results
NSP's non-regulated operations include many diversified businesses, such as
independent power production, gas marketing, industrial heating and cooling,
and energy-related refuse-derived fuel (RDF) production. NSP also has
investments in affordable housing projects and several income-producing
properties. The following discusses NSP's diversified business results in the
aggregate.
Operating Revenues and Expenses - Because non-regulated operating revenues are
less than 10 percent of NSP's consolidated revenues, the net results of non-
regulated businesses are reported in Other Income and Deductions-Net on the
Consolidated Statements of Income. (Note 14 to the Financial Statements lists
the individual components of this line item.) Non-regulated operating revenues
increased $151.3 million, or 167 percent in 1994, and $28.1 million, or 45
percent in 1993, due mainly to the impact of gas marketing and industrial
heating and cooling businesses acquired during 1993. Non-regulated operating
expenses had corresponding increases in 1994 due to the effects of 1993
acquisitions. In addition, such expenses increased in 1994 due to fewer
project development costs being capitalized on pending projects in 1994
compared with 1993, and project write-downs, as discussed below. The increase
in 1993 non-regulated operating income was due to improved RDF operations,
acquired businesses and 1992 project write-downs that did not recur in 1993.
Non-regulated operating expenses include charges of $5.0 million in 1994 and
$6.8 million in 1992 for previously capitalized development and investment
costs to reflect a decrease in the expected future cash flows of certain
energy projects.
Equity Income - NSP has a less-than-majority equity interest in many non-
regulated projects, as discussed in Notes 4 and 5 to the Financial Statements.
Consequently, a large portion of NSP's non-regulated earnings is reported as
Equity in Earnings of Unconsolidated Investees on the Consolidated Statements
of Income. The 1994 increase in equity income primarily is due to new energy
projects NRG entered into during 1994 (as discussed in Notes 4 and 5 to the
Financial Statements) and to more profitable operations of other energy
projects in which NRG has been an investor for several years.
Non-operating Gain - In 1994, a cogeneration project in which NRG was a 50-
percent investor received a payment from an unrelated utility company that had
agreed to purchase the project cogeneration energy as compensation for
terminating the energy purchase agreement. Other Income and Deductions-Net
includes a pretax gain of $9.7 million for NRG's share of the termination
settlement, net of project investment costs.
Interest Expense - Interest charges on the Consolidated Statements of Income
include interest expense related to non-regulated businesses of $7.3 million
in 1994, $2.3 million in 1993 and $0.1 million in 1992. The increases in 1994
and 1993 relate primarily to new non-utility long-term debt issued to finance
the 1993 acquisitions of NRG's industrial heating and cooling business
(Minneapolis Energy Center), a gas marketing business now operated by Cenergy,
and 1994 investments in affordable housing projects by Eloigne Company (a
wholly owned subsidiary of the Company). In addition, during 1994 and late
1993, United Power & Land and First Midwest Auto Park, wholly owned
subsidiaries of the Company, issued long-term debt secured by non-regulated
properties and lowered NSP's equity investment.
Income Taxes - Other Income and Deductions-Net reported on the Consolidated
Statements of Income (and as shown in Note 14 to the Financial Statements)
includes income tax expense (credits) related to non-regulated businesses of
$6.4 million in 1994, $3.5 million in 1993 and $(0.3) million in 1992. The
increase in 1994 is due mainly to higher income and gains from NRG's energy
projects, as discussed above. The 1994 effective tax rate is substantially
less than the U.S. federal tax rate due mainly to the tax treatment of income
from NRG's international projects and to energy and low-income housing tax
credits, as shown in Note 11 to the Financial Statements.
Factors Affecting Results of Operations
NSP's results of operations during 1994 and 1993 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
depend on customer usage, which varies with weather conditions, general
business conditions, the state of the economy and the cost of energy services.
Various regulatory agencies determine the prices for electric and gas service
within their respective jurisdictions. In addition, NSP's non-regulated
businesses are beginning to contribute significantly to NSP's earnings. The
historical and future trends of NSP's operating results have been and are
expected to be affected by the following factors:
Competition - The Energy Policy Act of 1992 (the Act) is a catalyst for
comprehensive and significant changes in the operation of electric utilities,
including increased competition. The Act's reform of the Public Utility
Holding Company Act (PUHCA) promotes creation of wholesale non-utility power
generators and authorizes the Federal Energy Regulatory Commission (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. Management
believes this legislation will promote the continued trend of increased
competition in the electric energy markets.
In 1994, the FERC issued proposed rulemaking to address the rate
treatment of potential "stranded investment" costs that could occur as
wholesale electric markets become more competitive. The FERC is soliciting
comments on options for recovery of transition costs associated with existing
electric investments for which competitive market pricing might not provide
recovery. NSP is evaluating the FERC proposal to determine the potential
effects on operating results and customer rates and has responded to the FERC
individually and through an industry group. The FERC has not reached a final
decision, and the effects of the proposed rulemaking currently are not known.
NSP filed open access transmission tariffs with the FERC in March 1994.
In accepting the filing, the FERC ruled NSP's tariff would be subject to the
requirement that NSP offer transmission service to third parties using terms
and conditions comparable to its own use of the system on behalf of NSP's
traditional retail sales customers. NSP also addressed the following open
access issues in its filing: timely responses to good faith transmission
requests; unbundling energy services; and establishing appropriate pricing
mechanisms to ensure that cost allocation prevents inter-class subsidies. In
addition, the filing allows NSP and its affiliates to use market-based rates
to sell capacity and energy. The FERC also announced a new transmission
pricing policy statement in October 1994. The new policy introduces greater
flexibility in transmission pricing structure. NSP's revenues and earnings are
not expected to be materially affected by the FERC's new pricing policies for
transmission services. NSP management plans to continue its efforts to be a
competitively priced supplier of electricity and an active participant in the
competitive market for electricity.
In response to the developing electric industry competition, Cenergy
applied for and was granted permission by the FERC to market electricity
(except electricity generated by NSP) in the United States, effective Dec. 1,
1994. Cenergy is one of the first affiliates of an electric utility to obtain
this approval from the FERC.
Some states are considering proposals to require "retail wheeling", which
is the transmission of power generated by a third party to retail customers
of another utility. In 1994, NSP filed a response to a proposal by its
regulator in Wisconsin outlining the transitional steps necessary to create
an open and fair competitive electric market. NSP's position is that all
customers should be able to choose their electric supplier by 2001, and that
generation also should be deregulated by 2001. NSP proposes that utilities
retain operational control of their transmission and distribution systems, and
that utilities should be permitted to recover the cost of investments that
were authorized under traditional regulation. Regulators in Wisconsin are
currently considering what action, if any, they should take regarding electric
industry competition.
During 1992 and 1993, the FERC issued a series of orders (together called
Order 636) addressing interstate natural gas pipeline service restructuring.
This restructuring has "unbundled" each of the services (sales,
transportation, storage and ancillary services) traditionally provided by 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.
The implementation of Order 636 has applied 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
have been allowed to recover from their customers 100 percent of prudently
incurred transition costs attributable to Order 636 restructuring. NSP
estimates that it will be responsible for less than $12 million of transition
costs over a five-year period beginning Nov. 1, 1993. To date, NSP's
regulatory commissions have approved recovery of these restructuring charges
in retail gas rates through the purchased gas adjustment. 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 in 1993 have enhanced its ability to participate in the
more competitive gas transportation business. In implementing Order 636,
Viking incurred no transition costs.
Regulation - NSP's utility rates are approved by the FERC, the Minnesota Public
Utilities Commission (MPUC), the North Dakota Public Service Commission, the
Public Service Commission of Wisconsin (PSCW), the Michigan Public Service
Commission and the South Dakota Public Utilities Commission. Rates are
designed to recover plant investment and operating costs and an allowed return
on investment, using an annual period upon which rate case filings are based.
NSP requests changes in rates for utility services as needed through filings
with the governing commissions. The rates charged to retail customers in
Wisconsin are reviewed and adjusted biennially. Because rate changes are not
requested annually in Minnesota, NSP's primary jurisdiction, changes in
operating costs can affect NSP's earnings, shareholders' equity and other
financial results. Except for Wisconsin electric operations, NSP's rate
schedules provide for cost-of-energy adjustments to billings and revenues for
changes in the cost of fuel for electric generation, purchased energy 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 and demand-side management efforts and cost of capital.
Rate Changes - 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 for wholesale
customers in Minnesota and Wisconsin. These rate changes increased revenues
by approximately $83 million in 1993 and an additional $19 million in 1994.
As discussed in Note 2 to the Financial Statements, filings for rate
changes in 1994 did not have a material impact on financial results. No
significant general rate filings in any of NSP's utility jurisdictions are
expected for 1995. However, the Company requested that the MPUC approve a new
rate adjustment clause designed to accelerate recovery of 1994 and expected
1995 deferred electric conservation program costs. This adjustment clause
could help reduce the need for filing a general rate increase request for
recovery of increases in conservation expenditures. In February 1995, the
MPUC voted to approve the new rate adjustment clause for the period May 1995
through June 1996. Thereafter, the Company would be required to request a new
cost recovery level annually. The Company estimates it will receive an
additional $24 million in revenues in 1995. This increased recovery will
result in a corresponding increase in conservation expenses. A final order
is expected in March 1995.
Legislative Changes - In May 1994, NSP received legislative authorization for
dry cask fuel storage facilities at the Company's Prairie Island nuclear
generating facility. As a condition of this authorization, the Legislature
established several resource commitments for NSP, including wind and biomass
generation sources. (See Notes 16 and 17 to the Financial Statements for more
information.)
Wholesale Customers - In 1992, nine of the Company's 19 municipal wholesale
electric customers notified the Company of their intent to terminate their
power supply agreements with the Company, effective July 1995 or July 1996.
These nine customers currently represent approximately $29 million in annual
revenues and a maximum demand load of approximately 155 megawatts (MW).
In 1992 and 1993, the Company signed long-term power supply agreements
with the 10 remaining 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 $10 million in current annual revenue and a maximum demand load
of approximately 59 MW. The rates contained in the agreements were accepted
by the FERC.
During 1993, the Company signed an electric power agreement to provide
Michigan's Upper Peninsula Power Company (UPPCO) with up to 150 MW of baseload
service, peaking service options and load regulation service options for 20
years from 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. UPPCO has nominated 50 MW of base load and 5 MW of
winter season peaking power purchases from NSP beginning Jan. 1, 1998. The
annual revenue for 1998 is projected to be approximately $11 million to $14
million. The interchange agreement between UPPCO and NSP for this sale was
accepted by the FERC. The Michigan Public Utilities Commission must also
approve the transaction.
Environmental Matters - NSP incurs several types of environmental costs,
including nuclear plant decommissioning, storage and ultimate disposal of used
nuclear fuel, disposal of hazardous materials and wastes, remediation of
contaminated sites and monitoring of discharges into the environment. NSP is
recording costs for environmental monitoring and accruals for nuclear plant
decommissioning and used nuclear fuel disposal as an ongoing operating expense
and has recorded its best estimate of the full obligation for environmental
remediation. Because of the continuing trend toward greater environmental
awareness and increasingly stringent regulation, NSP has been experiencing a
trend toward increasing environmental costs. This trend has caused and may
continue to cause slightly higher operating expenses and capital expenditures.
Costs charged to NSP's operating expenses for environmental monitoring and
disposal of hazardous materials and wastes in 1994 were approximately $7
million and are currently expected to increase to an average annual amount of
approximately $12 million for the five-year period 1995-1999. However, the
precise timing and amount of environmental costs, including those for site
remediation and disposal of hazardous materials, are currently unknown. In
1994, 1993 and 1992, the Company spent about $15 million, $15 million and $20
million, respectively, for capital expenditures on environmental improvements
at its utility facilities. In 1995, the Company expects to incur approximately
$15 million in capital expenditures for compliance with environmental
regulations. (See Notes 16 and 17 to the Financial Statements for further
discussion of these and other environmental contingencies that could affect
NSP.)
Weather - NSP's earnings can be dramatically affected by unusual weather. Mild
weather, mainly cool summers, reduced earnings by an estimated 13 cents per
share in 1994 and 18 cents per share in 1993. 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 per share.
Acquisitions - In 1994, NRG acquired ownership interests in three significant
international energy projects (as discussed in Note 4 to the Financial
Statements), which increased 1994 earnings by approximately 38 cents per
share. NSP also made three other strategically important business acquisitions
in 1993, including an interstate natural gas pipeline (Viking), an energy
services marketing business (Cenergy) and a steam heating and chilled water
cooling system business (Minneapolis Energy Center, now an NRG subsidiary).
NSP continues to evaluate opportunities to enhance its competitive position
and shareholder returns through strategic business acquisitions.
Impact of Non-regulated Investments - NSP's net income in 1994 includes after-
tax earnings of $33.0 million, or 49 cents per share, from all non-regulated
businesses. As discussed previously, NRG acquired equity interests in three
significant energy projects in 1994. NSP expects to continue investing
significant amounts in non-regulated projects, including domestic and
international power production projects through NRG, as described under
"Future Financing Requirements". Depending on the success and timing of
involvement in these projects, NSP expects that non-regulated earnings could
increase in the future to contribute at least 20 percent of NSP's earnings by
the year 2000. The non-regulated projects in which NSP has invested carry a
higher level of risk than NSP's traditional utility businesses. Current and
future investments in non-regulated projects are subject to uncertainties
prior to final legal closing, and continuing operations are subject to foreign
government actions, partnership actions or both. The 1994 operating results
of NSP's non-regulated businesses may not necessarily be indicative of future
operating results.
Accounting Changes - Effective Jan. 1, 1994, NSP adopted three new accounting
standards for postemployment benefits, fair value accounting for certain
investments and employee stock ownership plan transactions. These accounting
changes had an immaterial impact on earnings in 1994. (See Note 3 to the
Financial Statements for more information on these accounting changes.)
As discussed in Notes 3 and 10 to the Financial Statements, in 1993 NSP
changed its accounting for certain postretirement benefits and began recording
such 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 previously, NSP's utility companies obtained rate recovery
for substantially all of the increased costs (approximately $20 million)
accrued under Statement of Financial Accounting Standards (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.
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 Financial Accounting Standards Board (FASB)
is evaluating the financial presentation of these obligations and the related
expense accruals, which could require reporting reclassifications as early as
1995. The effects of regulation are expected to minimize or eliminate any
impact on operating expenses from potential accounting changes for
decommissioning costs. (For further discussion, see Note 16 to the Financial
Statements.)
Use of Derivatives - Through its subsidiaries, NSP uses derivative financial
instruments to manage the risks of fluctuations in foreign currencies and
natural gas prices. At Dec. 31, 1994, $93 million in notional amount (i.e. no
transfer of principal) of hedge instruments were in place to hedge
international investments subject to foreign currency exchange fluctuations,
and $16 million in notional amount of futures contracts were in place to hedge
the sale of natural gas. NSP also uses interest rate swap agreements to
convert fixed rate debt to variable rate debt. At Dec. 31, 1994, NSP had $320
million in notional amount of interest rate swap agreements. (See Note 13 to
the Financial Statements for further discussion of NSP's financial instruments
and derivatives.)
Non-recurring Items - NSP's earnings for 1994 include several non-recurring
items. Although their net effect was an earnings increase of only 1 cent per
share, individually significant non-recurring items included a gain on
termination of a non-regulated cogeneration contract, interest income from the
settlement of a federal income tax dispute, a charge for pre-1994
postemployment costs associated with adopting SFAS No. 112, and asset
impairment write-downs for certain non-regulated energy projects.
Inflation - Historically, certain operating costs, mainly labor and property
taxes, have been affected by inflation. Also, inflation has tended to increase
the replacement cost of operating facilities, which has increased depreciation
expense when replacement facilities are constructed. However, several
significant expense items have been less sensitive to inflation, including
fuel costs, income taxes and interest expense. Overall, inflation at the
levels currently being experienced is not expected to materially affect NSP's
prices to customers or returns to shareholders.
LIQUIDITY AND CAPITAL RESOURCES
1994 Financing Requirements - NSP's need for capital funds is primarily related
to the construction of plant and equipment to meet the needs of electric and
gas utility customers and to fund equity commitments or other investments in
non-regulated businesses. Total NSP utility capital expenditures (including
AFC) were $387 million in 1994. Of that amount, $304 million related to
replacements and improvements of NSP's electric system and $60 million
involved construction of natural gas distribution facilities. NSP companies
invested $159 million in non-regulated projects and property in 1994, mainly
for equity investments in domestic and international power projects. NRG
invested in joint venture projects that acquired electric generating plants
in Australia and Germany, and open-cast coal mining operations in Germany.
Eloigne Company invested in affordable housing projects, including wholly
owned and limited partnership ventures.
1994 Financing Activity - During 1994, NSP's primary sources of capital included
internally generated funds, long-term debt and short-term debt. The allocation
of financing requirements between these capital options is based on the
relative cost of each option, regulatory restrictions and the constraints of
NSP's long-range capital structure objectives. During 1994, NSP continued to
meet its long-range regulated capital structure objective of 45-50 percent
common equity and 42-50 percent debt.
Funds generated internally from operating cash flows in 1994 remained
sufficient to meet working capital needs, debt service, dividend payout
requirements and non-regulated investment commitments, as well as fund a
significant portion of construction expenditures. NSP's 1993 cash flows
improved over 1992 mainly due to more favorable weather and rate increases.
The pretax interest coverage ratio, excluding AFC, was 3.9 in 1994 and 3.9 in
1993. These ratios met NSP's objective range of 3.5-5.0 for interest coverage.
Internally generated funds could have provided financing for 69 percent of
NSP's capital expenditures for 1994 and 77 percent of the $1.9 billion in
capital expenditures incurred for the five-year period 1990-1994.
The Company had approximately $238 million in short-term borrowings
outstanding as of Dec. 31, 1994. Throughout 1994, short-term borrowings were
used to finance utility capital expenditures and provide for other NSP cash
needs.
In 1994, the Company issued $350 million of first mortgage bonds to
refinance higher-cost debt issues and reduce short-term debt levels. In
addition, United Power & Land issued $10 million of non-utility long-term debt
to recapitalize the Company's prior equity investment in the subsidiary.
Eloigne Company also issued approximately $8 million of long-term debt to
finance affordable housing project investments.
The Company issued 42,567 new shares of common stock in 1994 under NSP's
Executive Long-Term Incentive Award Stock Plan. At Dec. 31, 1994, the total
number of common shares outstanding was 66,922,144.
NSP's equity investments in non-regulated projects during 1994 were
financed through internally generated funds. Project financing requirements,
in excess of equity contributions from investors, were satisfied with project
debt. Project debt associated with many of NSP's non-regulated investments is
not reflected in NSP's balance sheet because the equity method of accounting
is used for such investments. (See Note 5 to the Financial Statements.)
Future Financing Requirements - Utility financing requirements for 1995-1999 may
be affected in varying degrees by numerous factors including load growth,
changes in capital expenditure levels, rate increases allowed by regulatory
agencies, new legislation, market entry of competing electric power
generators, changes in environmental regulations and other regulatory
requirements. NSP currently estimates that its utility capital expenditures
will be $383 million in 1995 and $1.9 billion for the five-year period 1995-
1999. Of the 1995 amount, $322 million is scheduled for electric facilities
and $31 million for natural gas facilities. These utility capital expenditure
estimates include approximately $190 million of anticipated expenditures for
environmental improvements at utility facilities for the five-year period
1995-1999. In addition to utility capital expenditures, expected financing
requirements for the 1995-1999 period include approximately $369 million to
retire long-term debt and meet first mortgage bond sinking fund requirements.
Through its subsidiaries, NSP expects to invest significant amounts in
non-regulated projects in the future. Financing requirements for non-regulated
project investments 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 and property are estimated to
be approximately $153 million in 1995 and approximately $623 million for the
five-year period 1995-1999. These amounts include expected NRG investments
through 1996 of up to $46 million for an existing German project and Eloigne
Company investments of up to $23 million in 1995 and $13 million annually in
1996-1999 for affordable housing projects. Eloigne Company expects to finance
approximately 65 percent of these investments in affordable housing projects
with equity and approximately 35 percent with long-term debt. In addition to
investments in non-regulated projects, NSP continues to evaluate opportunities
to enhance shareholder returns and achieve long-term financial objectives
through acquisitions of existing businesses. Long-term financing may be
required for such investments.
The Company will also have future financing requirements for the portion
of nuclear plant decommissioning costs not funded externally. Based on the
most recent decommissioning study, these amounts are expected to be
approximately $363 million, and are expected to be paid during the years 2010
to 2022.
Future Sources of Financing - NSP expects to obtain external capital for future
financing requirements by periodically issuing long-term debt, common stock
and preferred stock as needed to maintain desired capitalization ratios. Over
the long-term, NSP's equity investments in non-regulated projects are expected
to be financed through internally generated funds or NSP's issuance of common
stock. Financing requirements for the non-regulated projects, in excess of
equity contributions from investors, are expected to be fulfilled through
project debt. Decommissioning expenses not funded by an external trust are
expected to be financed through a combination of internally generated funds,
long-term debt and common stock. The extent of external capital required for
nuclear decommissioning costs is not known at this time.
NSP's ability to finance its utility construction program at a reasonable
cost and to provide for other capital needs depends on its ability to meet
investors' return expectations. Financing flexibility is enhanced by providing
working capital needs and a high percentage of total capital requirements from
internal sources, and having the ability to issue long-term securities and
obtain short-term credit. NSP expects to maintain adequate access to
securities markets in 1995. 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, A1 by Moody's Investors
Service, Inc. (Moody's), AA- by Duff & Phelps, Inc., and AA by Fitch Investors
Service, Inc. Ratings for the Wisconsin Company's first mortgage bonds are
generally comparable. These ratings reflect the views of such organizations,
and an explanation of the significance of these ratings may be obtained from
each agency. Moody's downgraded NSP's first mortgage bond ratings to A1 based
on its interpretation of provisions of a Minnesota law enacted in 1994 for
used nuclear fuel storage at the Prairie Island generating plant. (The other
three rating agencies reaffirmed their ratings of NSP's bonds after
considering the impact of the legislation on NSP.) As discussed in Notes 16
and 17 to the Financial Statements, the legislation requires NSP to increase
its use of renewable energy sources such as wind and biomass power. Moody's
has indicated that it believes these sources of power are considerably more
costly than the power currently generated and that NSP's electric production
costs will increase materially over current levels. NSP acknowledges that
electric production costs may increase as a result of the Prairie Island
legislation.
The Company's and the Wisconsin Company's first mortgage indentures limit
the amount of first mortgage bonds that may be issued. The MPUC and the PSCW
have jurisdiction over securities issuance. At Dec. 31, 1994, with an assumed
interest rate of 8.5 percent, the Company could have issued about $1.9 billion
of additional first mortgage bonds under its indenture, and the Wisconsin
Company could have issued about $248 million of additional first mortgage
bonds under its indenture.
The Company registered first mortgage bonds with the Securities and
Exchange Commission (SEC) in December 1993. Depending on capital market
conditions, the Company expects to issue the remaining $250 million of
registered but unissued bonds over the next several years to raise additional
capital or redeem outstanding securities.
The Company's Board of Directors has approved short-term borrowing levels
up to 10 percent of capitalization. The Company has received regulatory
approval for $350 million in short-term borrowing levels and plans to keep its
credit lines at or above its average level of commercial paper borrowings.
Commercial banks presently provide credit lines to the Company of
approximately $299 million, which excludes $11 million of credit lines
provided to subsidiaries of the Company. 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, 1994, 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 1.6 million shares of common stock under the
Company's Dividend Reinvestment and Stock Purchase Plan (DRSPP), Executive
Long-Term Incentive Award Stock Plan, and Employee Stock Ownership Plan (ESOP)
as of Dec. 31, 1994. The Company may issue new shares or purchase shares on
the open market for its stock plans. (See Note 7 to the Financial Statements
for discussion of stock awards outstanding.) The Company does not plan any
general public stock offerings in 1995, but may issue new shares for its DRSPP
and ESOP plans.
Internally generated funds from utility operations are expected to equal
approximately 85 percent of anticipated utility capital expenditures for 1995
and approximately 95 percent of the $1.9 billion in anticipated utility
capital expenditures for the five-year period 1995-1999. Internally generated
funds from all operations are expected to equal approximately 60 percent and
80 percent, respectively, of the anticipated total capital expenditures for
1995 and the five-year period 1995-1999. Because of NSP's intention to
reinvest foreign cash flows in non-U.S. operations, the equity income from
international investments currently does not provide operating cash available
for U.S. cash requirements such as payment of dividends, domestic capital
expenditures and domestic debt service. NSP intends to pursue a diverse
portfolio of foreign energy projects with varying levels of cash flows, income
and foreign taxation to allow maximum flexibility of foreign cash flows.
Item 8 - Financial Statements and Supplementary Data
See Item 14(a)-1 in Part IV for index of financial statements included
herein.
See Note 19 of Notes to Financial Statements for summarized quarterly
financial data.
INDEPENDENT AUDITORS' REPORT
To The Shareholders of 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. 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,
1994 and 1993 and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1994 in conformity
with generally accepted accounting principles.
As discussed in Note 3 to the consolidated financial statements, the Companies
changed their method of accounting for postretirement health care costs in
1993.
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 8, 1995
Consolidated Statements of Income Year Ended Dec. 31
(Thousands of dollars, except per share data) 1994 1993 1992
Utility Operating Revenues
Electric $2 066 644 $1 974 916 $1 823 316
Gas 419 903 429 076 336 206
Total 2 486 547 2 403 992 2 159 522
Utility Operating Expenses
Electric production expenses---fuel and purchased power 570 880 524 126 451 696
Cost of gas purchased and transported 263 443 282 028 220 370
Other operation 311 119 304 675 307 232
Maintenance 170 145 161 413 180 585
Administrative and general 193 818 182 535 187 975
Conservation and energy management 31 231 29 358 17 626
Depreciation and amortization 273 801 264 517 242 914
Property and general taxes 234 564 223 108 204 439
Income taxes 129 228 128 346 90 669
Total 2 178 229 2 100 106 1 903 506
Utility Operating Income 308 318 303 886 256 016
Other Income and Expense
Equity in earnings of unconsolidated investees 35 863 3 030 2 382
Allowance for funds used during construction---equity 4 548 7 328 8 993
Other income and deductions---net 1 961 5 588 (3 423)
Total 42 372 15 946 7 952
Income Before Interest Charges 350 690 319 832 263 968
Interest Charges
Interest on long-term debt 97 143 104 714 103 035
Other interest and amortization 17 940 8 848 6 203
Allowance for funds used during construction---debt (7 868) (5 470) (6 198)
Total 107 215 108 092 103 040
Income Before Accounting Change 243 475 211 740 160 928
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 243 475 211 740 206 440
Preferred Stock Dividends 12 364 14 580 16 172
Earnings Available for Common Stock $231 111 $197 160 $190 268
Average number of common and equivalent shares outstanding (000's) 66 845 65 211 62 641
Earnings per average common share:
Income before accounting change $3.46 $3.02 $2.31
Cumulative effect of unbilled revenue accounting change .73
Total $3.46 $3.02 $3.04
Common Dividends Declared per Share $2.625 $2.565 $2.495
See Notes to Financial Statements
Consolidated Statements of Cash Flows Year Ended Dec. 31
(Thousands of dollars) 1994 1993 1992
Cash Flows from Operating Activities:
Net Income $243 475 $211 740 $206 440
Adjustments to reconcile net income to
cash from operating activities:
Depreciation and amortization 304 583 286 855 261 457
Nuclear fuel amortization 45 553 43 120 45 129
Deferred income taxes from operations (2 262) 12 256 5 186
Deferred investment tax credits recognized (9 501) (9 223) (8 446)
Allowance for funds used during construction---equity (4 548) (7 328) (8 993)
Undistributed equity in earnings of unconsolidated investees (27 427) (1 142) (1 006)
Gain from non-regulated project termination settlement (9 685)
Cumulative effect of unbilled revenue accounting
change---net of tax (45 512)
Cash provided by (used for) changes in certain working
capital items (8 627) 33 259 (31 478)
Conservation program expenditures - net of amortization (29 963) (21 185) (16 948)
Cash provided by (used for) changes in other assets
and liabilities (1 042) 12 340 2 767
Net Cash Provided by Operating Activities 500 556 560 692 408 596
Cash Flows from Investing Activities:
Capital expenditures:
Utility businesses (387 026) (356 836) (423 346)
Non-regulated businesses (22 260) (4 859) (4 469)
Increase (decrease) in construction payables 11 668 2 598 (2 863)
Allowance for funds used during construction---equity 4 548 7 328 8 993
Sale (purchase) of short-term investments---net (866) 62 1 552
Investment in external decommissioning fund (42 677) (32 578) (27 929)
Proceeds from non-regulated project termination settlement 14 000
Business acquisitions (159 385)
Investments in non-regulated projects and other (136 826) (25 957) 2 554
Net Cash Used for Investing Activities (559 439) (569 627) (445 508)
Cash Flows from Financing Activities:
Change in short-term debt---net issuances (repayments) 132 239 (40 361) 146 561
Proceeds from issuance of long-term debt 367 184 613 120 126 531
Repayment of long-term debt, including reacquisition premiums (272 097) (489 106) (48 344)
Proceeds from issuance of common stock 1 368 183 654 2 940
Redemption of preferred stock, including premium (36 092) (25 838)
Dividends paid (186 568) (180 220) (171 355)
Net Cash Provided by Financing Activities 42 126 50 995 30 495
Net Increase (Decrease) in Cash and Cash Equivalents (16 757) 42 060 (6 417)
Cash and Cash Equivalents at Beginning of Period 57 812 15 752 22 169
Cash and Cash Equivalents at End of Period $41 055 $57 812 $15 752
Cash Provided by (Used for) Changes in Certain Working Capital Items:
Accounts receivable and accrued utility revenues $(1 695) $(50 403) $(14 108)
Materials and supplies inventories (13 462) 13 911 (5 280)
Payables and accrued liabilities (excluding construction
payables) 32 550 54 247 5 206
Customer rate refunds (10 410) 12 235 (11 987)
Other (15 610) 3 269 (5 309)
Net $(8 627) $33 259 $(31 478)
Supplemental Disclosures of Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized) $106 867 $107 037 $99 669
Income taxes $170 474 $120 491 $93 032
See Notes to Financial Statements
Consolidated Balance Sheets Dec. 31
(Thousands of dollars) 1994 1993
Assets
Utility Plant
Electric---including construction work in progress:
1994, $117,235; 1993, $174,893 $6 372 317 $6 167 670
Gas 677 233 621 871
Other 262 506 237 293
Total 7 312 056 7 026 834
Accumulated provision for depreciation (3 116 811) (2 888 144)
Nuclear fuel---including amounts in process:
1994, $12,505; 1993, $15,358 797 097 749 078
Accumulated provision for amortization (718 690) (673 669)
Net utility plant 4 273 652 4 214 099
Current Assets
Cash and cash equivalents 41 055 57 812
Short-term investments 892 26
Accounts receivable---net of accumulated provision for
uncollectible accounts: 1994, $4,072; 1993, $4,476 280 858 266 531
Accrued utility revenues 98 651 111 296
Federal income tax and interest receivable 28 858 20 927
Materials and supplies---at average cost
Fuel 56 960 41 776
Other 101 878 103 599
Prepayments and other 56 075 40 885
Total current assets 665 227 642 852
Other Assets
Regulatory assets 357 576 334 354
Non-regulated property---net of accumulated depreciation:
1994, $73,296; 1993, $63,351 172 961 157 615
Investments in non-regulated projects 181 330 45 772
External decommissioning fund and other investments 165 466 121 657
Federal income tax and interest receivable 56 358
Intangible assets and other 81 001 71 369
Total other assets 1 014 692 730 767
Total $5 953 571 $5 587 718
Liabilities & Equity
Capitalization
Common stockholders' equity $1 896 967 $1 827 454
Preferred stockholders' equity 240 469 240 469
Long-term debt 1 463 354 1 291 867
Total capitalization 3 600 790 3 359 790
Current Liabilities
Long-term debt due within one year 16 106 90 618
Other long-term debt potentially due within one year 141 600 141 600
Short-term debt---primarily commercial paper 238 439 106 200
Accounts payable 234 905 210 654
Taxes accrued 178 119 177 853
Interest accrued 28 164 24 110
Dividends payable on common and preferred stocks 47 283 46 195
Accrued payroll, vacation and other 79 029 73 792
Total current liabilities 963 645 871 022
Other Liabilities
Deferred income taxes 848 870 788 378
Deferred investment tax credits 173 838 187 466
Regulatory liabilities 200 517 243 880
Pension and other benefit obligations 92 514 64 224
Other long-term obligations and deferred income 73 397 72 958
Total other liabilities 1 389 136 1 356 906
Commitments and Contingent Liabilities (See Notes 16 and 17)
Total $5 953 571 $5 587 718
See Notes to Financial Statements
Consolidated Statements of Changes in Common Stockholders' Equity
Cumulative
Currency
Number of Retained Shares Held Translation
(Dollar amounts in thousands) Shares Issued Par Value Premium Earnings by ESOP Adjustments
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)
Net income 243 475
Dividends declared:
Cumulative preferred stock
at required rates (12 364)
Common stock (175 292)
Issuances of common stock 42 567 106 1 342
Stock issuance costs (80)
Tax benefit from stock options exercised 843
Repayment of ESOP loan 7 897
Currency translation adjustments $3 586
Balance at Dec. 31, 1994 66 922 144 $167 305 $545 875 $1 183 191 $(2 990) $3 586
See Notes to Financial Statements
Consolidated Statements of Capitalization
Dec. 31
(Thousands of dollars) 1994 1993
Common Stockholders' Equity
Common stock-authorized 160,000,000 shares of
$2.50 par value; issued shares: 1994,
66,922,144; 1993, 66,879,577 $167 305 $167 199
Premium on common stock 545 875 543 770
Retained earnings 1 183 191 1 127 372
Leveraged common stock held by Employee Stock
Ownership Plan (ESOP) - shares at cost:
1994, 59,445; 1993, 239,940 (2 990) (10 887)
Currency translation adjustments - net 3 586
Total common stockholders' equity $1 896 967 $1 827 454
Cumulative Preferred Stock - authorized 7,000,000
shares of $100 par value; outstanding shares:
1994 and 1993, 2,400,000
Minnesota Company
$3.60 series, 275,000 shares $ 27 500 $ 27 500
4.08 series, 150,000 shares 15 000 15 000
4.10 series, 175,000 shares 17 500 17 500
4.11 series, 200,000 shares 20 000 20 000
4.16 series, 100,000 shares 10 000 10 000
4.56 series, 150,000 shares 15 000 15 000
6.80 series, 200,000 shares 20 000 20 000
7.00 series, 200,000 shares 20 000 20 000
Variable Rate series A, 300,000 shares 30 000 30 000
Variable Rate series B, 650,000 shares 65 000 65 000
Total 240 000 240 000
Premium on preferred stock 469 469
Total preferred stockholders' equity $240 469 $240 469
Long-Term Debt
First Mortgage Bonds Minnesota Company
Series due:
June 1, 1995, 6 1/8% $30 000
March 1, 1996, 6.2% $8 800* 8 800*
Aug. 1, 1996, 5 7/8% 45 000
Oct. 1, 1997, 5 7/8% 100 000 100 000
Oct. 1, 1997, 6 1/2% 30 000
May 1, 1998, 6 3/4% 45 000
Feb. 1, 1999, 5 1/2% 200 000
Dec. 1, 2000, 5 3/4% 100 000 100 000
Oct. 1, 2001, 7 7/8% 150 000
March 1, 2002, 7 3/8% 50 000 50 000
Feb. 1, 2003, 7 1/2% 50 000 50 000
April 1, 2003, 6 3/8% 80 000 80 000
Jan. 1, 2004, 8 3/8% 75 000
Dec. 1, 2005, 6 1/8% 70 000 70 000
Dec. 1, 1993-2006, 6.57% 22 300** 23 400**
March 1, 2011, Variable Rate 13 700* 13 700*
July 1, 2019, 9 1/8% 98 000 99 000
June 1, 2020, 9 3/8% 70 000 100 000
Total $1 012 800 $919 900
Less redeemable bonds classified as current (See Note 9) (13 700) (13 700)
Less current maturities, including in 1993
the 2004 series bonds redeemed in January 1994 (1 200) (76 100)
Net $ 997 900 $830 100
* Pollution control financing
** Resource recovery financing
See Notes to Financial Statements
Dec. 31
(Thousands of dollars) 1994 1993
Long-Term Debt-continued
First Mortgage Bonds Wisconsin Company
(less reacquired bonds of $490 at Dec. 31, 1994)
Series due:
Oct. 1, 2003, 5 3/4% $40 000 $40 000
April 1, 2021, 9 1/8% 48 010 49 000
March 1, 2023, 7 1/4% 110 000 110 000
Total 198 010 199 000
Less current maturities (2 910)
Net $195 100 $199 000
Guaranty Agreements - Minnesota Company
Series due:
Feb. 1, 1993-2003, 5.41% $ 5 900* $ 6 100*
May 1, 1993-2003, 5.69% 24 750* 25 250*
Feb. 1, 2003, 7.40% 3 500* 3 500*
Total 34 150 34 850
Less current maturities (700) (700)
Net $33 450 $34 150
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* 100 000*
Anoka County Resource Recovery Bond-Series due
Dec. 1, 1993-2008, 7.05% 25 150** 26 100**
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% 29 511 31 644
NRG Energy Center, Inc. (Minneapolis Energy Center)
Senior Secured Notes-Series due June 15, 2013, 7.31% 81 498 83 518
United Power & Land First Mortgage Notes due
March 31, 2000, 7.62% 9 375
Various Affordable Housing Project Mortgage Notes due
1994-2009, 7.52%-10.0% 7 710
Employee Stock Ownership Plan Bank Loans due
1993-1995, Variable Rate 2 698 10 887
Other 10 736 8 397
Total 382 178 376 046
Less variable rate Becker bonds classified as current (See Note 9) (127 900) (127 900)
Less current maturities (11 296) (13 818)
Net $242 982 $234 328
Unamortized discount on long-term debt-net (6 078) (5 711)
Total long-term debt 1 463 354 1 291 867
Total capitalization $3 600 790 $3 359 790
* Pollution control financing
** Resource recovery financing
See Notes to Financial Statements
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant 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
material companies in which NSP holds a controlling financial interest,
including: the Wisconsin Company; NRG Energy, Inc. (NRG); Viking; Cenergy,
Inc. (Cenergy); and Eloigne Company. As discussed in Note 5, NSP has
investments in partnerships, joint ventures and projects for which the equity
method of accounting is applied. All significant intercompany transactions and
balances have been eliminated in consolidation except for intercompany and
intersegment profits for sales among the electric and gas utility businesses
of the Company, the Wisconsin Company and Viking, which are allowed in utility
rates. The Company and its subsidiaries collectively are referred to herein
as NSP.
Revenues - Revenues are recognized based on products and services provided to
customers each month. Because utility customer meters are read and billed on
a cycle basis, unbilled revenues (and related energy costs) are estimated and
recorded for services provided from the monthly meter-reading dates to month-
end.
The Company's rate schedules, applicable to substantially all of its
utility customers, include cost-of-energy adjustment clauses, under which
rates are adjusted to reflect changes in average costs of fuels, purchased
energy 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 energy. 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
used to finance utility construction activities, to qualified Construction
Work in Progress (CWIP). AFC rates were 5.0 percent in 1994, 7.4 percent in
1993 and 8.0 percent in 1992. The amount of AFC capitalized as a construction
cost in CWIP is credited to other income (for equity capital) and interest
charges (for debt capital). AFC amounts capitalized in CWIP are included in
rate base for establishing utility service rates. In addition to construction-
related amounts, AFC is also recorded to reflect returns on capital used to
finance conservation programs.
Depreciation - For financial reporting purposes, depreciation is computed by
applying the straight-line method over the estimated useful lives of various
property classes. The Company files with the Minnesota Public Utilities
Commission (MPUC) an annual review of remaining lives for electric and gas
production properties. The most recent studies, as approved by the MPUC,
recommended an increase of approximately $0.5 million and a decrease of
approximately $0.9 million for the 1994 and 1993 annual depreciation accruals,
respectively. The remaining lives of the Company's nuclear facilities were
submitted for review in 1994. The recovery period recommended for the Prairie
Island plant was reduced because of the uncertainty regarding used nuclear
fuel storage. (See Note 16.) The filing, as approved by the MPUC, increased
depreciation by approximately $9.7 million due to the change from previously
approved property lives. However, because the annual accruals for projected
future decommissioning expenses decreased, the net impact to the Company from
1994 capital recovery filings is a decrease of about $800,000 in annual
depreciation and decommissioning expenses, effective Jan. 1, 1994.
Every five years, the Company also must file an average service life
filing for transmission, distribution and general properties. The most recent
filing, as approved by the MPUC, increased 1993 depreciation by approximately
$4.7 million from 1992 levels. In 1994, the Company submitted to the MPUC a
depreciation study for the general plant accounts requesting a change in the
depreciation calculation method. While a straight-line method is still used,
the approved method change affects the level of detail at which depreciation
expense is calculated. The impact to 1994 depreciation accruals from the
change was a decrease of approximately $1.1 million. Depreciation provisions,
as a percentage of the average balance of depreciable utility property in
service, were 3.55 percent in 1994, 3.47 percent in 1993 and 3.36 percent in
1992.
Decommissioning - NSP records the cost of decommissioning the Company's nuclear
generating plants through annual depreciation accruals. The provision for the
estimated decommissioning costs has been calculated using an annuity approach
designed to provide for full expense accrual (with full rate recovery) of the
future decommissioning costs, including reclamation and removal, over the
estimated operating lives of the Company's nuclear plants.
Nuclear Fuel Expense - The original cost of nuclear fuel is amortized to fuel
expense based on energy expended. Nuclear fuel expense also includes
assessments from the U.S. Department of Energy (DOE) for future fuel disposal
and DOE facility decommissioning, as discussed in Note 16.
Environmental Costs - Accruals for environmental costs are recognized when it
is probable that a liability has been incurred and the amount of the liability
can be reasonably estimated. 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 mitigate
or prevent contamination from future operations. Where environmental
expenditures relate to facilities currently in use, such as pollution control
equipment, the costs may be capitalized and depreciated over the future
service periods. Estimated remediation costs are recorded at undiscounted
amounts, independent of any insurance or rate recovery, based on prior
experience, assessments and current technology. Accrued obligations are
regularly adjusted as environmental assessments and estimates are revised, and
remediation efforts proceed. For sites where NSP has been designated as one
of several potentially responsible parties, the amount accrued represents
NSP's estimated share of the cost. NSP intends to treat any future costs
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.
(Before 1993, NSP followed SFAS No. 96---Accounting for Income Taxes,
resulting in substantially the same accounting as SFAS No. 109.) Under the
liability method required by 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 has created certain
regulatory assets and liabilities related to income taxes, as summarized in
Note 12.
Investment tax credits are deferred and amortized over the estimated
lives of the related property.
Foreign Currency Translation - The local currencies are generally the functional
currency of NSP's foreign operations. Foreign currency denominated assets and
liabilities are translated at end-of-period rates of exchange. Income, expense
and cash flows are translated at weighted-average rates of exchange for the
period. The resulting currency translation adjustments are accumulated and
reported as a separate component of shareholders' equity.
Exchange gains and losses that result from foreign currency transactions
(e.g. converting cash distributions made in one currency to another currency)
are included in the results of operations as a component of equity in earnings
of unconsolidated investees. Through Dec. 31, 1994, NSP had not experienced
any material translation gains or losses from foreign currency transactions
that have occurred since the respective foreign investment dates.
Derivative Financial Instruments - NSP's policy is to hedge foreign currency
denominated investments as they are made to preserve their U.S. dollar value.
NRG has entered into currency hedging transactions through the use of forward
foreign currency exchange agreements. Gains and losses on these contracts
offset the effect of foreign currency exchange rate fluctuations on the
valuation of the investments underlying the hedges. The effect of hedging
gains and losses, net of income taxes, is reported with other currency
translation adjustments as a separate component of stockholders' equity. NRG
is not hedging currency translation adjustments related to operating results.
NSP does not speculate in foreign currencies. A second derivative arrangement
is the use of natural gas futures contracts by Cenergy to manage the risk of
gas price fluctuations. The cost or benefit of natural gas futures contracts
is recorded when related sales commitments are fulfilled as a component of
Cenergy's non-regulated operating expenses. A third derivative instrument used
by NSP is interest rate swaps that convert fixed rate debt to variable rate
debt. The cost or benefit of the interest rate swap agreements is recorded as
a component of interest expense.
Use of Estimates - In recording transactions and balances resulting from
business operations, NSP uses estimates based on the best information
available. Estimates are used for such items as plant depreciable lives, tax
provisions, uncollectible accounts, environmental loss contingencies, unbilled
revenues and actuarially determined benefit costs. As better information
becomes available (or actual amounts are determinable), the recorded estimates
are revised. Consequently, operating results can be affected by revisions to
prior accounting estimates. Recent changes in interest rates have resulted in
changes to actuarial assumptions used in the benefit cost calculations for
postretirement benefits. Also, the depreciable lives of certain plant assets
are reviewed and, if appropriate, revised each year, as discussed previously.
(See Notes 10 and 16 for more information on the effects of these changes in
estimates.)
Cash Equivalents - NSP considers investments in certain debt instruments
(primarily commercial paper) with an original 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
amortized consistent with ratemaking treatment established by regulators. Note
12 describes the nature and amounts of these regulatory deferrals.
Other Assets - The purchase of the Minneapolis Energy Center by an NRG
subsidiary in 1993 at a price exceeding the underlying fair value of net
assets acquired resulted in recorded goodwill. This goodwill and other
intangible assets acquired are being amortized using the straight-line method
over 30 years. NSP periodically evaluates the recovery of goodwill based on
an analysis of estimated undiscounted future cash flows.
Intangible and other assets also include deferred financing costs of
approximately $12.9 million at Dec. 31, 1994, which are being amortized over
the remaining maturity period of the related debt.
Reclassifications - Certain reclassifications have been made to the 1993 and
1992 financial statements to conform with the 1994 presentation. These
reclassifications had no effect on net income or earnings per share.
2. Rate Matters
On Aug. 9, 1994, the Company applied to the North Dakota Public Service
Commission (NDPSC) for an annual electric rate reduction of $3.6 million. The
reduction reflects a correction in cost allocations to the North Dakota
jurisdiction. The Company also requested authority to make refunds to
customers to effectively implement the reduction as of June 1, 1994. On Nov.
9, 1994, the NDPSC approved the proposed rate reduction, the liability for
which has been accrued as of Dec. 31, 1994. In January 1995, the NDPSC held
a hearing on the possibility of retroactive refunds for the period Jan. 1,
1989, through June 1, 1994, but has not yet reached a decision. The ultimate
outcome of this proceeding is not determinable at this time.
Other rate increases filed in Wisconsin and North Dakota that were
effective in 1994 increased revenues by approximately $2.6 million.
3. Accounting Changes
Postemployment Benefits - Effective Jan. 1, 1994, NSP adopted the provisions of
Statement of Financial Accounting Standards (SFAS) No. 112---Employers'
Accounting for Postemployment Benefits. This standard required the accrual of
certain postemployment costs, such as injury compensation and severance, that
are payable in the future. Initially, the Company's pre-1994 injury
compensation liability was deferred in a regulatory asset based on a
preliminary decision to request amortization through rates over future
periods. In October 1994, another Minnesota utility was ordered by the MPUC
to defer its pre-1994 SFAS No. 112 liability and amortize it to match a three-
year rate recovery period. Since the Company may not file a rate case within
the deferral period approved by the MPUC, which ends in 1996, the Company's
pre-1994 liability of approximately $9.4 million (8 cents per share) was
expensed during 1994.
Fair Value Accounting for Certain Investments - Effective Jan. 1, 1994, NSP
adopted the provisions of SFAS No. 115---Accounting for Certain Investments
in Debt and Equity Securities. This new standard resulted in an increase of
approximately $1.4 million in decommissioning investments to present such
investments at their market value at Dec. 31, 1994. This increase represents
an unrealized gain on investments, which has been deferred as a regulatory
liability. The Company anticipates offsetting such gains, when realized,
against decommissioning costs in future ratemaking.
Accounting for Employee Stock Ownership Plans (ESOP) - Effective Jan. 1, 1994,
NSP adopted the American Institute of Certified Public Accountants' Statement
of Position (SOP) 93-6. This SOP changed the accounting for compensation
expense associated with ESOP plans, and changed how ESOP shares were
considered for earnings-per-share calculations. No additional compensation
expense was recorded by NSP in 1994 due to the adoption of this SOP. The
impact of the reduction in average common shares was immaterial to 1994
earnings per share (an increase in earnings per share of less than 1 cent).
Postretirement Benefits - As discussed in Note 10, NSP changed its accounting
for postretirement medical and death benefits in 1993. Due to rate recovery
of the expense increases, there was no material effect on net income in 1993
or 1994. 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. In 1994,
administrative and general expenses increased by approximately $16 million due
to the full recognition of accrued SFAS No. 106 costs, including amounts
deferred from 1993.
4. Business Acquisitions
Through its subsidiaries, NRG purchased equity interests during 1994 in three
significant international projects, two in Germany and one in Australia. One
of the investments is a 33-percent interest in Mitteldeutsche
Braunkohlengesellschaft mbh (MIBRAG), a German corporation. MIBRAG was formed
by the German government to operate coal mines, electric power plants and
other energy-related facilities. The other German investment is a 50-percent
interest in Saale Energie GmbH (Saale), also a German corporation. Saale owns
a 400-megawatt share of a 900-megawatt power plant currently under
construction near Schkopau, Germany. The Australian investment is a 37.5-
percent interest in a joint venture that acquired a 1,680-megawatt coal-fired
power plant in Gladstone, Queensland, Australia, which is operated by an NRG
subsidiary. The total acquisition investments in these three projects through
1994, including capitalized development costs, was approximately $100 million.
Earnings from equity interests in NRG international projects acquired in 1994
contributed approximately 38 cents per share to NSP's 1994 earnings.
5. Investments Accounted for by the Equity Method
Through its non-regulated subsidiaries, NSP has investments in various
international and domestic energy projects and domestic affordable housing and
real estate projects. (Before 1994, such investments had been limited to
immaterial domestic projects.) The equity method of accounting is applied to
such investments because the ownership structure prevents NSP from exercising
a controlling influence over operating and financial policies of the projects.
A summary of NSP's significant equity-method investments is as follows:
Purchased or
Name Geographic Area Economic Interest Placed in Service
Various Independent Power
Production Facilities U.S.A. 45%-50% July 1991-December 1994
Affordable Housing-Limited
Partnerships U.S.A. 50%-99% April 1993-December 1994
Rosebud SynCoal Partnership U.S.A. 50% August 1993
MIBRAG Europe 33% January 1994
Gladstone Power Station Australia 37.5% March 1994
Schkopau Power Station Europe 20.6% Under Construction
Scudder Latin American Trust
for Independent Power
Energy Projects Latin America 6.3%-12.5% December 1994
Summarized Financial Information of Unconsolidated Investees - Summarized
financial information for these projects, including interests owned by NSP and
other parties, was as follows as of and for the year ended Dec. 31, 1994:
Financial Position (Millions of dollars) Results of Operations
(Millions of dollars)
Current Assets $ 514.9 Operating Revenues $778.4
Other Assets 1,593.8 Operating Income $128.0
Total Assets $2,108.7 Net Income $117.0
Current Liabilities $ 159.6
Other Liabilities 1,480.0
Equity 469.1
Total Liabilities and
Equity $2,108.7
6. Cumulative Preferred Stock
The Company has two series of adjustable rate preferred stock. The dividend
rates are calculated quarterly and are based on prevailing rates of certain
taxable government debt securities indices. At Dec. 31, 1994, the annualized
dividend rates were $5.82 for series A and $5.97 for series B.
At Dec. 31, 1994, 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.
7. 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, 1994, the Company could have paid, without restrictions, additional
cash dividends of more than $1 billion on common stock.
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 restricted
stock and other performance awards. Performance awards are valued in dollars,
but are paid in shares based on the market price at the time of payment.
Transactions under the various incentive stock programs, which may result in
the issuance of new shares, were as follows:
Stock Awards (Thousands of shares) 1994 1993 1992
Outstanding Jan. 1 537.1 528.7 403.3
Options granted 304.0 196.9 201.8
Other stock awards .2 9.5 .8
Options and awards exercised (42.6) (174.3) (57.0)
Options and awards forfeited (16.1) (22.2) (20.1)
Other (.2) (1.5) (.1)
Outstanding at Dec. 31 782.4 537.1 528.7
Option price ranges:
Unexercised at Dec. 31 $33.25-$43.50 $33.25-$43.50 $33.25-$40.94
Exercised during the year $33.25-$43.50 $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.
8. Short-Term Borrowings
NSP has approximately $310 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 approximately $3.6 million of borrowings against these credit
lines, with interest payable at 9.75 percent, at Dec. 31, 1994, and no such
borrowings at Dec. 31, 1993. At Dec. 31, 1994 and 1993, the Company had $234.8
million and $106.2 million, respectively, in short-term commercial paper
borrowings outstanding. The weighted average interest rate on all short-term
borrowings as of Dec. 31, 1994 and Dec. 31, 1993, was 6.1 percent and 3.3
percent, respectively.
9. 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
$740 million. The Company may, and has, applied property additions in lieu of
cash payments on all series, except the 9 1/8 percent Series due July 1, 2019,
as permitted by its First Mortgage Indenture. The Wisconsin Company also may
apply property additions in lieu of cash on all series as permitted by its
First Mortgage Indenture. Except for minor exclusions, all real and personal
property is subject to the liens of the first mortgage indentures.
The Company's First Mortgage Bonds Series due March 1, 2011, and the City
of Becker Pollution Control Revenue Bonds Series due March 1, 2019, and Sept.
1, 2019, have variable interest rates, which currently change at various
periods up to 270 days, based on prevailing rates for certain commercial paper
securities or similar issues. The interest rates applicable to these issues
averaged 5.9 percent, 4.1 percent and 4.1 percent, respectively, at Dec. 31,
1994. The 2011 series bonds are redeemable upon seven days notice at the
option of the bondholder. The Company also is potentially liable for repayment
of the 2019 Series Becker Bonds when the bonds are tendered, which occurs each
time the variable interest rates change. The principal amount of all three
series of these variable rate bonds outstanding represents potential short-
term obligations and, therefore, is reported under current liabilities on the
balance sheet.
Maturities and sinking-fund requirements on long-term debt are: 1995,
$16,106,000; 1996, $18,934,000; 1997, $110,538,000; 1998, $13,541,000; and
1999, $209,888,000.
10. 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.
The funded status of NSP's pension plan as of Dec. 31 is as follows:
(Thousands of dollars) 1994 1993
Actuarial present value of benefit obligation:
Vested $571 254 $655 002
Non-vested 120 420 139 346
Accumulated benefit obligation $691 674 $794 348
Projected benefit obligation $836 957 $974 160
Plan assets at fair value 1 165 584 1 244 650
Plan assets in excess of projected benefit obligation (328 627) (270 490)
Unrecognized prior service cost (21 538) (22 580)
Unrecognized net actuarial gain 370 289 315 049
Unrecognized net transitional asset 691 767
Net pension liability recorded $20 815 $22 746
For regulatory purposes, the Company's pension expense is determined and
recorded under the aggregate-cost method. As required by SFAS No. 87---
Employers' Accounting for Pensions, the difference between the pension costs
recorded for ratemaking purposes and the amounts determined under SFAS No. 87
are recorded as a regulatory liability on the balance sheet. Net annual
periodic pension cost includes the following components:
(Thousands of dollars) 1994 1993 1992
Service cost-benefits earned during the period $27 536 $25 015 $24 080
Interest cost on projected benefit obligation 65 107 71 075 69 853
Actual return on assets (12 668) (152 019) (115 455)
Net amortization and deferral (82 114) 66 299 39 019
Net periodic pension cost determined under SFAS No. 87 (2 139) 10 370 17 497
Additional costs recognized due to actions of regulators 3 922 5 117 2 741
Net periodic pension cost recognized for ratemaking $1 783 $15 487 $20 238
The weighted average discount rate used in determining the actuarial
present value of the projected obligation was 8 percent in 1994 and 7 percent
in 1993. The rate of increase in future compensation levels used in
determining the actuarial present value of the projected obligation was 5
percent in 1994 and 1993. Changes made to assumptions for the 1993 valuation
decreased 1994 pension costs (determined under SFAS No. 87) by approximately
$3 million. Changes made to assumptions for the 1994 valuation are expected
to increase 1995 pension costs (determined under SFAS No. 87) by approximately
$1 million. The assumed long-term rate of return on assets used for cost
determinations under SFAS No. 87 was 8 percent for 1994, 1993 and 1992. Plan
assets principally consist of common stock of public companies and U.S.
government securities.
Postretirement Health Care - NSP has a contributory health and welfare benefit
plan that provides health care and death benefits to substantially all
employees after their retirement. The plan is intended to provide for sharing
the costs of retiree health care between NSP and retirees. For employees
retiring after Jan. 1, 1994, a six-year cost-sharing strategy was implemented
with retirees paying 15 percent of the total cost of health care in 1994,
increasing to a total of 40 percent in 1999.
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 pre-1993 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 considered 1994 plan design changes, including Medicare
integration, increased retiree cost sharing and managed indemnity measures not
in effect in 1993.
Before 1993, NSP funded payments for retiree benefits internally. While
NSP generally prefers to continue using internal funding of benefits paid and
accrued, significant levels of external funding have been required by NSP's
regulators, as discussed below, including the use of tax-advantaged trusts.
Plan assets held in such trusts as of Dec. 31, 1994, consisted of investments
in equity mutual funds and cash equivalents. The funded status of NSP's health
care plan as of Dec. 31 is as follows:
(Millions of dollars) 1994 1993
APBO:
Retirees $132.2 $120.2
Fully eligible plan participants 21.5 18.8
Other active plan participants 79.4 90.8
Total APBO 233.1 229.8
Plan assets at fair value 8.0 6.1
APBO in excess of plan assets 225.1 223.7
Unrecognized net actuarial gain (loss) 2.3 (1.3)
Unrecognized transition obligation (194.0) (204.8)
Net benefit obligation recorded $ 33.4 $ 17.6
The assumed health care cost trend rates used in measuring the APBO at
Dec. 31, 1994 and 1993, respectively, were 11.0 and 14.1 percent for those
under age 65, and 7.5 and 8.0 percent for those over age 65. The assumed cost
trend rates are expected to decrease each year until they reach 5.5 percent
for both age groups in the year 2004, after which they are assumed to remain
constant. A 1-percent increase in the assumed health care cost trend rate for
each year would increase the APBO by approximately 13 percent as of Dec. 31,
1994. Service and interest cost components of the net periodic postretirement
cost would increase by approximately 16 percent with a similar 1-percent
increase in the assumed health care cost trend rate. The assumed discount rate
used in determining the APBO was 8 percent for Dec. 31, 1994, 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 1994 and 1993. While the 1994 assumption
changes had no effect on 1994 benefit costs, the effect of the changes in 1995
is expected to be a cost decrease of approximately $1.3 million. Similarly,
the assumption changes made for the Dec. 31, 1993, calculations had no effect
on 1993 benefit costs, but decreased 1994 costs by approximately $2 million.
In 1992, NSP recognized $12.8 million as the cost attributable to
postretirement health care and death benefits based on payments made. The net
annual periodic postretirement benefit cost recorded for 1994 and 1993
consists of the following components:
(Millions of dollars) 1994 1993
Service cost-benefits earned during the year $5.0 $4.4
Interest cost (on service cost and APBO) 16.1 17.5
Actual return on assets (.2) (.1)
Amortization of transition obligation 10.8 10.8
Net amortization and deferral (.3) .1
Net periodic postretirement health care cost under SFAS No. 106 31.4 32.7
Costs recognized (deferred) due to actions of regulators 4.1 (12.1)
Net periodic postretirement health care cost recognized for
ratemaking $35.5 $20.6
Regulators for NSP's retail and wholesale customers in Minnesota,
Wisconsin and North Dakota have allowed full recovery of increased benefit
costs under SFAS No. 106, effective in 1993. Increased 1993 accrual costs for
Minnesota retail customers are being amortized over the years 1994 through
1996, consistent with approved rate recovery. External funding was required
by Minnesota and Wisconsin retail regulators to the extent it is tax
advantaged; funding began for Wisconsin in 1993 and must begin by the next
general rate filing for Minnesota. For wholesale ratemaking, the FERC has
required external funding for all benefits paid and accrued under SFAS No.
106.
ESOP - NSP has a leveraged Employee Stock Ownership Plan (ESOP) that covers
substantially all employees. Employer contributions to this non-contributory,
defined contribution plan are generally made to the extent NSP realizes a tax
savings on its income statement from dividends paid on certain shares held by
the ESOP. Contributions to the ESOP in 1994, 1993 and 1992, which represent
compensation expense, were $5,695,000, $6,281,000 and $6,415,000,
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 11.)
Leveraged shares held by the ESOP are allocated to participants when dividends
on stock held by the plan are used to repay ESOP loans. Of the 5.4 million
shares of the Company's stock that NSP's ESOP currently holds, an average of
111,845 uncommitted leveraged ESOP shares were excluded from earnings-per-
share calculations in 1994. The fair value of NSP's leveraged ESOP shares
approximated cost at Dec. 31, 1994.
401(k) - NSP has a contributory, defined contribution Retirement Savings Plan
(the Plan), which complies with section 401(k) of the Internal Revenue Code
and covers substantially all employees. Beginning in 1994, NSP matches
specified amounts of employee contributions Plan. NSP's matching
contributions were $2.6 million in 1994.
11. 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 1994 and 1993,
and 34 percent in 1992) to net income before income tax expense. The reasons
for the difference are as follows:
(Thousands of dollars) 1994 1993 1992
Tax computed at statutory U.S. federal tax rate $131 860 $119 868 $84 015
Increases (decreases) in tax from:
State income taxes net of federal income tax benefit 22 053 20 838 13 421
Tax rate differential on foreign income (6 750)
Tax credits recognized (13 049) (9 545) (8 846)
Non-taxable AFC-equity included in book income (1 592) (2 565) (3 058)
Net-of-tax AFC included in book depreciation 4 860 4 403 4 518
Use of the flow-through method for depreciation in prior years 4 651 7 004 5 884
Effect of tax rate changes for plant-related items (5 715) (4 648) (5 202)
Dividends paid on ESOP shares (2 983) (3 009) (3 245)
Other---net (69) (1 606) (1 311)
Total income tax expense from operations $133 266 $130 740 $86 176
Effective income tax rate 35.4% 38.2% 34.9%
Income taxes are comprised of the following expense (benefit) items:
Included in utility operating expenses:
Current federal tax expense $108 652 $92 099 $69 198
Current state tax expense 34 823 25 787 18 535
Deferred federal tax expense (3 450) 15 010 8 518
Deferred state tax expense (1 606) 4 431 2 533
Deferred investment tax credits (9 191) (8 981) (8 115)
Total 129 228 128 346 90 669
Included in other income and expense:
Current federal tax expense 3 959 7 853 1 490
Current state tax expense 923 2 289 613
Current foreign tax expense 219
Current federal tax credits (3 548) (321) (400)
Deferred federal tax expense (835) (6 736) (4 518)
Deferred state tax expense (209) (449) (1 347)
Deferred foreign tax expense 3 839
Deferred investment tax credits (310) (242) (331)
Total 4 038 2 394 (4 493)
Total income tax expense from operations $133 266 $130 740 $86 176
Income before income taxes includes foreign income of $29.7 million in
1994. NSP's management intends to reinvest the earnings of foreign operations
indefinitely. Accordingly, U.S. income taxes and foreign withholding taxes
have not been provided on the earnings of foreign subsidiary companies. The
cumulative amount of undistributed pre-tax earnings of foreign subsidiaries
upon which no U.S. income taxes or foreign withholding taxes have been
provided is approximately $30.8 million at Dec. 31, 1994. The additional U.S.
income tax and foreign withholding tax on the unremitted foreign earnings, if
repatriated, would be offset in whole or in part by foreign tax credits. Thus,
it is impracticable to estimate the amount of tax that might be payable.
The components of NSP's net deferred tax liability at Dec. 31 were:
(Thousands of dollars) 1994 1993
Deferred tax liabilities:
Differences between book and tax bases of property $824 332 $792 542
Regulatory assets 144 605 128 991
Tax benefit transfer leases 76 775 87 924
Other 7 854 7 050
Total deferred tax liabilities $1 053 566 $1 016 507
Deferred tax assets:
Regulatory liabilities $81 280 $95 504
Deferred investment tax credits 65 812 73 648
Deferred compensation, vacation and other
accrued liabilities not currently deductible 50 572 62 811
Other 18 110 11 341
Total deferred tax assets $215 774 $243 304
Net deferred tax liability $837 792 $773 203
12. Regulatory Assets and Liabilities
The following summarizes the individual components of unamortized regulatory
assets and liabilities shown on the Consolidated Balance Sheets at Dec. 31:
Amortization
(Thousands of dollars) Period 1994 1993
AFC recorded in plant on a net-of-tax basis* Plant Lives $155 102 $165 915
Conservation and energy management programs* Up to 10 Years 76 902 46 939
Losses on reacquired debt Term of New Debt 52 514 48 529
Environmental costs Up to 15 Years 47 779 45 568
Deferred postretirement benefit costs 3-15 Years 9 930 15 514
Unrecovered purchased gas costs 1-2 Years 7 601 3 216
State commission accounting adjustments* Plant Lives 5 544 6 246
Other Various 2 204 2 427
Total regulatory assets $357 576 $334 354
Excess deferred income taxes collected from customers $75 277 $113 276
Investment tax credit deferrals 110 831 120 123
Pension costs 11 054 6 969
Unrealized gains from decommissioning investments 1 412
Fuel refunds and other 1 943 3 512
Total regulatory liabilities $200 517 $243 880
* Earns a return on investment in the ratemaking process.
13. Financial Instruments
The estimated Dec. 31 fair values of NSP's recorded financial instruments are
as follows:
1994 1993
Carrying Fair Carrying Fair
(Thousands of dollars) Amount Value Amount Value
Cash, cash equivalents and short-term
investments $41 947 $41 947 $57 838 $57 838
Long-term decommissioning investments $145 467 $145 467 $101 378 $110 130
Long-term debt, including current portion $1 621 060 $1 540 595 $1 524 085 $1 584 435
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. As discussed in Note 3, NSP adopted
in 1994 SFAS No. 115, which required certain debt and equity securities to be
recorded at their market value. NSP began recording decommissioning fund
investments at their market value at that time. 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.
NRG has entered into three forward foreign currency exchange contracts
with a counterparty to hedge exposure to currency fluctuations to the extent
permissible by hedge accounting requirements. Pursuant to these contracts,
transactions have been executed that are designed to protect the economic
value in U.S. dollars of NRG's equity investments, denominated in Australian
dollars and German deutsche marks (DM). NRG's forward foreign currency
exchange contracts, in the notional amount of $93 million, hedge approximately
$94 million of foreign currency denominated investments at Dec. 31, 1994.
These forward foreign currency exchange contracts are not reflected on NSP's
balance sheet. The contracts do require compensating balances of $7 million,
which are reflected as other current assets on NSP's balance sheet. The
contracts terminate in 2004 and require foreign currency interest payments by
either party during each year of the contract. If the contracts had been
terminated at Dec. 31, 1994, $4.3 million would have been payable by NRG for
currency exchange rate changes to date. Management believes NRG's exposure to
credit risk due to non-performance by the counterparty to its forward exchange
contracts is not significant, based on the investment grade rating of the
counterparty.
Cenergy has entered into natural gas futures contracts in the notional
amount of $16.1 million at Dec. 31, 1994. The contract terms range from one
month to three years. The contracts are intended to mitigate risk from
fluctuations in the price of natural gas that will be required to satisfy
sales commitments for future deliveries to customers in excess of Cenergy's
natural gas reserves. Cenergy's futures contracts hedge the sale of $16.6
million of natural gas. These futures contracts are not reflected on NSP's
balance sheet. Margin balances of $3.4 million at Dec. 31, 1994, were
maintained on deposit with brokers and recorded as cash and cash equivalents
on NSP's balance sheet. The counterparties to the futures contracts are the
New York Mercantile Exchange and major gas pipeline operators. Management
believes that the risk of non-performance by these counterparties is not
significant. If the contracts had been terminated at Dec. 31, 1994, $1.7
million would have been payable by Cenergy for natural gas price fluctuations
to date.
NSP has three interest rate swap agreements with notional amounts
totalling $320 million. These swaps were entered into in conjunction with
first mortgage bonds. As summarized below, these agreements effectively
convert the interest costs of these debt issues from fixed to variable rates
based on six-month London Interbank Offered Rates (LIBOR), with the rates
changing semiannually.
Net Effective
Notional Amount Term of Interest Cost
Series (millions of dollars) Swap Agreement at Dec. 31, 1994
5 7/8% Series due Oct. 1, 1997 $100 Maturity 5.69%
5 1/2% Series due Feb. 1, 1999 $200 Maturity 6.68%
7 1/4% Series due March 1, 2023 $ 20 March 1, 1998 7.43%
Market risks associated with these agreements result from short-term
interest rate fluctuations. Credit risk related to non-performance of the
counterparties is not deemed significant, but would result in NSP terminating
the swap transaction and recognizing a gain or loss, depending on the fair
market value of the swap. Such agreements are not reflected on NSP's balance
sheets. The interest rate swaps serve to hedge the interest rate risk
associated with fixed rate debt in a declining interest rate environment. This
hedge is produced by the tendency for changes in the fair market value of the
swap to be offset by changes in the present value of the liability
attributable to the fixed rate debt issued in conjunction with the interest
rate swaps. If the interest rate swaps had been discontinued on Dec. 31, 1994,
the present value of NSP's additional obligation would have been $26 million,
which is offset by a reduction in the present value of the related debt of
$27.5 million below carrying value.
14. Detail of Certain Income and Expense Items
Administrative and general (A&G) expense for utility operations consists of
the following:
(Thousands of dollars) 1994 1993 1992
A&G salaries and wages $49 726 $51 601 $48 608
Postretirement medical and injury
compensation benefits 41 901 14 995 13 776
Other benefits---all utility employees 38 792 51 860 54 410
Information technology, facilities and
administrative support 29 751 30 504 35 139
Insurance and claims 16 771 16 165 18 092
Other 16 877 17 410 17 950
Total $193 818 $182 535 $187 975
Other income and deductions---net consist of the following:
(Thousands of dollars) 1994 1993 1992
Non-regulated operations:
Operating revenues and sales $242 019 $90 654 $62 616
Operating expenses 241 479* 81 403 65 744*
Pretax operating income (loss) 540 9 251 (3 128)
Interest and investment income 10 839 4 522 3 452
Gain on cogeneration contract termination 9 685
Charitable contributions (5 037) (4 752) (4 585)
Environmental and regulatory contingencies (4 568) (100) (1 300)
Other---net (excluding income taxes) (5 460) (939) (2 355)
Income tax related to all non-operating
items---(expense) benefit (4 038) (2 394) 4 493
Total $ 1 961 $ 5 588 $(3 423)
*Includes non-regulated energy project write-downs of $5.0 million in 1994 and
$6.8 million in 1992.
15. 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, 1994 and 1993, was $585,783,000 and $584,822,000,
respectively. The corresponding accumulated provisions for depreciation were
$132,092,000 and $114,251,000.
16. Nuclear Obligations
Fuel Disposal - NSP is responsible for the temporary storage of used nuclear
fuel from the Company's nuclear generating plants. Under a contract with the
Company, the DOE is obligated to assume the responsibility for permanent
storage or disposal of NSP's used nuclear fuel. The Company has been funding
its portion of the DOE's permanent disposal program since 1981. Funding took
place through an internal sinking fund until 1983, when the DOE began
assessing fuel disposal fees under the Nuclear Waste Policy Act of 1982 based
on 0.1 cent per kilowatt-hour sold to customers from nuclear generation. The
cumulative amount of such assessments from the DOE to NSP through Dec. 31,
1994, is $218.5 million. Currently, it is not determinable if the amount and
method of the DOE's assessments to all utilities will be sufficient to fully
fund the DOE's permanent storage or disposal facility.
The DOE has stated in statute and by contract that a storage or permanent
disposal facility would be ready to accept used nuclear fuel by 1998.
Accordingly, NSP has been, with regulatory and legislative approval, providing
its own temporary on-site storage facilities at its Monticello and Prairie
Island plants, with a capacity sufficient for used fuel from the plants until
at least that date. However, indications from the DOE are that a permanent
federal facility will not be ready to accept used fuel from utilities until
approximately 2010. Accordingly, NSP is investigating all of its alternatives
for used fuel storage until the DOE facility is available. When on-site
temporary storage at NSP's nuclear plants reaches approved capacity, the
Company could seek interim storage at a contracted private facility. The
Company received Minnesota legislative approval in 1994 for additional on-site
storage facilities at its Prairie Island plant, provided the Company satisfies
certain responsibilities. Seventeen dry cask containers, each of which can
store approximately one-half year's used fuel, can become available as
follows: five immediately in 1994; four more in 1996 if an application for an
alternative storage site is filed, an effort to locate such a site is made and
100 megawatts (MW) of wind generation is available or contracted for
construction; and the final eight in 1999 unless the specified alternative
site is not operational or under construction, certain resource commitments
are not met, or the Minnesota Legislature revokes its approval. (See
additional discussion of legislative commitments in Note 17.) With the dry
cask storage facilities approved in 1994 for the Prairie Island nuclear
generating plant, the Company believes it has adequate storage capacity to
continue operation of its nuclear plants until at least 2002 and 2003 for
Prairie Island Units 1 and 2, respectively, and 2008 for Monticello. Storage
availability for operation beyond these dates is not assured at this time.
Fuel expense includes DOE fuel disposal assessments of $10.6 million,
$8.7 million and $6.8 million for 1994, 1993 and 1992, respectively. Disposal
expenses reflect reductions of $0.7 million in 1994, $2.6 million in 1993 and
$3.7 million in 1992 due to a change in the DOE's basis of charging customers,
retroactive to 1983. Nuclear fuel expenses in 1994 and 1993 also include about
$5 million and $1 million, respectively, for payments to the DOE for the
decommissioning and decontamination of the DOE's uranium enrichment
facilities. The DOE's initial assessment of $46 million to the Company was
recorded in 1993. This assessment will be payable in annual installments from
1993-2008 and will be expensed on a monthly basis in the 12 months following
each payment. The most recent installment paid in 1994 was $3.9 million;
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 conform to the FERC's cost-of-energy adjustment clause
procedures, the Company also expects recovery of these DOE assessments in
retail ratemaking as payments are made each year.
Plant Decommissioning - Decommissioning of all Company nuclear facilities is
planned for the years 2010-2022, using the prompt dismantlement method. The
Company is following industry practice by ratably accruing the costs for
decommissioning over the approved cost recovery period and including the
accruals in Utility Plant---Accumulated Depreciation, as discussed in Note 1.
The Financial Accounting Standards Board is reviewing the accounting and
reporting guidelines for decommissioning cost accruals. Until such guidelines
require a different presentation, the Company plans to continue reporting
plant decommissioning obligations as accumulated depreciation. Consequently,
the total decommissioning cost obligation and corresponding asset currently
are not recorded in NSP's financial statements. In addition, the Company
cannot predict whether new guidelines, if issued, would increase or decrease
decommissioning expenses or if the income statement presentation of such
expenses would change.
Consistent with cost recovery in utility customer rates, the Company
records annual decommissioning accruals based on periodic site-specific cost
studies and a presumed level of dedicated funding. Cost studies quantify
decommissioning costs in current dollars. Since the costs are expected to be
paid in 2010-2022, funding presumes that current costs will escalate in the
future at a rate of 4.5 percent per year. The total estimated decommissioning
costs that will ultimately be paid, net of income earned by external trust
funds, is currently being accrued using an annuity approach over the approved
plant recovery period. Under this approach, escalated future costs are
discounted to current year dollars using the assumed rate of return on
funding, which is currently 6 percent (net of tax) for external funding and
approximately 8 percent (net of tax) for internal funding.
The total obligation for decommissioning is currently expected to be
funded approximately 82 percent by external funds and 18 percent by internal
funds, as approved by the MPUC. Rate recovery of internal funding began in
1971 through depreciation rates for removal expense, and was changed to a
sinking fund recovery in 1981. Contributions to the external fund started in
1990 and are expected to continue until plant decommissioning begins. Costs
not funded by external trust contributions and related earnings will be funded
through internally generated funds and issuance of Company debt or stock. The
assets held in trusts as of Dec. 31, 1994, primarily consisted of investments
in tax-exempt municipal bonds, common stock of public companies and U.S.
government securities.
The following table summarizes the funded status of the decommissioning
obligation at Dec. 31, 1994:
(Millions of dollars)
Estimated future decommissioning costs (undiscounted) $1 838.1
Effect of discounting future payments 1 053.5
Present value of decommissioning obligation 784.6
External trust fund assets at fair value 145.5
Decommissioning obligation in excess of assets currently
held in external trust $639.1
Decommissioning expenses recognized include the following components:
(Millions of dollars) 1994 1993 1992
Annual decommissioning cost accrual reported
as depreciation expense:
Externally funded $33.2 $28.4 $27.8
Internally funded (including interest costs) 1.1 14.5 11.9
Interest cost on externally funded decommissioning obligation 3.5 3.7 0.6
Earnings from external trust funds-net (3.5) (3.7) (0.6)
Current year decommissioning accruals-net $34.3 $42.9 $39.7
At Dec. 31, 1994, the Company has recorded and recovered in rates
cumulative decommissioning accruals of $340 million; $138 million has been
deposited into external trust funds for such accruals. The Company believes
future decommissioning cost accruals will continue to be recovered in customer
rates. Decommissioning and interest accruals are included with the accumulated
provision for depreciation on the balance sheet. Interest costs and trust
earnings are reported in Other Income and Expense on the income statement.
A revision to NSP's 1993 nuclear decommissioning study and nuclear plant
depreciation capital recovery request was filed with the MPUC and approved in
1994. Although management expects to operate the Prairie Island units through
the end of their licensed lives, the requested capital recovery would allow
for the plant to be fully depreciated, including the accrual and recovery of
decommissioning costs, about six years earlier than the end of its licensed
life. The approved recovery period for Prairie Island has been reduced because
of the uncertainty regarding used fuel storage, discussed previously. The
updated nuclear decommissioning study supports a decrease in annual cost
accruals for decommissioning as well as the shortened recovery period. The
combined impact of the request as approved, including the shorter depreciation
period and lower decommissioning costs, is a net decrease of about $800,000
in annual depreciation and decommissioning expenses. The revised cost levels
approved by the MPUC were recorded in 1994.
17. Commitments and Contingent Liabilities
Legislative Resource Commitments - In 1994, the Minnesota Legislature
established several energy resource and other commitments for NSP to fulfill
to obtain the Prairie Island temporary nuclear fuel storage facility approval,
as discussed in Note 16. The additional resource commitments, which can be
built, purchased or (in the case of biomass generation) converted, can be
summarized as follows:
Power Type Megawatts Deadline
Wind 100* (Additional) 12/31/96
Wind 225 (Cumulative) 12/31/98
Biomass 50 (Additional) 12/31/98
Wind 200 (Additional) 12/31/02
Biomass 75 (Additional) 12/31/02
Wind 400** (Additional) 12/31/02
* In addition to 25 MW of wind generation currently installed.
** If required by least-cost planning and resource planning.
Other commitments include applying for, locating and licensing an
alternative used fuel storage site, a low-income discount for electric
customers, additional required conservation improvement expenditures and
various study and reporting requirements to a newly formed legislative
electric energy task force. NSP has implemented programs to begin meeting
these legislative commitments.
Capital Commitments - NSP estimates utility capital expenditures, including
acquisitions of nuclear fuel, will be $383 million in 1995 and $1.9 billion
for 1995-1999. There also are contractual commitments for the disposal of used
nuclear fuel. (See Note 16.)
NRG is contractually committed to additional equity investments in an
existing German energy project. Such commitments are for approximately DM 36
million in 1995 and DM 35 million in 1996. The 1995 and 1996 commitments would
be approximately $23 million each year, based on exchange rates in effect at
Dec. 31, 1994.
Leases - Rentals under operating leases were approximately $24.0 million, $27.5
million and $25.1 million for 1994, 1993 and 1992, 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 1995 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 minimum purchase of approximately
$600 million of coal, $35 million of nuclear fuel and $377 million of natural
gas, or to make payments in lieu thereof, under these contracts. In addition,
NSP is required to pay additional amounts depending on actual quantities
shipped under these agreements. As a result of FERC Order 636, NSP has been
very active in developing a mix of gas supply contracts designed to meet its
needs for retail gas sales. The contracts are with several suppliers and for
various periods of time. Because NSP has other sources of fuel available, and
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 Purchase 1995-2005 500
Seasonal Participation
Power Purchase 1995-1996 250
Seasonal Peaking Power
Purchase 1995-1996 200
Seasonal Diversity Exchanges:
Summer exchanges from MH 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 500-megawatt participation power purchase commitment is
based on 80 percent of the costs of owning and operating the Company's Sherco
3 generating plant (adjusted to 1993 dollars). The total estimated future
annual capacity costs for all MH agreements range from approximately $66
million to $69 million. Negotiations are under way regarding the
interpretation of specific contractual factors relating to the annual cost of
the 500-megawatt participation agreement. These commitments, which represent
about 21 percent of MH's output capability in 1995, account for approximately
13 percent of the Company's 1995 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 MW 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 first two
phases of construction, which provide the majority of the benefits to NSP,
were completed in 1994. The final phase, which primarily benefits MH, is
expected to be completed in May 1995.
The Company has an agreement with Minnkota Power Cooperative (MPC) for
the purchase of summer season capacity and energy. From 1995 through 2001, the
Company will buy 150 MW of summer season capacity for $12.4 million annually.
From 2002 through 2015, the Company will purchase 100 MW of capacity for $10.0
million annually. Under the agreement, energy 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 Iowa-Illinois Gas and Electric Company for the
purchase of 331 MW in 1995 and 388 MW in 1996, including reserves. The annual
cost of this capacity will be approximately $4 million.
The Company has agreements with several non-regulated power producers to
purchase electric capacity and associated energy. The total annual cost of
current commitments for non-regulated installed capacity is approximately $20
million for 107 MW in 1995 and 119 MW in 1996. This annual cost will increase
to approximately $37 million-$45 million for 1997-2018 and to approximately
$25 million-$29 million for 2019-2027 due to a new power purchase agreement.
Under this agreement, which was approved by the MPUC in February 1995, the
Company will purchase an additional 245 to 262 MW of electric capacity and
associated energy from 1997 through 2027.
Nuclear Insurance - The Company's public liability for claims resulting from any
nuclear incident is limited to $8.9 billion under the 1988 Price-Anderson
amendment to the Atomic Energy Act of 1954. The Company has secured $200
million of coverage for its public liability exposure with a pool of insurance
companies. The remaining $8.7 billion of exposure is funded by the Secondary
Financial Protection Program, available from assessments by the federal
government in case of a nuclear accident. The Company is subject to
assessments of $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
cleanup costs with coverage limits of $2.0 billion for each of the Company's
two nuclear plant sites. The coverage consists of $500 million from American
Nuclear Insurers/Mutual Atomic Energy Liability Underwriters (ANI/MAELU) and
$1.5 billion from Nuclear Electric Insurance Limited (NEIL). As of Jan. 1,
1995, insurance with ANI/MAELU will change to Nuclear Mutual Limited. The
coverage amounts will remain unchanged.
NEIL provides insurance coverage for the cost of replacement power
obtained during certain prolonged accidental outages of nuclear generating
units and coverage for property losses in excess of $500 million occurring at
nuclear stations. Premiums billed to NSP from NEIL are expensed as paid each
year. All companies insured with NEIL are subject to retrospective premium
adjustments if losses exceed accumulated reserve funds. Capital has been
accumulated in the reserve funds of NEIL to the extent that the Company would
have no exposure in case of a single incident under the replacement power
coverage and the property damage coverage. However, in each calendar year, the
Company could be subject to maximum assessments of approximately $4.6 million
(five times the amount of its annual premium) and $26.1 million (7.5 times the
amount of its annual premium) if losses exceed accumulated reserve funds under
the replacement power and property damage coverages, respectively.
Environmental Contingencies - Other long-term liabilities include an accrual of
$49 million at Dec. 31, 1994, for estimated costs associated with
environmental remediation. Approximately $40 million of the liability relates
to a DOE assessment for decommissioning of a federal uranium enrichment
facility, as discussed in Note 16. Other estimates have been recorded for
expected environmental costs associated with manufactured gas plant sites
formerly used by the Company and other waste disposal sites, as discussed
below.
These environmental liabilities do not include accruals recorded (and
collected from customers in rates) for future nuclear fuel disposal costs or
decommissioning costs related to the Company's nuclear generating plants. (See
Note 16 for further discussion.)
NSP has not developed any specific site restoration and exit plans for
its fossil fuel plants, hydroelectric plants or substation sites because the
Company intends to operate at these sites indefinitely. If such plans were
developed in the future, NSP would intend to treat restoration and exit costs
as a removal cost of retirement in utility plant and include them in
depreciation accruals. An estimated removal cost (based on historical
experience) is currently included in depreciation expense.
NSP has met or exceeded state and federal removal and disposal
requirements for polychlorinated biphenyls (PCB) equipment. NSP has removed
nearly all PCB capacitors, transformers and equipment from its distribution
system and power plants. Minimal costs are expected to be incurred for future
removal and disposal of PCB equipment. PCB-contaminated mineral oil is
detoxified and reused or burned for energy recovery at a permitted facility,
with minimal cost to NSP. Other than described below, any potential future
cleanup or remediation costs for past PCB disposal is unknown at this time.
The Environmental Protection Agency (EPA) or state environmental agencies
have designated the Company as a "potentially responsible party" (PRP) for 10
waste disposal sites to which the Company allegedly sent hazardous materials.
Under applicable law, the Company, along with each PRP, could be held jointly
and severally liable for the total remediation costs of all 10 sites, which
are currently estimated at $122 million. If additional remediation is
necessary or unexpected costs are incurred, the amount could be in excess of
$122 million. The Company is not aware of the other parties' inability to pay,
nor does it know if responsibility for any of the sites is disputed by any
party. The Company's share of the costs associated with these 10 sites is
approximately $2.5 million. Of this amount, about $1.4 million has already
been paid in connection with six of the 10 sites for which the Company has
settled with the EPA and other PRPs. For the remaining four sites, neither the
amount of remediation costs nor the final method of their allocation among all
designated PRPs has been determined. However, the Company has recorded an
estimate of approximately $1 million for future costs for all four sites, with
the estimated payment dates not determinable at this time. 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
remediation costs of these sites. It is the Company's practice to vigorously
pursue and, if necessary, litigate with insurers to recover incurred
remediation costs whenever possible. Through litigation, the Company has
recovered 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 potentially may be involved in the cleanup and
remediation at three sites. One site is a solid and hazardous waste landfill
site in Eau Claire, Wis. 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 predict the outcome of this matter at this time. The second site,
in Ashland, Wis., contains creosote/coal tar contamination. The Wisconsin
Company is discussing its potential involvement with the Wisconsin Department
of Natural Resources. Investigations are under way to determine the Wisconsin
Company's responsibility as well as that of predecessor companies contributing
to the contamination. The investigation should also determine the extent and
source of the contamination and potential methods for remediation. An estimate
of cleanup and remediation costs at these two sites and the extent of the
Wisconsin Company's responsibility, if any, for sharing such costs are not
known at this time. The third site is a landfill site in Hudson, Wis. which
is one of the 10 waste disposal sites discussed previously.
The Company also is continuing to investigate 15 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 15 gas
sites under investigation, the Company already has remediated one site and is
actively taking remedial action at four of the sites. In addition, the Company
has been notified that two other sites eventually will require remediation,
and a study will be conducted to determine the cost of cleanup. The Company
has paid $5.3 million to date on these seven active sites. The one remediated
site continues to be monitored. The Company currently estimates its liability
for the other six active sites to be approximately $8.4 million, with payment
expected over the next 11 years. The estimate is based on prior experience and
includes investigation, remediation and litigation costs. The possible range
of the liability for these six sites could be from $8.4 million to
approximately $12 million, depending on the extent of contamination. As for
the other eight inactive sites, no liability has been recorded for remediation
since at this time the sites require only monitoring. 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 these 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. During 1994, the Company's gas utility received approval
for deferred accounting for certain gas remediation costs incurred at four
active sites, with final rate treatment of such costs to be determined in the
next general gas rate case.
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 generating plants. These limits will be phased in beginning in
1995. The majority of the rules implementing this complex legislation have
been finalized. No additional capital expenditures are anticipated to comply
with the sulfur dioxide emission limits of the Clean Air Act. NSP has expended
significant amounts over the years to reduce sulfur dioxide emissions at its
plants. Based on revisions to the sulfur dioxide portion of the program, NSP's
emission allowance allocations for the years 1995-1999 were dramatically
reduced. The Company's capital expenditures include some costs for ensuring
compliance with the Clean Air Act's other emission requirements; other
expenditures may be necessary upon EPA's finalization of remaining rules.
Because NSP is only beginning to implement some provisions of the Clean Air
Act, its overall financial impact is unknown at this time. Capital
expenditures will be required for opacity compliance commencing in 1995 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.
Several of NSP's operating facilities have asbestos-containing material,
which represents a potential health hazard to people who come in contact with
it. Governmental regulations specify the required timing and nature of
disposal of asbestos-containing materials. Under such requirements, asbestos
not readily accessible to the environment need not be removed until the
facilities containing the material are demolished. NSP estimates its future
asbestos removal costs will approximate $43 million. Most of these costs will
not need to be incurred until current operating facilities are demolished and
will be included in the costs of removal for the facilities.
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. In July 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 12 lawsuits have
been filed, including one proposed class action, the litigation following this
incident is in a preliminary stage, pending a report from the National
Transportation Safety Board, and the ultimate costs to the Company are unknown
at this time.
18. Segment Information
Year Ended Dec. 31
(Thousands of dollars) 1994 1993 1992
Utility operating income before income taxes
Electric $399 185 $ 393 758 $ 321 837
Gas 38 361 38 474 24 848
Total operating income before income taxes $437 546 $ 432 232 $ 346 685
Utility depreciation and amortization
Electric $252 322 $ 245 200 $ 225 134
Gas 21 479 19 317 17 780
Total depreciation and amortization $273 801 $ 264 517 $ 242 914
Capital expenditures
Electric utility $303 896 $ 284 239 $ 367 522
Gas utility 60 183 36 312 42 850
Common utility and non-regulated businesses 45 207 41 144 17 443
Total capital expenditures $409 286 $ 361 695 $ 427 815
Identifiable assets
Electric utility $4 634 511 $4 543 286 $4 421 151
Gas utility 556 975 521 595 428 192
Total identifiable assets 5 191 486 5 064 881 4 849 343
Other corporate assets 762 085 522 837 293 118
Total assets $5 953 571 $5 587 718 $5 142 461
19. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended
(Thousands of dollars) March 31, 1994 June 30, 1994 Sept. 30, 1994 Dec. 31, 1994
Utility operating revenues $683 462 $581 963 $612 328 $608 794
Utility operating income 85 795 65 526 88 932 68 065*
Net income 65 794 52 808 76 065 48 808*
Earnings available for common stock 62 737 49 751 72 968 45 655*
Earnings per common share $.94 $.74 $1.09 $.68*
Dividends declared per common share $.645 $.660 $.660 $.660
Stock prices---high $43 7/8 $43 5/8 $43 7/8 $47
---low $40 1/8 $38 3/4 $40 3/8 $41 7/8
Quarter Ended
(Thousands of dollars) March 31, 1993 June 30, 1993 Sept. 30, 1993 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
* Net of expense recognized of $8.7 million ($5.1 million net of tax), or 8
cents per share, to write off the unamortized deferred costs associated with
adopting SFAS No. 112 (See Note 3).
Item 9 - Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
During 1994 there were no disagreements with the Company's independent
public accountants on accounting procedures or accounting and financial
disclosures. As discussed in the Company's Form 8-K filed Dec. 16, 1994, on
Dec. 14, 1994 the Company's Board of Directors approved the appointment of the
accounting firm of Price Waterhouse LLP as independent accountants for the
Registrants beginning in fiscal year 1995, subject to ratification by the
shareholders.
PART III
Item 10. Directors and Executive Officers of the Registrant
(a)
CLASS III -- Nominees for Terms Expiring in 1998
H. Lyman Bretting President and Chief Executive Officer, C.G. Bretting
Age 58 Manufacturing Company, Inc., Ashland, Wisconsin, a
Director Since 1990 manufacturer of napkin and paper towel folding
machines.
Member of Finance Also director of M&I National Bank of Ashland and
and Power Supply Northern States Power Company (Wisconsin),
Committees a wholly-owned subsidiary of the Company.
David A. Christensen President and Chief Executive Officer, Raven
Age 60 Industries, Inc., Sioux Falls, South Dakota, a
Director Since 1976 manufacturer of reinforced plastics, electronic
Member of Corporate equipment and sewn products. Also director of Norwest
Management and Power Bank South Dakota, N.A., Norwest Corporation and Raven
Supply Committees Industries, Inc.
Allen F. Jacobson Retired effective November 1, 1991 as Chairman and
Age 68 Chief Executive Officer, Minnesota Mining and
Director Since 1983 Manufacturing Company (3M). Also director of Abbot
Member of Corporate Laboratories, Deluxe Corporation, Minnesota Mining
Management and and Manufacturing Company, Mobil Corporation,
Power Supply Potlatch Corporation, Prudential Insurance Company
Committees of America, Sara Lee Corporation, Silicon Graphics,
Inc., U.S. West, Inc., and Valmont Industries, Inc.
Margaret R. Preska Distinguished Service Professor, Minnesota State
Age 57 Universities, since February 1, 1992. Prior thereto,
Director Since 1980 President, Mankato State University, Mankato,
Member of Corporate Minnesota, an educational institution. Also director
Management and Power of Norwest Bank Minnesota South Central, N.A.
Supply Committees
CLASS I -- Directors Whose Terms Expire In 1996
W. John Driscoll Retired effective June 30, 1994 as Chairman of the
Age 65 Board, Rock Island Company, St. Paul, Minnesota, a
Director Since 1974 private investment company, in which capacity he had
Member of Audit and served since May 15, 1993. Prior thereto, President.
Corporate Management Also director of Comshare Inc., The John Nuveen
Committees Company, MIP Properties, Inc., The St. Paul Companies,
Inc. and Weyerhaeuser Company.
Dale L. Haakenstad Retired effective December 31, 1989 as President and
Age 67 Chief Executive Officer, Western States Life Insurance
Director Since 1978 Company, Fargo, North Dakota.
Member of Audit and
Power Supply
Committees
James J. Howard Chairman, President and Chief Executive Officer of the
Age 59 Company since December 1, 1994. Prior thereto,
Director Since 1987 Chairman of the Board and Chief Executive Officer of
Ex-officio member the Company since July 1, 1990. Also director of Ecolab
of all Committees Inc., Honeywell Inc., ReliaStar Financial Corp. and
Walgreen Company.
John E. Pearson Retired effective January 31, 1992 as Chairman, The
Age 68 NWNL Companies, Inc. and Northwestern National Life
Director Since 1983 Insurance Company, a wholly-owned subsidiary of The
Member of Corporate NWNL Companies, Inc. in which capacity he had served
Management and since July 1, 1991. Prior thereto, Chairman and Chief
Finance Committees Executive Officer, The NWNL Companies, Inc., and
Northwestern National Life Insurance Company. Also
director of Norwest Corporation.
G. M. Pieschel Chairman of the Board, Farmers and Merchants State
Age 67 Bank, Springfield, Minnesota, a commercial bank, since
Director Since 1978 January 14, 1993. Prior thereto, Chief Executive
Member of Audit and Officer and President of Farmers and Merchants State
Finance Committees Bank.
CLASS II -- Directors Whose Terms Expire in 1997
Richard M. Kovacevich President and Chief Executive Officer, Norwest
Age 51 Corporation, Minneapolis, Minnesota, a holding company
Director Since 1990 for banking institutions, since January 1, 1993. Prior
Member of Finance thereto, President and Chief Operating Officer. Also
Power Supply director of Fingerhut Companies, Inc., Northwestern
Committees National Life Insurance Company, Norwest Corporation
and ReliaStar Financial Corp.
Douglas W. Leatherdale Chairman of the Board, President and Chief Executive
Age 58 Officer, The St. Paul Companies, Inc., a worldwide
Director Since 1991 property and liability insurance organization, since
Member of Audit and May 1, 1990. Also director of The John Nuveen Company
Corporate Management and United HealthCare Corporation.
Committees
A. Patricia Sampson Consultant, Dr. Sanders and Associates, a management
Age 46 and diversity consulting company, since January 1,
Director Since 1985 1995. Prior thereto, Chief Executive Officer, until
Member of Audit and December 31, 1994 and Executive Director, until June
Finance Committees 1, 1993, Greater Minneapolis Area Chapter of the
American Red Cross.
Edwin M. Theisen Retired effective November 30, 1994 as President and
Age 64 Chief Operating Officer of the Company. Also director
Director Since 1990 of Firstar Bank of Minnesota, N.A.
Member of Finance
and Power Supply
Committees
(b) Reference is made to "Executive Officers" as of March 1, 1995, in Part I.
(c) The information called for with respect to the identification of certain
significant employees is not applicableto the registrant.
(d) There are no family relationships between the directors and executive
officers listed above. There are no arrangements nor understandings between
any named officer and any other person pursuant to which such person
was selected as an officer.
(e) Each of the officers named in Part I was elected to serve in the office
indicated until the meeting of the Board of Directors preceding the Annual
Meeting of Shareholders in 1995 and until his or her successor is elected and
qualified.
(f) There are no legal proceedings involving directors, nominees for
directors, or officers.
Compliance with Section 16(a) of the Exchange Act
The Securities Exchange Act of 1934 requires all executive officers and
directors to report any changes in the ownership of common stock of the Company
to the Securities and Exchange Commission, The New York Stock Exchange and the
Company.
Based solely upon a review of these report and written representations that
no additional reports were required to be filed in 1994, the Company believes
that all reports were filed on a timely basis.
Item 11. Executive Compensation
COMPENSATION OF EXECUTIVE OFFICERS
The following table sets forth cash and noncash compensation for each of the
last three fiscal years ended December 31, 1994, for services in all
capacities to the Company and its subsidiaries, to the Chief Executive
Officer, the next four highest compensated executive officers of the Company
who were serving as executives at December 31, 1994, and one former executive
officer who would have been one of the four most highly compensated officers
of the Company during 1994 had he not resigned from the Company before the end
of the year.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
AWARDS PAYOUTS
(a) (b) (c) (d) (e) (f) (g) (h) (i)
NUMBER OF
OTHER RESTRICTED SECURITIES ALL OTHER
ANNUAL STOCK UNDERLYING LTIP COMPEN-
COMPENSATION AWARDS OPTIONS PAYOUTS SATION
NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($)(4) ($)(5) ($)(6) AND SARS(#)($)(7) ($)(8)
JAMES J. HOWARD 1994 511,300 317,800 3,504 240,311 15,150 0 9,056
Chairman, President & 1993 511,300 231,931 0 129,075 12,782 23,925 11,324
Chief Executive Officer 1992 485,000 0 2,934 0 13,541 0 44,052
EDWARD J. MCINTYRE 1994 205,600 102,700 2,465 61,680 5,117 0 6,438
Vice President & Chief 1993 205,600 71,395 7,339 35,595 4,508 7,461 5,081
Financial Officer 1992 199,000 0 5,037 0 4,753 0 27,981
GARY R. JOHNSON 1994 183,600 81,700 9,945 55,080 4,570 0 3,672
Vice President, General 1993 183,600 53,424 1,315 28,380 3,648 4,525 5,831
Counsel and 1992 168,450 0 6,005 0 3,889 0 6,922
Corporate Secretary
LOREN L. TAYLOR(1) 1994 174,583 55,000 1,046 40,942 3,455 0 3,166
President, NSP Electric 1993 171,500 32,347 1,202 18,290 2,737 2,728 5,685
1992 152,750 0 5,361 0 2,669 0 6,609
DOUGLAS D. ANTONY(2) 1994 163,893 75,100 1,025 41,837 2,942 0 4,419
President, NSP Generation 1993 146,300 61,329 6,517 17,210 2,493 2,087 3,490
1992 103,344 0 5,097 0 1,168 0 1,982
EDWIN M. THEISEN(3) 1994 297,367 283,516 10,681 0 8,843 0 7,775
Former President & 1993 324,400 129,452 1,271 65,620 7,240 10,650 6,267
Chief Operating Officer 1992 306,500 0 6,870 0 7,606 0 55,324
(1) Mr. Taylor was elected President, NSP Electric on October 27, 1994 after
having served as a vice president in various areas of the Company since
1989.
(2) Mr. Antony was elected President, NSP Generation effective September 7,
1994 after having served as Vice President - Nuclear Generation since
January 1993. Prior thereto, Mr. Antony was not an executive officer.
(3) Mr. Theisen retired as President & Chief Operating Officer of the Company
on November 30, 1994.
(4) This column consists of awards made to each named executive under the
Company's Executive Incentive Plan. Due to Mr. Theisen's retirement during
1994, he additionally received the cash equivalent of the restricted stock
award for 1994 in accordance with the Company's LTIP, in the amount of
$126,516.
(5) This column consists of reimbursements for taxes on certain personal
benefits received by the named executives.
(6) Amounts shown in this column reflect the market value of the shares of
restricted stock awarded under the LTIP, except with respect to Mr.
Antony's additional award (discussed below) and are based on the closing
price of the Company's common stock on the date that the awards were made.
Restricted shares earned for 1994 under the Company's LTIP were granted on
January 25, 1995 based on the performance period ending September 30, 1994.
As of December 31, 1994, the named executives held the following as a
result of grants under the LTIP: Mr. Howard held 3,097 restricted shares at
a market value of $136,268; Mr. McIntyre held 854 restricted shares at a
market value of $37,576; Mr. Antony held 413 restricted shares at a market
value of $18,172; Mr. Taylor held 454 restricted shares at a market value
of $19,976, Mr. Johnson held 680 restricted shares at a market value of
$29,957 and Mr. Theisen held 0 restricted shares at a market value of $0.
The restricted stock awards vest one year after the date of grant with
respect to fifty (50%) of the shares and two years after such date with
respect to the remaining shares, conditioned upon the continued employment
of the recipient with the Company. Non-preferential dividends are paid on
the restricted shares.
Mr. Antony received an additional 2,200 shares of restricted stock during
1994, which as of December 31, 1994, had a market value of $96,800. These
additional shares vest with respect to 50% of the shares if Mr. Antony has
been continually employed by the Company on October 26, 1996 and with
respect to the remainder of the shares if he has been continually employed
with the Company on October 26, 1998.
The total number of restricted shares awarded during the years 1992, 1993
and 1994 are as follows: 7,191 shares for Mr. Howard, 1,910 shares for Mr.
McIntyre, 2,594 shares for Mr. Antony, 982 shares for Mr. Taylor, 1,473
shares for Mr. Johnson and 3,671 for Mr. Theisen.
(7) The Company had no LTIP payouts in 1994 due to the replacement, by the
Corporate Management Committee of the Company's Board of Directors, of
dividend equivalent stock appreciation rights (DESARs) formerly awarded
under the Company's LTIP, in favor of increased stock options and
restricted stock levels.
(8) This column consists of the following: $4,031 was contributed by the
Company for the Employee Stock Ownership Plan (ESOP) for Messrs. Howard and
Theisen, respectively, $3,807 for Mr. McIntyre, $2,297 for Messrs. Johnson
and Taylor, respectively, and $2,642 for Mr. Antony; (The Company
contribution on behalf of all ESOP participants, including the named
executive officers, was equal to 1.3% of their covered compensation.); the
value to each named executive of the remainder of insurance premiums paid
under the Officer Survivor Benefit Plan by the Company: $2,320 for Mr.
Howard, $227 for Mr. McIntyre, $476 for Mr. Johnson, $0 for Mr. Taylor,
$837 for Mr. Antony and $1,418 for Mr. Theisen; imputed income as a result
of life insurance paid by the Company on behalf of each named executive:
$2,205 for Mr. Howard, $341 for Mr. McIntyre, $399 for Mr. Johnson, $369
for Mr. Taylor, $440 for Mr. Antony and $1,826 for Mr. Theisen; Company
matching 401(k) plan contribution of $500 to each named executive; and,
earnings accrued under the Company Deferred Compensation Plan to the extent
such earnings exceeded the market rate of interest (as prescribed pursuant
to the SEC rules), which was $1,563 for Mr. McIntyre and $0 for all other
named executives.
OPTIONS AND STOCK APPRECIATION RIGHTS (SARs)
The following table indicates for each of the named executives (i) the
extent to which the Company used stock options and SARs for executive
compensation purposes in 1994 and (ii) the potential value of such options
and SARs as determined pursuant to the SEC rules.
OPTIONS AND SARS GRANTED IN 1994
POTENTIAL REALIZABLE VALUE
AT ASSUMED ANNUAL RATES
OF STOCK PRICE APPRECIATION
INDIVIDUAL GRANTS FOR OPTION TERM
(a) (b) (c) (d) (e) (f) (g)
% OF TOTAL
OPTIONS AND
OPTIONS/ SARS EXERCISE
SARS GRANTED TO OR BASE
GRANTED(1) EMPLOYEES PRICE EXPIRATION
NAME (#) IN 1994 ($/SH) DATE 5%($)(3) 10%($)(3)
J. Howard 15,150 options 4.9% 42.187 1-26-04 401,952 1,018,626
E. McIntyre 5,117 options 1.7% 42.187 1-26-04 135,762 344,047
G. Johnson 4,570 options 1.5% 42.187 1-26-04 121,249 307,269
L. Taylor 3,455 options 1.1% 42.187 1-26-04 91,666 232,300
D. Antony 2,942 options 1.0% 42.187 1-26-04 78,056 197,808
E. Theisen 8,843 options 2.9% 42.187 1-26-04 234,618 594,568
All
Shareholders(2) N/A N/A N/A N/A 1,774,775,230 4,497,470,638
(1) Options were granted on January 26, 1994 and vested on January 26, 1995. No
SARs were awarded for 1994.
(2) Potential realizable values during the ten year period commencing January
26, 1994, are based on the market price ($42.187) and the outstanding
shares (66,893,377) of common stock of the Company on that date.
(3) The hypothetical potential appreciation shown in columns (f) and (g) for
the named executives is required by the SEC rules. The amounts in these
columns do not represent either the historical or anticipated future
performance of the Company's common stock level of appreciation.
The following table indicates for each of the named executives the number
and value of exercisable and unexercisable options and SARs as of December 31,
1994.
AGGREGATED OPTION AND SAR EXERCISES IN 1994
AND FY-END OPTION/SAR VALUE
(a) (b) (c) (d) (e)
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED IN-THE-MONEY
SHARES OPTIONS AND SARS AT 12/31/94 OPTIONS AND SARS AT
ACQUIRED ON REALIZED (#) -- EXERCISABLE (EX)/ 12/31/94 ($) -- EXERCISABLE (EX)/
NAME EXERCISE(#) VALUE($) UNEXERCISABLE (UNEX) UNEXERCISABLE (UNEX)*
J. Howard N/A N/A 52,423 (ex) 291,519 (ex)
15,150 (unex) 27,459 (unex)
E. McIntyre N/A N/A 17,401 (ex) 94,769 (ex)
5,117 (unex) 9,274 (unex)
G. Johnson N/A N/A 10,559 (ex) 36,588 (ex)
4,570 (unex) 8,281 (unex)
L. Taylor N/A N/A 7,673 (ex) 26,687 (ex)
3,455 (unex) 6,262 (unex)
D. Antony N/A N/A 5,938 (ex) 26,196 (ex)
2,942 (unex) 5,332 (unex)
E. Theisen 66 3,005 25,529 (ex) 139,385 (ex)
8,843 (unex) 16,023 (unex)
* Share price on December 30, 1994 was $44. Company common stock was not traded
on December 31, 1994.
PENSION PLAN TABLE
The following table illustrates the approximate retirement benefits payable
to employees retiring at the normal retirement age of 65 years:
ESTIMATED ANNUAL BENEFITS FOR YEARS OF SERVICE INDICATED
AVERAGE
COMPENSATION YEARS OF SERVICE
(4 YEARS) 5 10 15 20 25 30
$ 50,000 $ 3,500 $ 7,000 $ 10,500 $ 14,500 $ 18,000 $ 21,500
100,000 7,500 15,500 23,000 30,500 38,500 46,000
150,000 11,500 23,500 35,000 47,000 58,500 70,500
200,000 16,000 31,500 47,500 63,500 79,000 95,000
250,000 20,000 40,000 59,500 79,500 99,500 119,500
300,000 24,000 48,000 72,000 96,000 120,000 144,000
350,000 28,000 56,000 84,000 112,500 140,500 168,500
400,000 32,000 64,500 96,500 128,500 161,000 193,000
450,000 36,000 72,500 108,500 145,000 181,000 217,500
500,000 40,500 80,500 121,000 161,500 201,500 242,000
550,000 44,500 89,000 133,000 177,500 222,000 266,500
600,000 48,500 97,000 145,500 194,000 242,500 291,000
650,000 52,500 105,000 157,500 210,500 263,000 315,500
700,000 56,500 113,500 170,000 226,500 283,500 340,000
750,000 60,500 121,500 182,000 243,000 303,500 364,500
800,000 65,000 129,500 194,500 259,500 324,000 389,000
850,000 69,000 138,000 206,500 275,500 344,500 413,500
900,000 73,000 146,000 219,000 292,000 365,000 438,000
950,000 77,000 154,000 231,000 308,500 385,500 462,500
After an employee has reached 30 years of service, no additional years are
used in determining pension benefits. The annual compensation used to
calculate the average compensation shown in this table is based on the
participant's base salary for the year (as shown on the Summary
Compensation Table at column (c)) and bonus compensation paid in that same
year (as shown on the Summary Compensation Table at column (d); see figure
for prior year). The benefit amounts shown are amounts computed in the form
of a straight-life annuity. The amounts are not subject to offset for
social security or otherwise, except as provided in the employment
agreement with Mr. Howard, as described below.
At the end of 1994, each of the executive officers named in the Summary
Compensation Table had the following credited service: Mr. Howard, 7.92
years, Mr. Antony, 25.5 years, Mr. Johnson, 16.08 years, Mr. McIntyre,
21.83 years, Mr. Taylor, 21.58 years and Mr. Theisen, 30 years.
An employment agreement with Mr. Howard provides that if employment
terminates prior to age 60, he will receive payments from the Company
equivalent to benefits he would have earned under the Pension Plan without
regard to service and compensation limitations in a minimum annual amount
of $22,535. If employment continues past age 60, he and his spouse, if she
survives him, will receive combined benefits from the Pension Plan and
supplemental Company payments as though he had completed 30 years of
service, less the pension benefits earned from a former employer.
SEVERANCE PLAN
The Company's Severance Plan covers the full-time regular-benefit,
nonbargaining employees of the Company, including the named executives, and
participating subsidiaries. The Severance Plan provides severance benefits to
covered employees whose termination of employment is involuntary and unrelated
to unsatisfactory performance. Subject to a maximum of 24 months of pay, a
covered employee is eligible to receive monthly payments of two months of base
pay plus the greater of two weeks of base pay for each year of service or one
week of base pay for each $2,000 of base annual salary. Covered employees are
also eligible to receive incentive pay, group insurance benefits and service
and compensation credit under the Pension Plan for the period they receive
monthly severance benefits. Outplacement services are also provided under the
Plan.
DIRECTOR COMPENSATION
Directors not employed by the Company receive a $20,000 annual retainer, or
a pro rata portion thereof if service is less than 12 months, and $1,200 for
attendance at each Board meeting and $1,000 for each Committee meeting
attended. A $2,500 annual retainer is paid to each elected Committee
Chairperson. Employees of the Company receive no separate compensation for
services as a director. In addition, directors have a deferred compensation
and retirement plan in which they can participate. The deferred compensation
plan provides for deferral of the director fees until after retirement from
the Board of Directors. The retirement plan continues payment of the
director's retainer, at the rate in effect for the calendar quarter
immediately preceding the director's retirement multiplied by 1.2. Benefits
continue for a period equal to the number of calendar quarters served on the
Board, up to 40 calendar quarters.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Security Ownership of Directors, Nominees and Named Executive Officers
Set forth in the following table is the beneficial ownership of common stock
of the Company as of March 15, 1995 for all directors and each of the named
executive officers of the Company as defined in the rules of the Securities
and Exchange Commission. As of March 15, 1995, the directors and executive
officers as a group beneficially owned 85,286 shares, less than 0.14 percent,
of the Company's common stock (including shares allocated to the accounts of
executive officers in the Executive Long-Term Incentive Award Stock Plan
(LTIP) and the Employee Stock Ownership Plan for which they have voting power
but not investment power).
H. Lyman Bretting 1,355
David A. Christensen 500
W. John Driscoll 2,000
Dale L. Haakenstad 682
James J. Howard* 25,875
Allen F. Jacobson 712
Richard M. Kovacevich 1,000
Douglas W. Leatherdale 300
John E. Pearson 1,353
G. M. Pieschel 683
Margaret R. Preska 600
A. Patricia Sampson 372
Douglas D. Antony* 6,721
Gary R. Johnson* 5,773
Edward J. McIntyre* 8,430
Loren L. Taylor* 4,893
Edwin M. Theisen* 13,098
*Shares shown for Messrs. Howard, McIntyre, Johnson, Taylor, Antony and
Theisen do not include options to purchase common stock of the Company which
are exercisable within 60 days under the Company's LTIP: 65,577 option shares
for Mr. Howard, 21,881 option shares for Mr. McIntyre, 14,676 option shares
for Mr. Johnson, 10,787 option shares for Mr. Taylor, 8,666 option shares for
Mr. Antony and 34,372 option shares for Mr. Theisen.
Item 13. Certain Relationships and Related Transactions
Edwin M. Theisen, a director and former employee of the Company, is currently
performing certain consulting services for the Company pursuant to a one-year
agreement whereby he receives $15,000 per month in return for such services.
PART IV
Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Financial Statements Page
Included in Part II of this report:
Independent Auditors' Report. 44
Consolidated Statements of Income
for the three years ended
December 31, 1994. 45
Consolidated Statements of Cash Flows
for the three years ended
December 31, 1994. 46
Consolidated Balance Sheets,
December 31, 1994 and 1993. 47
Consolidated Statements of Changes
in Common Stockholders' Equity
for the three years ended
December 31, 1994 48
Consolidated Statements of
Capitalization, December 31,
1994 and 1993. 49
Notes to Financial Statements. 51
(a) 2. Financial Statement Schedules
Schedules are omitted because of the absence of the conditions under
which they are required or because the information required is
included in the financial statements or the notes.
(a) 3. Exhibits
* Indicates incorporation by reference
3.01* Restated Articles of Incorporation 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* Oct. 1, 1994 (Exhibit 4.01 to Form 8-K dated October 5,
1994, File No. 1-3034).
4.46* 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:
4.47* Mar. 1, 1949 (Exhibit 7.02 to File No. 2-7825).
4.48* Jun. 1, 1957 (Exhibit 2.13 to File No. 2-13463).
4.49* Aug. 1, 1964 (Exhibit 4.20 to File No. 2-23726).
4.50* Dec. 1, 1969 (Exhibit 2.03E to File No. 2-36693).
4.51* Sep. 1, 1973 (Exhibit 2.01F to File No. 2-48805).
4.52* Feb. 1, 1982 (Exhibit 4.01G to File No. 2-76146).
4.53* Mar. 1, 1982 (Exhibit 4.39 to Form 10-K for the year 1982,
File No. 10-3140).
4.54* Jun. 1, 1986 (Exhibit 4.01I to File No. 33-6269).
4.55* Mar. 1, 1988 (Exhibit 4.01J to File No. 33-20415).
4.56* 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)
4.57* Apr. 1, 1991 (Exhibit 4.01L to File No. 33-39831).
4.58* Mar. 1, 1993 (Exhibit 4.01 to Form 8-K dated March 4,
1993, File No. 10-3140).
4.59* Oct. 1, 1993 (Exhibit 4.01 to Form 8-K dated September 21,
1993, File No. 10-3140).
4.60 NSP Employee Stock Ownership Plan.
10.01 Mid-continent Area Power Pool (MAPP) Agreement, dated
March 31, 1972, with amendments in 1994, between the
local power suppliers in the North Central States area.
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 10.01 to Form 10-Q for the Quarter Ended
September 30, 1994, 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
10.02 to Form 10-Q for the Quarter Ended September 30,
1994, 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 10.03 to Form 10-Q for the
Quarter Ended September 30, 1994, 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. (Exhibit 10.09 to Form 10-K for
the Year 1993, File No. 1-3034).
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.
10.13* NSP Deferred Compensation Plan amended effective January
1, 1993. (Exhibit 10.16 to Form 10-K for the Year 1993,
File No. 1-3034).
10.14* Annual Executive Incentive Plan for 1994 (Exhibit 10.01 to
Form 10-Q for the Quarter Ended March 31, 1994, File No.
1-3034).
12.01 Statement of Computation of Ratio of Earnings to Fixed
Charges.
16.01* Independent Auditors' Letter re: Change in Certifying
Accountant (Exhibit 16.01 to Form 8-K dated December 13,
1994, File No. 1-3034).
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.
27.01 Financial Data Schedule
(b) Reports on Form 8-K. The following reports on Form 8-K were filed
either during the three months ended December 31, 1994, or between
December 31, 1994 and the date of this report:
October 4, 1994 (Filed October 4, 1994) - Item 5. Other Events. Re:
Disclosure of an agreement by a joint venture between one of the Company's
non-regulated subsidiaries and Cogentrix, Inc., had agreed to terminate a
contract for power sales from a cogeneration project in Michigan. Disclosure
negotiations by the Company and the Minnesota Pollution Control Agency (MPCA)
of a Stipulation Agreement to address monitoring procedures used at the
Company's Prairie Island Generating Plant between January and September of
1992 that allegedly did not comply with National Pollution Discharge System
permits, limiting the halogen content of water discharges at the Plant.
October 5, 1994 (Filed October 7, 1994) - Item 5. Other Events. Re:
Disclosure of Underwriting Agreement and filing of a prospectus supplement
relating to $150,000,000 First Mortgage Bonds, Series due October 1, 2001.
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 October 1, 2001 and the computation of ratio
of earnings to fixed charges.
December 13, 1994 (Filed December 16, 1994) - Item 4. Change in
Registrant's Certifying Accountant. Re: Disclosure of the Company's change
in independent accountants for 1995. Deloitte & Touche LLP was informed that
the firm would no longer be engaged as independent accountants for the
Registrant and its subsidiaries after the completion of audit work for the
fiscal year ended December 31, 1994. The Company's Board of Directors
approved the appointment of the accounting firm of Price Waterhouse LLP as
independent accountants for the Registrant for 1995, subject to ratification
by the shareholders. Item 7. - Financial Statements and Exhibits. Exhibit
No. 16 - Letter from Deloitte & Touche LLP.
January 30, 1995 (Filed February 2, 1995) - Item 5. Other Events.
Disclosure of the Company receiving a notice of violation from the United
States Nuclear Regulatory Commission (NRC), regarding the inspection of the
quality assurance programs at the Company and PX Engineering Company, Inc.,
a subcontractor responsible for the fabrication and assembly of certain
components for the TN-40 spent fuel storage containers which will be used at
the Prairie Island Nuclear Generating Plant. Disclosure of the Mescalero
Apache Tribe vote against participation in a joint Mescalero-Utility Spent
Nuclear Fuel Storage Initiative.
February 28, 1995 (Filed March 2, 1995) - Item 5. Other Events.
Disclosure of a basic agreement between San Joaquin Valley Energy Partners
(SJVEP) and Pacific Gas & Electric Company (PG&E) regarding the acquisition
of existing Standard Offer 4 (SO4) contracts by PG&E from SJVEP. The parties
entered into a bridging agreement to cover the period until all approvals are
received for the transaction. NRG Energy, Inc., a wholly owned subsidiary of
the Company, has a 45 percent interest in SJVEP, through wholly owned
subsidiaries.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this annual report to be
signed on its behalf by the undersigned, thereunto duly authorized.
NORTHERN STATES POWER COMPANY
March 24, 1995 (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
(Douglas W Leatherdale) (John E Pearson)
Douglas W Leatherdale John E Pearson
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 Director
EXHIBIT INDEX
Method of Exhibit
Filing No. Description
DT 4.60 NSP Employee Stock Ownership Plan
DT 10.01 Mid-continent Area Power Pool
Agreement
DT 10.12 NSP Severance 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 Auditor's Consent
DT 27.01 Financial Data Schedule